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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, 2002.
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from ________ to ________.
Commission file numbers: 1-14323
333-93239-01
ENTERPRISE PRODUCTS PARTNERS L.P.
ENTERPRISE PRODUCTS OPERATING L.P.
(Exact name of registrants as specified in their charters)
DELAWARE 76-0568219
DELAWARE 76-0568220
(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. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).
Yes [X] No [ ]
The aggregate market value of the Common Units of Enterprise Products Partners
L.P. ("EPD") held by non-affiliates at June 28, 2002, based on the closing price
of such equity securities in the daily composite list for transactions on the
New York Stock Exchange on June 28, 2002, was approximately $292.2 million. This
figure assumes that Duncan Family 1998 Trust, Duncan Family 2000 Trust, EPOLP
1999 Grantor Trust, Shell US Gas & Power LLC, and the directors and executive
officers of Enterprise Products GP, LLC (the "General Partner") are affiliates
of EPD.
There were 156,357,266 Common Units, 32,114,804 Subordinated Units and
10,000,000 Special Units of EPD outstanding at March 1, 2003. No common equity
securities of Enterprise Products Operating L.P. are held by non-affiliates.
Enterprise Products Operating L.P. is owned 98.9899% by its parent, EPD, and
1.0101% by the General Partner.
EXPLANATORY NOTE
This report constitutes a combined report for Enterprise Products Partners L.P.
(the "Company")(Commission File No. 1-14323) and its 98.9899% owned subsidiary,
Enterprise Products Operating L.P. (the "Operating Partnership")(Commission File
No. 333-93239-01). Since the Operating Partnership owns substantially all of the
Company's consolidated assets and conducts substantially all of the Company's
business and operations, the information within this annual report on Form 10-K
constitutes combined information for the Company and the Operating Partnership
except for the following:
o Part I, Item 4
o Part II, Items 5, 6 and 8
o Part III, Item 12 (to the extent this section addresses
Unitholder matters)
o Sarbanes-Oxley Section 302 Certifications
ENTERPRISE PRODUCTS PARTNERS L.P.
ENTERPRISE PRODUCTS OPERATING L.P.
TABLE OF CONTENTS
Page No.
--------
PART I
Glossary
Items 1 and 2. Business and Properties. 1
Item 3. Legal Proceedings. 30
Item 4. Submission of Matters to a Vote of Security Holders. 30
PART II
Item 5. Market for Registrants' Common Equity and Related Unitholder Matters. 31
Item 6. Selected Financial Data. 31
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operation. 33
Item 7A. Quantitative and Qualitative Disclosures about Market Risk. 55
Item 8. Financial Statements and Supplementary Data. 58
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure. 59
PART III
Item 10. Directors and Executive Officers of our Registrants. 59
Item 11. Executive Compensation. 63
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Unitholder Matters. 66
Item 13. Certain Relationships and Related Transactions. 68
Item 14. Controls and Procedures. 72
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. 73
Financial Statements F-1
Signatures Page S-1
Sarbanes-Oxley Section 302 Certifications C-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
Accum. OCI Accumulated Other Comprehensive Income
Asset platform For a discussion of our "asset platform" please read "Business and
Properties--General" beginning on page 1 of this annual report.
Basell Basell polyolefins and affiliates
Baytank Odjfell Terminals (Houston) LP
BBtus 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 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
Burlington Burlington Resources Inc. and affiliates
CEO Chief Executive Officer
CFO Chief Financial Officer
ChevronPhillips ChevronPhillips Chemical Company L.P. and affiliates
ChevronTexaco ChevronTexaco Corp., its subsidiaries and affiliates
CMAI Chemical Market Associates, Inc.
Cogeneration Cogeneration is the simultaneous production of electricity and heat using a
single fuel such as natural gas.
Company Enterprise Products Partners L.P. and its consolidated subsidiaries, including
the Operating Partnership
ConocoPhillips ConocoPhillips Petroleum Company and affiliates
CornerStone CornerStone Propane Partners, L.P. and affiliates
CPG Cents per gallon
Deepwater Deepwater refers to oil and gas production areas located at depths of 1,000 feet
or more such as those found in the Gulf of Mexico.
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
Duke Duke Energy Corporation and its affiliates
El Paso El Paso Corporation, its subsidiaries and affiliates
E-Oaktree E-Oaktree, LLC, a subsidiary of the Company of whom 98% of its membership
interests were acquired by us from affiliates of Williams in July 2002
EPA Environmental Protection Agency
EPCO Enterprise Products Company, an affiliate of the Company and our ultimate parent
company (including its 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 and Millennium Chemicals, Inc.
Evangeline Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively, an
equity investment of EPOLP
FASB Financial Accounting Standards Board
GLOSSARY (CONTINUED)
Feedstock A raw material required for an industrial process such as in petrochemical manufacturing
FERC Federal Energy Regulatory Commission
Forward sales contracts The sale of a commodity or other product in a current period for delivery in a future period.
Fractionation For a discussion of our Fractionation segment, please read "The Company's Operations--Fractionation"
beginning on page 14 of this annual report.
FTC U.S. Federal Trade Commission
GAAP Generally Accepted Accounting Principles in the United States of America
General Partner Enterprise Products GP, LLC, the General Partner of the Company and the Operating Partnership
HSC Denotes our Houston Ship Channel pipeline system
ICA Interstate Commerce Act
Isomerization For a discussion of the isomerization process, please read "The Company's Operations --
Fractionation -- Isomerization" beginning on page 17 of this annual report.
IPO Refers to our initial public offering in July 1998
Kinder Morgan Kinder Morgan Operating LP "A"
La Porte La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively, an equity investment of EPOLP
LIBOR London interbank offered rate
Mapletree Mapletree, LLC, a subsidiary of the Company of whom 98% of its membership interests were acquired by
us from affiliates of Williams in July 2002
MBA Mont Belvieu Associates, see "MBA acquisition" below
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
Mid-America Mid-America Pipeline Company, LLC
Midstream Energy Assets The intermediate segments of the energy industry downstream of oil and gas production and upstream of
end user consumption. These segments provide services to producers and consumers of energy. These
services generally include but are not limited to natural gas gathering, processing and wholesale
marketing and NGL fractionation, transportation and storage.
MMcf/d Million cubic feet per day
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
Mont Belvieu Mont Belvieu, Texas
Moody's Moody's Investors Service
MTBE Methyl tertiary butyl ether
Natural gas processing For a discussion of our natural gas processing business, please read "The Company's
Operations -- Processing" beginning on page 20 of this annual report.
Nemo Nemo Gathering Company, LLC, an equity investment of EPOLP
Neptune Neptune Pipeline Company LLC, an equity investment of EPOLP
NGL or NGLs Natural gas liquid(s)
NGL marketing activities For a discussion of our NGL marketing activities, please read "The Company's Operations--Processing"
beginning on page 20 of this annual report.
NYSE New York Stock Exchange
Ocean Breeze Ocean Breeze Pipeline Company, LLC, an equity investment of EPOLP (merged into Neptune during fourth
quarter of 2001)
OPIS Oil Price Information Service
Operating Partnership Enterprise Products Operating L.P. and its subsidiaries
GLOSSARY (CONTINUED)
OTC Olefins Terminal Corporation, an equity investment of the Company
Petrochemical marketing For a discussion of our petrochemical marketing activities, please read "The
Company's Operations--Fractionation--Propylene
fractionation" beginning on page 18 of this annual report.
Promix K/D/S Promix LLC, an equity investment of EPOLP
SEC U.S. Securities and Exchange Commission
Seminole Seminole Pipeline Company
SFAS Statement of Financial Accounting Standards issued by the FASB
Shell Shell Oil Company, its subsidiaries and affiliates
Splitter III Refers to the propylene fractionation facility we acquired from Diamond-Koch
Spot market Refers to a market where buyers and sellers consummate routine transactions
where performance by both parties is short-term in nature and prices are based
on market conditions at the time the transaction is executed. For a
discussion of "spot market" transactions, please read "The Company's
Operations--Fractionation--Propylene
fractionation" beginning on page 18 of this annual report.
S&P Standard & Poor's Rating Services
Starfish Starfish Pipeline Company LLC, an equity investment of EPOLP
Straddle plants A natural gas processing facility situated on a pipeline that is the sole inlet
and outlet for the processing facility
Throughput Refers to the physical movement of volumes through a pipeline
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 The Williams Companies, Inc. and subsidiaries
Wilprise Wilprise Pipeline Company, LLC, an equity investment of EPOLP
1998 Trust Duncan Family 1998 Trust (formerly Enterprise Products 1998 Unit Option Plan Trust),
an affiliate of EPCO
1999 Trust EPOLP 1999 Grantor Trust, a subsidiary of EPOLP
2000 Trust Duncan Family 2000 Trust (formerly Enterprise Products 2000 Rabbi Trust), an affiliate of EPCO
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
GENERAL
We are a publicly traded limited partnership (NYSE symbol, "EPD") that
was formed in April 1998 to acquire, own, and operate all of the NGL processing
and distribution assets of Enterprise Products Company, or EPCO. We conduct all
of our business through our 98.9899% owned subsidiary, Enterprise Products
Operating L.P., our "Operating Partnership" and its subsidiaries and joint
ventures. Our general partner, Enterprise Products GP, LLC, owns a 1.0% interest
in us and a 1.0101% interest in our Operating Partnership. We do not have any
employees. All of our management, administrative and operating functions are
performed by employees of EPCO, our ultimate parent company, pursuant to the
EPCO Agreement. For a discussion of the EPCO Agreement, please read Item 13 of
this annual report. Unless the context requires otherwise, references to "we,"
"us," "our" or the "Company" are intended to mean the consolidated business and
operations of Enterprise Products Partners L.P., which includes Enterprise
Products Operating L.P. and its subsidiaries. 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 midstream energy company that provides
a wide range of services to producers and consumers of natural gas and natural
gas liquids, or NGLs. NGLs are used by the petrochemical and refining industries
to produce plastics, motor gasoline and other industrial and consumer products
and also are used as residential and industrial fuels. Our asset platform
comprises the only integrated natural gas and NGL transportation, fractionation,
processing, storage and import/export network in North America. We provide
integrated services to our customers and generate fee-based cash flow from
multiple sources along our natural gas and NGL "value chain." We have provided
definitions in the Glossary for some of the industry terms, names of companies
and other abbreviations used in this document. With respect to the industry
terms, we have provided the location in the document where you will find a more
complete explanation of each industry term. Our services include the:
o gathering and transmission of raw natural gas from both onshore and
offshore Gulf of Mexico developments;
o processing of raw natural gas into a marketable product that meets
industry quality specifications by removing mixed NGLs and
impurities;
o purchase of natural gas for resale to our industrial, utility and
municipal customers;
o transportation of mixed NGLs to fractionation facilities by
pipeline;
o fractionation (or separation) of mixed NGLs produced as by-products
of crude oil refining and natural gas production into component NGL
products: ethane, propane, isobutane, normal butane and natural
gasoline;
o transportation of NGL products to end-users by pipeline, railcar and
truck;
o import and export of NGL products and petrochemical products through
our dock facilities;
o fractionation of refinery-sourced propane/propylene mix into high
purity propylene, propane and mixed butane;
o transportation of high purity propylene to end-users by pipeline;
o storage of natural gas, mixed NGLs, NGL products and petrochemical
products;
o conversion of normal butane to isobutane through the process of
isomerization;
o production of high-octane additives for motor gasoline from
isobutane; and
o sale of NGL and petrochemical products we produce and/or purchase
for resale.
For a complete description of our natural gas processing activities,
please refer to the business segment discussion titled "Processing" on page 20.
For information regarding our fractionation and isomerization activities, please
see the section titled "Fractionation" on page 14. In May 2002, we completed a
two-for-one split of each class of our partnership Units. All references to
number of Units or earnings per Unit contained in this annual report reflect the
Unit split, unless otherwise indicated.
1
BUSINESS STRATEGY
Our business strategy is to:
o 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 and the Rocky Mountain
region;
o develop and invest in joint venture projects with strategic partners
that will provide the raw materials for these projects or purchase
the projects' end products;
o expand our asset base through accretive acquisitions of
complementary midstream energy assets; and
o increase our fee-based cash flows by investing in pipelines and
other fee-based businesses.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND RISK FACTORS
This annual report contains various forward-looking statements and
information that are based on our beliefs and those of our general partner, as
well as assumptions made by us and information currently available to us. When
used in this document, words such as "anticipate," "project," "expect," "plan,"
"goal," "forecast," "intend," "could," "believe," "may" and similar expressions
and statements regarding our plans and objectives for future operations, are
intended to identify forward-looking statements. Although we and our general
partner believe that such expectations reflected in such forward-looking
statements are reasonable, neither we nor our general partner can give any
assurances 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 anticipated,
estimated, projected or expected. You should not put undue reliance on any
forward-looking statements. When considering forward-looking statements, please
review our "Risk Factors" below.
RISK FACTORS
Among the key risk factors that may have a direct impact on our results
of operations and financial condition are:
We have significant leverage that may restrict our future financial and
operating flexibility.
Our leverage is significant in relation to our partners' capital. At
December 31, 2002, our total outstanding debt, which represented approximately
63.9% of our total capitalization, was approximately $2.2 billion. These amounts
are before the application of approximately $258.9 million in net proceeds
before offering expenses from our January 2003 equity offering, For a
description of our debt obligations, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Our liquidity and
capital resources - Our debt obligations" under Item 7 of this annual report.
For a discussion of subsequent events affecting our financial statements, please
see our footnote titled "Subsequent Events" in the Notes to Consolidated
Financial Statements under Item 8 of this annual report.
Debt service obligations, restrictive covenants and maturities
resulting from this leverage may adversely affect our ability to finance future
operations, pursue acquisitions and fund other capital needs, and may make our
results of operations more susceptible to adverse economic or operating
conditions. Our ability to repay, extend or refinance our existing debt
obligations and to obtain future credit will depend primarily on our operating
performance, which will be affected by general economic, financial, competitive,
legislative, regulatory, business and other factors, many of which are beyond
our control. Our ability to access the capital markets for future offerings may
be limited by adverse market conditions resulting from, among other things,
general economic conditions, contingencies and uncertainties that are difficult
to predict and beyond our control.
If we are unable to access the capital markets for future offerings, we
might be forced to seek extensions for some of our short-term maturities or to
refinance some of our debt obligations through bank credit, as opposed to
long-term public debt securities or equity securities. The price and terms upon
which we might receive such extensions or additional bank credit could be more
onerous than those contained in our existing debt agreements. Any such
arrangements could, in turn, increase the risk that our leverage may adversely
affect our future financial and operating flexibility.
2
A decrease in the difference between NGL product prices and natural
gas prices results in lower margins on volumes processed, which would
adversely affect our profitability.
The profitability of our operations depends upon the spread between NGL
product prices and natural gas prices. NGL product prices and natural gas prices
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:
o the level of domestic production;
o the availability of imported oil and gas;
o actions taken by foreign oil and gas producing nations;
o the availability of transportation systems with adequate capacity;
o the availability of competitive fuels;
o fluctuating and seasonal demand for oil, gas and NGLs; and
o conservation and the extent of governmental regulation of production
and the overall economic environment.
Our Processing segment is directly exposed to commodity price risks, as
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 in response to changes in supply, market uncertainty and a variety
of additional factors that are beyond our control. These pricing risks cannot be
completely hedged or eliminated, and any attempt to hedge pricing risks may
expose us to financial losses.
A reduction in demand for our products by the petrochemical, refining
or heating industries could adversely affect our results of operations.
A reduction in demand for our products by the petrochemical, refining
or heating industries, whether because of general economic conditions, reduced
demand by consumers for the end products made with NGL products, increased
competition from petroleum-based products due to pricing differences, adverse
weather conditions, government regulations affecting prices and production
levels of natural gas or the content of motor gasoline or other reasons, could
adversely affect our results of operations. For example:
Ethane. If natural gas prices increase significantly in relation to
ethane prices, it may be more profitable for natural gas processors to leave the
ethane in the natural gas stream to be burned as fuel than to extract the ethane
from the mixed NGL stream for sale.
Propane. The demand for propane as a heating fuel is significantly
affected by weather conditions. Unusually warm winters will cause the demand for
propane to decline significantly and could cause a decline in the volumes of
propane that we extract and transport.
Isobutane. Any reduction in demand for motor gasoline in general or
MTBE in particular may similarly reduce demand for isobutane. During periods in
which the difference in market prices between isobutane and normal butane is low
or inventory values are high relative to current prices for normal butane or
isobutane, our operating margin from selling isobutane will be reduced.
MTBE. A number of states have either banned or currently are
considering legislation to ban MTBE. In addition, Congress is contemplating a
federal ban on MTBE, and several oil companies have taken an early initiative to
phase out the production of MTBE. If MTBE is banned or if its use is
significantly limited, the revenues and equity earnings we record related to its
production may be materially reduced or eliminated. For additional information
regarding MTBE, please read "Regulation and Environmental Matters--Impact of the
Clean Air Act's oxygenated fuels programs on our BEF investment" on page 28 of
this annual report.
Propylene. Any downturn in the domestic or international economy could
cause reduced demand for propylene, which could cause a reduction in the volumes
of propylene that we fractionate and expose our investment in inventories of
3
propane/propylene mix to pricing risk due to requirements for short-term price
discounts in the spot or short-term propylene markets.
Please read "The Company's Operations" beginning on page 6 of this
annual report for a more detailed discussion of our operations.
A decline in the volume of NGLs delivered to our facilities could
adversely affect our results of operations.
Our profitability is materially impacted by the volume of NGLs
processed at our facilities. 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 the volume of
NGLs delivered to our facilities for processing, thereby reducing revenue and
operating income.
Our business requires extensive credit risk management that may not be
adequate to protect against customer nonpayment.
As a result of business failures, revelations of material
misrepresentations and related financial restatements by several large,
well-known companies in various industries over the last year, there have been
significant disruptions and extreme volatility in the financial markets and
credit markets. Because of the credit intensive nature of the energy industry
and troubling disclosures by some large, diversified energy companies, the
energy industry has been especially impacted by these developments, with the
rating agencies downgrading a number of large energy-related companies.
Accordingly, in this environment we are exposed to an increased level of credit
and performance risk with respect to our customers. If we fail to adequately
assess the creditworthiness of existing or future customers, unanticipated
deterioration in their creditworthiness could have an adverse impact on us.
Acquisitions and expansions may affect our business by substantially
increasing the level of our indebtedness and contingent liabilities and
increasing our risks of being unable to effectively integrate these new
operations.
From time to time, we evaluate and acquire assets and businesses that
we believe complement our existing operations. We may encounter difficulties
integrating these acquisitions with our existing businesses without a loss of
employees or customers, a loss of revenues, an increase in operating or other
costs or other difficulties. In addition, we may not be able to realize the
operating efficiencies, competitive advantages, cost savings or other benefits
expected from these acquisitions. Future acquisitions may require substantial
capital or the incurrence of substantial indebtedness. As a result, our
capitalization and results of operations may change significantly following an
acquisition, and you will not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider in determining
the application of these funds and other resources.
Our tax treatment depends on our status as a partnership for federal
income tax purposes, as well as our not being subject to entity-level
taxation by states. If the IRS treats us as a corporation or we become
subject to entity-level taxation for state tax purposes, it would
substantially reduce distributions to our Unitholders and our ability
to make payments on our debt securities.
The after-tax economic benefit of an investment in the common units
depends largely on our being treated as a partnership for federal income tax
purposes. If we were classified as a corporation for federal income tax
purposes, we would pay federal income tax on our income at the corporate rate.
Some or all of the distributions made to Unitholders would be treated as
dividend income, and no income, gains, losses or deductions would flow through
to Unitholders. Treatment of us as a corporation would cause a material
reduction in the anticipated cash flow and after-tax return to the Unitholders,
likely causing a substantial reduction in the value of the common units.
Moreover, treatment of us as a corporation would materially and adversely affect
our ability to make payments on our debt securities.
In addition, because of widespread state budget deficits, several
states are evaluating ways to subject partnerships to entity-level taxation
through the imposition of state income, franchise or other forms of taxation. If
any state were to impose a tax upon us as an entity, the cash available for
distribution to you would be reduced. The partnership agreement provides that,
if a law is enacted or existing law is modified or interpreted in a manner that
4
subjects us to taxation as a corporation or otherwise subjects us to
entity-level taxation for federal, state or local income tax purposes, then the
minimum quarterly distribution and the target distribution levels will be
decreased to reflect that impact on us.
Terrorist attacks aimed at our facilities could adversely affect our
business.
Since the September 11, 2001 terrorist attacks on the United States,
the United States government has issued warnings that energy assets, including
our nation's pipeline infrastructure, may be the future target of terrorist
organizations. Any terrorist attack on our facilities, those of our customers
and, in some cases, those of other pipelines, could have a material adverse
effect on our business. An escalation of political tensions in the Middle East
and elsewhere, such as the recent commencement of United States military action
in Iraq, could result in increased volatility in the world's energy markets and
result in a material adverse effect on our business.
RECENT STRATEGIC ACQUISITIONS
The following is a brief summary of our strategic acquisitions since
the end of 2001. Additional information regarding these acquisitions is
contained in the rest of this annual report.
Acquisition of Mid-America and Seminole Pipeline Systems. On July 31,
2002, we completed the acquisition of an effective 98% interest in the
Mid-America Pipeline System and an effective 78.4% interest in the Seminole
Pipeline System from Williams for approximately $1.2 billion in cash. The
Mid-America Pipeline System is a 7,226-mile NGL pipeline system connecting the
Hobbs hub on the Texas-New Mexico border with supply regions in the Rocky
Mountains and supply regions and markets in the Midwest. The Seminole Pipeline
System is a 1,281-mile pipeline system that interconnects with the Mid-America
pipeline system and transports mixed NGLs and NGL products from the Hobbs hub
and Permian Basin to Mont Belvieu, Texas.
Acquisition of Propylene Fractionation Business ("Splitter III"). In
February 2002, we completed the purchase of various propylene fractionation
assets and certain inventories of propylene and propane from Diamond-Koch for
approximately $239 million in cash. The primary asset acquired was a 66.7%
interest in a polymer grade propylene fractionation facility located in Mont
Belvieu, Texas having 41 MBPD of capacity.
Acquisition of Storage Business. In January 2002, we completed the
purchase of various NGL and petrochemical storage assets from Diamond-Koch for
approximately $130 million in cash. These storage facilities consist of 25
operational salt dome storage caverns located in Mont Belvieu, Texas with a
practical capacity of 64 million barrels, local distribution pipelines and
related equipment.
For additional information regarding these and other acquisitions
completed during 2002, please see our footnote titled "Business Acquisitions" in
the Notes to Consolidated Financial Statements under Item 8 of this annual
report.
5
THE COMPANY'S OPERATIONS
We have five reportable business segments: Pipelines, Fractionation,
Processing, Octane Enhancement and Other. Pipelines consists of NGL,
petrochemical and natural gas pipeline systems, storage, and import/export
services. Fractionation primarily includes NGL and propylene fractionation and
isomerization services. Processing includes our natural gas processing business
and related NGL marketing activities. Octane Enhancement includes facilities
that produce motor gasoline additives to enhance octane (currently producing
MTBE). The Other segment consists of fee-based marketing services and various
operational support activities.
For additional information regarding our business segments including
revenues, gross operating margin and assets, see the Notes to Consolidated
Financial Statements under Item 8 of this report.
PIPELINES
Our Pipelines segment owns or has interests in approximately 14,000
miles of NGL, petrochemical and natural gas transportation and distribution
pipelines. This segment also includes our storage and import/export terminalling
businesses.
NGL and petrochemical pipelines
Our NGL and petrochemical pipelines transport mixed NGLs and other
hydrocarbons to our fractionation plants, distribute and collect NGL products
and propylene to and from petrochemical plants and refineries and deliver
propane to customers along the Dixie pipeline and certain sections of the
Mid-America Pipeline System. Our pipelines provide transportation services to
customers on a fee basis. Therefore, the results of operations for this business
are generally dependent upon the volume of product transported and the level of
fees charged to customers (which includes our NGL and petrochemical marketing
activities). Typically, our NGL and petrochemical pipelines do not take title to
the products they transport; rather the shipper retains title and the associated
commodity price risk.
In the markets we serve, we compete with a number of intrastate and
interstate liquids pipeline companies (including those affiliated with major
oil, petrochemical and gas companies) and barge, rail and truck fleet operators.
In general, our NGL and petrochemical pipelines compete with these entities in
terms of transportation rates and service. We believe that our pipeline systems
offer significant flexibility in rendering transportation services for our
customers due to the large number of receipt and delivery points that we can
offer to them.
Taken as a whole, this business area has not exhibited a significant
degree of seasonality. However, propane transportation volumes are generally
higher in the October through March timeframe due to increased use of propane
for heating in the upper Midwest and southeastern United States. Conversely,
mixed NGL transportation volumes are generally lower during the winter months as
traditionally higher natural gas prices negatively affect NGL extraction
economics at natural gas processing plants connected to the pipelines. In
addition, volumes on the Lou-Tex NGL pipeline are generally higher during the
April through September period due to gasoline blending activities at refineries
in anticipation of the summer driving season.
6
The following table summarizes our NGL and petrochemical pipeline
transportation and distribution networks:
LENGTH OUR
IN OWNERSHIP
NGL AND PETROCHEMICAL PIPELINES MILES INTEREST
- -------------------------------------------------------------------------------
Mid-America Pipeline System 7,226 98.0%
Dixie 1,301 19.9%
Seminole Pipeline System 1,281 78.4%
Louisiana Pipeline System 536 100.0%
Promix (1) 410 33.3%
Lou-Tex Propylene 291 100.0%
Lou-Tex NGL 206 100.0%
HSC 175 100.0%
Tri-States 169 33.3%
Chunchula 117 100.0%
Lake Charles/Bayport 87 50.0%
Belle Rose 48 41.7%
Wilprise 30 37.4%
Sabine Propylene 21 100.0%
La Porte (2) 17 50.0%
-------------
Total NGL and petrochemical pipelines 11,915
=============
- -------------------------------------------------------------------------------
(1) The Promix NGL pipelines are an integral component of the NGL fractionation
activities of Promix, the assets and equity earnings of which are accounted for
as part of our Fractionation segment.
(2) The La Porte pipeline is an integral component of the propylene
fractionation activities of Splitter III, which is accounted for under our
Fractionation segment. Our investment in and equity earnings from La Porte are
reported under the Fractionation segment.
Mid-America Pipeline System. In July 2002, we acquired an effective 98%
interest in the Mid-America Pipeline System (or "Mid-America") from Williams for
approximately $934.8 million in cash. Mid-America is a regulated 7,226-mile NGL
pipeline system consisting of three NGL pipelines: the 2,548-mile Rocky Mountain
pipeline, the 2,740-mile Conway North pipeline, and the 1,938-mile Conway South
pipeline. The Mid-America Pipeline System crosses thirteen states: Wyoming,
Utah, Colorado, New Mexico, Texas, Oklahoma, Kansas, Missouri, Nebraska, Iowa,
Illinois, Minnesota and Wisconsin. We also acquired fifteen unregulated propane
terminals that are part of this system.
The Rocky Mountain system transports mixed NGLs from the Rocky Mountain
Overthrust and San Juan Basin areas to the Hobbs hub located on the Texas-New
Mexico border. The Conway North segment links the large NGL hub at Conway,
Kansas to refineries and propane markets in the upper Midwest. In addition, the
Conway North segment has access to, through third-party pipeline connections,
NGL supplies from Canada's Western Sedimentary basin. The Conway South system
connects the Conway hub with Kansas refineries and transports mixed NGLs from
Conway, Kansas to the Hobbs hub (with interconnections to the Seminole Pipeline
System at the Hobbs hub). Williams operated this pipeline under a transition
services agreement through January 31, 2003, at which time we took over
operation of this system.
Approximately 60% of the volumes transported on the Mid-America system
are mixed NGLs sourced from natural gas processing plants located in the Permian
Basin in West Texas, the Hugoton Basin of southwestern Kansas, the San Juan
Basin of northwest New Mexico, and the Green River Basin of southwestern
Wyoming. The remaining volumes are generally purity NGL products originating
from NGL fractionators in the mid-continent areas of Kansas, Oklahoma, and
Texas, as well as deliveries from Canada. For additional information regarding
7
the consideration paid to acquire Mid-America, see our "Business Acquisitions"
footnote in the Notes to Consolidated Financials under Item 8 of this annual
report.
Dixie. The Dixie pipeline is a regulated 1,301-mile propane pipeline
extending from Mont Belvieu, Texas and Louisiana to markets in the southeastern
United States. Propane supplies transported on this system primarily originate
from southeast Texas, southern Louisiana and Mississippi. We currently estimate
that Dixie transports approximately 50% of the propane requirements in the
markets it serves. We own a 19.9% interest in Dixie. An affiliate of
ConocoPhillips operates the system.
Seminole Pipeline System. In July 2002, we acquired an effective 78.4%
interest in the Seminole Pipeline System (or "Seminole") from Williams for
approximately $248.2 million in cash. Seminole is a regulated 1,281-mile
pipeline system that transports mixed NGLs and NGL products from the Hobbs hub
on the Texas-New Mexico border and the Permian Basin area to Mont Belvieu,
Texas. The Seminole pipeline is interconnected with the Mid-America Pipeline
System at the Hobbs hub. The primary source of throughput for Seminole is the
volume originating from the Mid-America system. In general, the volumes
transported by Seminole are ultimately used by petrochemical plants that
manufacture various products in southeast Texas. Williams operated this pipeline
under a transition services agreement through January 31, 2003, at which time we
took over operation of this system. For additional information regarding the
consideration paid to acquire Seminole, see our "Business Acquisitions" footnote
in the Notes to Consolidated Financials under Item 8 of this annual report.
Louisiana Pipeline System. The Louisiana pipeline system is a 536-mile
network of nine NGL pipelines located in Louisiana. This system transports mixed
NGLs and NGL products originating in southern Louisiana and Texas 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 natural gas processing plants, NGL
fractionators and other facilities located in Louisiana. We own 100% of 428
miles of this system with the remaining 108 miles belonging to joint ventures in
which we have an ownership interest. We operate all but 43 miles of these
pipelines.
Promix. The Promix pipeline system is a 410-mile NGL gathering pipeline
that gathers mixed NGLs from 12 natural gas processing plants in Louisiana for
delivery to the Promix NGL fractionator. This system is an integral part of the
Promix NGL fractionation facility, of which we own 33.3%.
Lou-Tex Propylene Pipeline System. The Lou-Tex propylene pipeline
system consists of a 291-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 Pipeline System. 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 Pipeline System. 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.
These pipelines are used to deliver NGL 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 indirectly own interests in
three pipelines that supply mixed NGLs to the BRF and Promix NGL fractionators.
We own a 33.3% interest in Tri-States, which owns a l69-mile NGL pipeline that
extends from Mobile Bay, Alabama to near Kenner, Louisiana. In addition, we own
a 41.7% interest in and operate Belle Rose, which owns a 48-mile NGL pipeline
that extends from the interconnect with Tri-States near Kenner, Louisiana to the
Promix NGL fractionator. We own a 37.4% interest in Wilprise, which owns a
30-mile NGL pipeline that extends from the interconnect with Tri-States near
Kenner, Louisiana to Sorrento, Louisiana. The mixed NGLs transported on these
systems originate from gas processing facilities located along the Mississippi,
8
Alabama and Louisiana Gulf Coast. BP operates the Tri-States system. Williams
operated the Wilprise system through January 31, 2003, at which time we assumed
the role of operator of this system.
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.
Lake Charles/Bayport. Our Lake Charles/Bayport pipeline system is
comprised of two pipelines: a 77-mile system used (in combination with a
pipeline owned and operated by ExxonMobil) to distribute polymer grade propylene
from Mont Belvieu, Texas to polypropylene plants in Lake Charles, Louisiana and
Bayport, Texas; and approximately 10 miles of related polymer grade propylene
pipelines located in the La Porte, Texas area. We have a 50% ownership interest
in and operate the 77-mile section of this system. We have varying ownership
interests in the remaining 10 miles of this overall system.
Sabine Propylene. The Sabine Propylene pipeline system is a 21-mile
pipeline used to transport polymer grade propylene from third-party plant
facilities in Port Arthur, Texas to a connection with our Lake Charles pipeline.
We own and operate this system.
La Porte. The La Porte pipeline system is a 17-mile pipeline used to
distribute polymer grade propylene from Mont Belvieu, Texas to La Porte, Texas.
This system is an integral part of our Splitter III operations. We own an
aggregate 50% of the La Porte pipeline and operate the system.
NGL and petrochemical pipeline utilization
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,
the utilization rates of our principal NGL and petrochemical pipelines are
measured in terms of throughput (in MBPD, on a net basis).
FOR YEAR ENDED DECEMBER 31,
--------------------------------------------
NGL AND PETROCHEMICAL PIPELINES 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------
Mid-America Pipeline System (1) 641 n/a n/a
Dixie 21 26 14
Seminole Pipeline System (1) 202 n/a n/a
Louisiana Pipeline System 179 138 115
Lou-Tex Propylene 25 27 23
Lou-Tex NGL 38 29 30
HSC 135 133 106
Tri-States, Wilprise and Belle Rose 44 36 42
Lake Charles/Bayport 11 6 5
Sabine Propylene (2) 11 n/a n/a
Chunchula 5 5 6
--------------------------------------------
Total net volume of NGL and petrochemical pipelines 1,312 400 341
============================================
- -------------------------------------------------------------------------------
(1) In July 2002, we acquired ownership interests in these systems from
Williams. The throughput rates shown in the table above reflect operating data
for the five months that we owned these systems during 2002. During 2001,
average transportation volumes for the Mid-America and Seminole systems were 641
MBPD and 241 MBPD, respectively (both amounts on a gross basis). We own an
effective 98% of the Mid-America system and 78.4% of the Seminole system.
(2) Our Sabine Propylene pipeline commenced operations during the first quarter
of 2002.
9
Natural gas pipelines
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 gas to
customers such as electric utility companies, local natural gas distribution
companies and industrial customers. Acadian Gas is 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; rather 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.
Our Gulf of Mexico offshore pipelines compete with other offshore systems
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 Louisiana pipelines have historically experienced slightly
higher throughput rates during the winter and summer months. During the winter,
natural gas consumption by residential and industrial users for heating is
greater due to the decline in temperatures. During the summer, natural gas
consumption by gas-fired electrical generation facilities is greater due to an
increase in air conditioning demand. Our offshore natural gas pipelines exhibit
little to no effects of seasonality; however, these systems may be affected by
weather events such as hurricanes and tropical storms in the Gulf of Mexico.
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 to which they are connected, then throughput
volumes on these pipelines will decline, thereby affecting our earnings from
these assets. We actively seek to offset the loss of volumes due to natural
depletion by adding connections to new customers and fields.
The following table summarizes our natural gas pipeline assets and
ownership interests:
LENGTH OUR
IN OWNERSHIP
NATURAL GAS PIPELINES MILES INTEREST
- -------------------------------------------------------------------------------
Cypress 577 100.0%
Acadian 438 100.0%
Stingray 379 50.0%
VESCO (1) 260 13.1%
Manta Ray 235 25.7%
Nautilus 101 25.7%
Evangeline 27 49.5%
Nemo 24 33.9%
----------
Total natural gas pipelines 2,041
==========
- -------------------------------------------------------------------------------
(1) The VESCO gas gathering pipelines are an integral part of the natural gas
processing activities of VESCO. Accordingly, these pipelines are accounted for
under our cost-method investment in VESCO, which is part of our Processing
segment.
10
Acadian, Cypress and Evangeline. In April 2001, we acquired Shell's
Acadian Gas natural gas pipeline business. This business 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 with approximately 3 Bcf of
natural gas storage capacity. 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.
The Acadian Gas 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 pipeline companies and
a bi-directional interconnect with the U.S. natural gas marketplace at the Henry
Hub. In general, the natural gas transported by the Acadian Gas systems
originate from onshore Louisiana sources and offshore Gulf of Mexico production
areas.
Stingray. In January 2001, we purchased a 50.0% indirect 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 50.0%
equity investment in Starfish, a joint venture with Shell. The Stingray system
is a 379-mile, 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.
Currently, natural gas transported by Stingray originates from the Garden Banks
and East and West Cameron production areas of the Gulf of Mexico. Stingray's
natural gas dehydration facility is connected to the onshore terminus of the
system in south Louisiana. Shell is the operator of these systems and owns the
remaining equity interest in Starfish.
Manta Ray, Nautilus and Nemo. In connection with our purchase of the
Stingray interest, we also acquired from El Paso a 25.7% indirect 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 equipment and the Nautilus system
comprises approximately 101 miles of regulated pipelines. Our ownership of the
Manta Ray and Nautilus systems is through our unconsolidated affiliate, Neptune.
We also purchased from El Paso a 33.9% indirect 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 and Marathon the operator for Nautilus. Shell and Marathon
are our co-owners in Neptune and Shell owns the remaining interest in Nemo.
Currently, the primary source of natural gas throughput for the
Nautilus system is production from the Manta Ray system through its
interconnection in the Ship Shoal 207 area in the Gulf of Mexico offshore
Louisiana. The primary sources of throughput for the Manta Ray system are the
Green Canyon, Ship Shoal, South Timbalier, Grand Isle and Ewing Bank areas of
the Gulf of Mexico offshore Louisiana. BP, Shell and others have announced plans
to build the Cleopatra pipeline that will transport natural gas from the
Southern Green Canyon area of the Gulf of Mexico to Manta Ray. This pipeline is
expected to be completed by the end of 2003. Presently, the only source of
volumes for Nemo is Shell's Green Canyon development in the Brutus field.
Natural gas pipeline utilization
The maximum amount of natural gas that these systems can transport per
day depends upon the operating balance achieved at a given time between various
segments of each 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 a system cannot be practically determined. In light of the
complex, interconnected nature of the pipeline networks and the varying diameter
of pipe used and pressure employed, the utilization rates of our principal
natural gas pipeline systems are measured in BBtus per day of natural gas
transported. As shown in the following table, the utilization rates of our
principal natural gas pipelines are measured in terms of throughput (in BBtus
per day, on a net basis).
11
FOR YEAR ENDED
DECEMBER 31,
------------------------------
NATURAL GAS PIPELINES 2002 2001
- -------------------------------------------------------------------------------------------------
Acadian Gas and Evangeline 704 783
Stingray 267 300
Manta Ray, Nautilus and Nemo 236 266
------------------------------
Total net volume of natural gas pipelines 1,207 1,349
==============================
NGL and Petrochemical Storage
Our NGL and petrochemical storage facilities are integral parts of our
pipeline operations. In general, our underground storage wells are used to store
mixed NGLs, NGL products and petrochemical products for customers and ourselves.
The profitability of our storage operations is primarily dependent upon the
volume of material stored and the level of fees charged.
Our principal storage operations are primarily determined by the
operational requirements of our customers in the petrochemical industry. We
usually experience an increase in the demand for storage services during the
spring and summer months due to increased feedstock storage requirements for
motor gasoline production and a decrease during the fall and winter months when
propane inventories are being drawn down for heating needs.
The following table summarizes our practical (or useable) storage
capacity and net storage capacity by state (net storage capacity is based on our
level of ownership in the assets):
OWNERSHIP
PRACTICAL OF PRACTICAL
CAPACITY, CAPACITY,
NGL AND PETROCHEMICAL STORAGE ASSETS MMBBLS MMBBLS
- -------------------------------------------------------------------------------------------------
Texas 94.1 93.8
Louisiana 32.5 14.3
Mississippi 12.0 9.5
Iowa 0.5 0.5
Nebraska 0.3 0.3
Oklahoma 0.1 0.1
------------------------------
Total NGL and petrochemical storage capacity 139.5 118.5
==============================
Our primary storage facilities are located at Mont Belvieu, Texas. We
own and operate 90.5 MMBbls of practical storage capacity at Mont Belvieu, of
which 64 MMBbls of this capacity was acquired from Diamond-Koch in January 2002
for approximately $130 million. We also own storage facilities located at Breaux
Bridge, Napoleonville, Sorrento and Venice, Louisiana having a practical
capacity of 32.5 MMBbls. Our Mississippi storage assets are comprised of
facilities located at or near Petal and Hattiesburg having a practical capacity
of 12 MMBbls. Of the facilities located in Louisiana and Mississippi, we operate
those located in Breaux Bridge and Napoleonville, Louisiana and Petal,
Mississippi. Affiliates of Dynegy and Shell operate the remaining facilities. In
connection with our purchase of the Mid-America and Seminole pipeline systems in
July 2002, we acquired 20 underground NGL and petrochemical storage wells
located in four states. The Mid-America and Seminole storage facilities have a
practical storage capacity of 4.5 MMBbls.
Our storage wells allow us to optimize throughput on our pipeline
systems and maintain operational efficiency. When used in conjunction with our
processing plant operations, storage wells allow us to mix various batches of
feedstock and maintain both 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 fees when they cannot take immediate delivery of products.
Segment revenues include fees charged to our NGL and petrochemical marketing
activities for their use of the storage facilities. These intersegment revenues
and expenses are eliminated in consolidation.
12
We also store products for customers in our wells for a fee. The amount
of storage capacity available for this type of storage activity varies daily
depending on our processing requirements. Our competitors in this area are other
storage and pipeline companies such as TEPPCO and Dynegy. Major oil and gas
companies such as Exxon Mobil and ConocoPhillips occasionally use their
proprietary storage assets in this role, thereby entering into competition with
us and other providers. We compete with other service providers primarily in
terms of the fees charged, pipeline connections and dependability. We believe
that the integrated nature of our processing, pipeline and import/export
operations provide our storage customers access to a competitively priced,
flexible and dependable network of assets.
Import and Export Facilities
Houston Ship Channel 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 the amount of time that a tanker is idle 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. Import volumes are usually at
their highest rates from April through September of each year due to lower
international demand and pricing for NGLs relative to domestic levels in those
months. Typically, our import cargoes originate from North Africa and North Sea
production areas.
In addition, we own an NGL export facility located at the same terminal
as our import facility. Our export facility includes an NGL products chiller and
related equipment used for loading refrigerated marine tankers for third-party
exporters. Our export facility can load vessels with refrigerated propane and
butane at rates up to 5,000 barrels per hour. In general, export cargoes shipped
from this facility are destined for Mexico, Central and South America, Europe
and the Far East (Japan, Korea and China). Export volumes are predominately
higher during the winter months due to increased propane exports. Prior to March
2003, we owned 50.0% of this export facility through our equity investment in
EPIK. On March 1, 2003, we acquired the remaining 50.0% ownership interests in
this facility for $19 million plus certain post-closing working capital
adjustments.
Dynegy and Dow own facilities that are the primary competitors of our
NGL import facility. Our primary competitors in the NGL export services market
are Dynegy and ChevronTexaco. Both the import and export operations compete with
third-party operations primarily in terms of service, such as 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. The profitability of import and export
activities primarily depends upon the quantities loaded and offloaded and the
fees we charge associated with each activity.
OTC. In February 2002, we acquired a 50.0% interest in OTC, which owns
an above ground polymer grade propylene storage and export facility located in
Seabrook, Texas. The facility is operated by Baytank with administrative
services provided by JLM Industries. We acquired our interest in OTC in
connection with our purchase of the Splitter III propylene fractionation
facility from Diamond-Koch. This facility can load vessels of polymer grade
propylene at rates up to 5,000 barrels per hour. OTC's primary competitor is an
export operation owned by ChevronPhillips located on the Houston Ship Channel.
OTC's operations are an integral part of our Splitter III propylene
fractionation business, of which the assets and earnings (including those of
OTC) are accounted for as part of our Fractionation segment.
13
Due to the timing and logistics of ship and barge loading and
offloading activities, we measure utilization in terms of volumes loaded and
offloaded through our import/export facilities. The following table shows the
volume for each facility over the last three years (in MBPD, on a net basis):
FOR YEAR ENDED DECEMBER 31,
----------------------------------
2002 2001 2000
----------------------------------
NGL import facility 22 45 9
NGL export facility 19 8 17
OTC (1) 4 n/a n/a
----------------------------------
Total net imports and exports 45 53 26
==================================
- -------------------------------------------------------------------------------
(1) The OTC propylene export facility is an integral part of our Splitter III
propylene fractionation operations. Accordingly, this facility is accounted for
under Splitter III, which is part of our Fractionation segment.
FRACTIONATION
NGL Fractionation
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
production, one of the basic building blocks for a wide range of plastics and
other chemical products. Propane is used both as a petrochemical feedstock in
the production of ethylene and propylene and as a heating, engine and industrial
fuel. Isobutane is fractionated from mixed butane (a mixed stream of normal
butane and isobutane) or produced 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, 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 (1) domestic gas processing plants, (2) domestic crude oil refineries
and (3) imports of butane and propane mixtures. When produced at the wellhead,
natural gas consists of a mixture of hydrocarbons that must be processed to
remove NGLs and impurities to 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 largest source of volumes
processed by our NGL fractionators and are 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 received by NGL extraction,
the mixed NGL recovery levels of gas processing plants may be reduced. This
leads to a reduction in volumes available for NGL fractionation. The increase or
decrease in NGL recovery levels is a primary factor behind changes in gross
fractionation volumes.
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 us. 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.
Based upon industry data, we believe 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
14
historically had a higher concentration of NGLs than continental shelf or
domestic land-based production along the Gulf Coast. In addition, through
connections with our Mid-America and Seminole pipeline systems, our Mont Belvieu
NGL fractionator has access to NGLs from additional major supply basins in North
America, including the Rocky Mountain Overthrust and San Juan Basin NGL
production areas. Lastly, significant volumes of mixed NGLs are contractually
committed to our NGL fractionation facilities by joint owners and third-party
customers.
The majority of our NGL fractionation facilities process mixed NGL
streams for third-party customers and our NGL marketing activities under toll
fee arrangements. This fee (typically in cents per gallon) is subject to
adjustment for changes in certain fractionation expenses, including natural gas
fuel costs. At our Norco and Toca-Western facilities, we perform fractionation
services for certain customers by retaining a percentage of the NGLs we
fractionate for them as payment (an "in-kind" fee). The results of operations 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). We are exposed to fluctuations in NGL prices to the extent we
receive in-kind fees for our services. Our tolling customers generally retain
title to the NGLs that we process for them. Overall, the NGL fractionation
business exhibits little to no seasonal variation.
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 440 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 facilities in Kansas and several facilities
in Louisiana. Finally, we also compete with a number of producers who operate
small NGL fractionators at individual field processing facilities.
Our NGL fractionation operations include eight NGL fractionators with a
combined gross processing capacity of 572 MBPD and a net processing capacity to
us of 331 MBPD. The following table summarizes our NGL fractionation facilities:
GROSS OUR NET
CAPACITY, OWNERSHIP CAPACITY,
NGL FRACTIONATION FACILITY LOCATION MBPD INTEREST MBPD
- -----------------------------------------------------------------------------------------------------------------
Mont Belvieu Texas 210 75.00% 158
Promix Louisiana 145 33.33% 48
Norco Louisiana 70 100.00% 70
BRF Louisiana 60 32.24% 19
Venice Louisiana 36 13.10% 5
Tebone Louisiana 30 33.70% 10
Toca-Western Louisiana 14 100.00% 14
Petal Mississippi 7 100.00% 7
------- ------
Total 572 331
======= ======
15
During 2002, our NGL fractionation facilities processed mixed NGLs at
an average rate of 235 MBPD or 75% of capacity, both amounts on a net basis. The
following table shows net processing volumes and capacity (in MBPD) and the
corresponding overall utilization rates of our NGL fractionation facilities for
the last three years:
FOR YEAR ENDED DECEMBER 31,
-------------------------------------
NGL FRACTIONATION FACILITY 2002 2001 2000
- --------------------------------------------------------------------------------------
Mont Belvieu 127 110 106
Promix 30 30 34
Norco 41 41 47
BRF 17 14 15
Other 20 9 11
----------------------------------------
Total net volume 235 204 213
========================================
Net capacity (1) 313 290 290
========================================
Utilization rate 75% 70% 73%
========================================
- -------------------------------------------------------------------------------
(1) Net capacity amounts have been adjusted for the timing of acquisitions
Mont Belvieu. We operate one of the largest NGL fractionation
facilities in the United States with a gross processing capacity of 210 MBPD.
Our facility is located at Mont Belvieu, Texas, which is the key hub of the
domestic NGL industry. This hub is adjacent to the largest concentration of
refineries and petrochemical plants in North America and is located on a large
naturally-occurring salt dome that provides for the underground storage of
significant quantities of NGLs.
Our Mont Belvieu facility processes mixed NGLs from several major NGL
supply basins in North America including the Mid-Continent, Permian Basin, San
Juan Basin, Rocky Mountain Overthrust and the U.S. Gulf Coast. Our Mont Belvieu
NGL fractionation facility is supported by long-term fractionation agreements
with Burlington Resources and Duke (which accounted for 73 MBPD of net
processing volume in 2002), each of which is a significant producer of NGLs and
a co-owner of the facility. In June 2002, we purchased an additional 12.5%
ownership interest in these assets from ChevronTexaco for approximately $8.1
million. As a result, we own an effective 75% interest in this facility.
Promix. We operate and own a 33.3% interest in Promix, which owns a 145
MBPD NGL fractionation facility located near Napoleonville, Louisiana. Promix
includes a 410-mile mixed NGL gathering system connected to twelve gas
processing plants, five NGL salt dome storage wells and a barge loading
facility.
Norco. We own and operate an NGL fractionation facility at Norco,
Louisiana. The Norco facility receives mixed NGLs via pipeline from the
Yscloskey and Toca natural gas processing plants in Louisiana and has a gross
processing capacity of 70 MBPD. During 2002, long-term in-kind fee arrangements
exclusive to this facility accounted for approximately 32 MBPD of processing
volume.
BRF. We operate and own a 32.2% 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.
Toca-Western. We own and operate an integrated NGL fractionation and
natural gas processing facility located in St. Bernard Parish, Louisiana that we
acquired in 2002. The NGL fractionator contained within this complex has a gross
and net processing capacity of 14 MBPD.
Tebone. We own a 33.7% interest in a 30 MBPD NGL fractionation facility
located in Ascension Parish, Louisiana. The Tebone NGL fractionation facility
was built in the 1960s and receives NGLs from the North Terrebonne gas
processing plant.
16
Petal. We own and operate an NGL fractionation facility at Petal,
Mississippi that has an average production capacity of 7 MBPD. The Petal
facility is connected to our Chunchula pipeline system and serves NGL producers
in Mississippi, Alabama and Florida.
Venice. As a result of our VESCO investment, we own a 13.1% interest in
a 36 MBPD NGL fractionator located in Plaquemines Parish, Louisiana. This
facility is part of the integrated natural gas processing complex owned by
VESCO.
Isomerization
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. Customers utilizing the services
provided by these facilities include third parties and our Processing segment's
NGL marketing activities. 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. These facilities also produce high purity grade isobutane
under various toll processing agreements to meet BEF's feedstock requirements.
The isomerization facilities are also used by our Processing segment's NGL
marketing activities to convert normal and/or mixed butanes into isobutane in
order to satisfy isobutane sales contracts. The intersegment tolling revenues we
record for these services in our isomerization business and the corresponding
expense to our NGL marketing activities are eliminated in consolidation. During
2002, 18 MBPD of isobutane production was attributable to our NGL marketing
activities, 16 MBPD to BEF-related contracts, with the balance related to
various toll processing arrangements.
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. 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 ISOMERIZATION FACILITY 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------
Production 84 80 74
==============================================
Net capacity 116 116 116
==============================================
72% 69% 64%
Utilization rate ==============================================
In the isomerization market, we compete primarily 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 our Mont Belvieu complex with its extensive connections to
pipeline and storage assets.
17
Propylene fractionation
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.
Results of operations for our polymer grade propylene plants are
generally dependent upon toll processing arrangements and petrochemical
marketing activities. Under toll processing arrangements, we are paid fees based
on the volume of refinery grade propylene used to produce polymer grade
propylene. Our largest toll processing customers in 2002 were Huntsman and
Equistar. As part of our petrochemical marketing activities, we have several
long-term polymer grade propylene sales agreements, the largest of which is with
an affiliate of Shell. To meet our petrochemical marketing obligations, we have
entered into several long-term agreements to purchase refinery grade propylene.
To limit the exposure of our petrochemical marketing activities to price risk,
we attempt to match the timing and price of our feedstock purchases with those
of the sales of end products. During 2002, 11 MBPD of our net polymer grade
propylene production was associated with toll processing operations with the
balance attributable to petrochemical marketing activities. Overall, the
propylene fractionation business exhibits little seasonality.
We can unload barges carrying refinery grade propylene using our import
terminal located on the Houston Ship Channel. In addition, we can 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 and from other third party pipelines. In turn, polymer grade
propylene is transported to customers by truck or pipeline. We can also export
volumes of polymer grade propylene as a result of our investment in OTC.
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 energy cost efficient which allows
us to be 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. Our petrochemical marketing
activities encounter competition from fully integrated oil companies and various
petrochemical companies. Each of our petrochemical marketing competitors have
varying levels of financial and personnel resources and competition generally
revolves around price, service, logistics and location issues. Our propylene
fractionation business consists of three polymer grade propylene facilities and
one chemical grade propylene plant. The following table summarizes our propylene
fractionation business assets and ownership:
GROSS EFFECTIVE NET
CAPACITY, OWNERSHIP CAPACITY,
PROPYLENE FRACTIONATION FACILITY LOCATION MBPD INTEREST MBPD
- ---------------------------------------------------------------------------------------------------------------------
Splitter I Texas 17 100.0% 17
Splitter II Texas 14 100.0% 14
Splitter III Texas 41 66.7% 27
BRPC Louisiana 23 30.0% 7
-------------- ------------
Total 95 65
============== ============
18
During 2002, our propylene fractionation facilities produced at an
average rate of 56 MBPD or 89% of capacity, both amounts on a net basis. The
table below shows our net production volumes and capacity (both in MBPD) based
on our ownership interest and the corresponding overall utilization rates of our
facilities for the last three years:
FOR YEAR ENDED DECEMBER 31,
----------------------------------
PROPYLENE FRACTIONATION FACILITY 2002 2001 2000
- -------------------------------------------------------------------------------
Splitter I & II 27 27 29
Splitter III 25 n/a n/a
BRPC 4 4 4
----------------------------------
Total net volume 56 31 33
==================================
Net capacity (1) 63 38 35
==================================
Utilization rate 89% 82% 94%
==================================
- -------------------------------------------------------------------------------
(1) Net capacity amounts have been adjusted for the timing of acquisitions
Splitter I, II and III. We operate three polymer grade propylene
fractionation facilities (Splitters I, II and III) in Mont Belvieu, Texas having
a combined net capacity of 58 MBPD. We own a 54.6% interest in Splitter I, all
of Splitter II and a 66.7% interest in Splitter III. We lease the remaining
45.4% interest in Splitter I from an affiliate of Shell. We acquired the
Splitter III facility and related assets from Diamond-Koch in February 2002 for
$239 million in cash. Approximately 80% of the feedstock requirements of these
facilities are under long-term supply contracts, with the remaining 20% being
met through spot market purchases. The majority of the feedstock volumes
originate from refineries along the Gulf Coast and in the Mid-Continent regions
of North America.
BRPC. We operate and own a 30.0% 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. The results
of operation of BRPC depend upon the volume of refinery grade propylene
processed and the level of fees we charge Exxon Mobil.
19
PROCESSING
The Processing segment consists of our natural gas processing business
and related NGL marketing activities. At the core of our natural gas processing
business are thirteen processing plants located on the Louisiana and Mississippi
Gulf Coast with a gross natural gas processing capacity of 11.77 Bcf/d (3.37
Bcf/d on a net basis). The following table lists our gas processing plants,
gross and net processing capacities and our current ownership interest in each
facility:
GROSS GAS NET GAS
PROCESSING OUR PROCESSING
CAPACITY OWNERSHIP CAPACITY
NATURAL GAS PROCESSING FACILITY LOCATION (BCF/D) INTEREST (BCF/D)
- --------------------------------------------------------------------------------------------------------
Toca Louisiana 1.10 59.9% 0.66
Yscloskey Louisiana 1.85 32.1% 0.59
Calumet Louisiana 1.60 31.3% 0.50
Pascagoula Mississippi 1.00 40.0% 0.40
North Terrebonne Louisiana 1.30 28.8% 0.37
Neptune Louisiana 0.30 66.0% 0.20
Venice Louisiana 1.30 13.1% 0.17
Toca-Western Louisiana 0.16 100.0% 0.16
Sea Robin Louisiana 0.95 15.5% 0.15
Burns Point Louisiana 0.16 50.0% 0.08
Blue Water Louisiana 0.95 7.4% 0.07
Iowa Louisiana 0.50 2.0% 0.01
Patterson II Louisiana 0.60 2.0% 0.01
--------- --------
Total 11.77 3.37
========= ========
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
takes title to the NGLs extracted from the natural gas stream and reimburses
producers for the market value of the energy extracted based upon the Btus
consumed from the natural gas stream in the form of fuel and mixed NGLs are
defined as "keepwhole" contracts. The processor derives a profit margin from
these contracts to the extent the market value of the NGLs extracted exceeds the
costs of extraction.
Our natural gas processing facilities are primarily straddle plants
situated on mainline natural gas pipelines that bring unprocessed natural gas
production from the Gulf of Mexico onshore. These facilities 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 typically 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 in our NGL marketing activities to meet
contractual requirements or sold on spot and forward markets.
The natural gas processing 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 73 MBPD during 2002, 63
MBPD during 2001 and 72 MBPD during 2000.
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
20
includes natural gas production from deepwater developments. This is a life of
lease dedication, which may extend the agreement well beyond 20 years. Shell is
one of the largest oil and gas producers and holds one of the largest lease
positions in the deepwater Gulf of Mexico. Generally, this contract has the
following rights and obligations:
o the exclusive right, but not the obligation, to process
substantially all of Shell's Gulf of Mexico natural gas production;
plus
o the exclusive right, but not the obligation, to process all natural
gas production from leases dedicated by Shell for the life of such
leases; plus
o 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
o the obligation to re-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.
As noted previously, we take title to a portion of the mixed NGLs that
are extracted by our natural gas processing 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 NGL marketing activities.
As part of these marketing activities, we have a number of isobutane sales
contracts. To fulfill our obligations under these sales contracts, we can
purchase isobutane on the open market for resale, sell isobutane from our
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. The intersegment
expense and revenue recorded as a result of utilizing the services of our
isomerization business are eliminated in consolidation.
In support of its commercial goals, our NGL marketing activities within
this segment rely on inventories of mixed NGLs and purity NGL products. These
inventories are the result of accumulated equity NGL production volumes, imports
and other spot and contract purchases. Our inventories of ethane, propane and
normal butane are typically higher in summer months as each are in higher demand
and at higher price levels during winter months. Isobutane and natural gasoline
inventories are generally flat throughout the year. Our inventory cycle begins
in late-February to mid-March (the seasonal low point); builds through
September; remains flat until early December; before being drawn down through
winter until the seasonal low is reached again.
Since we take title to NGLs and are obligated under certain of our gas
processing contracts to pay market value for or replace 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. Periodically, we attempt to
mitigate these risks through the use of commodity financial instruments.
Some of our exposure to commodity price risk is mitigated because
natural gas with a high content of NGLs must be processed in order to meet
pipeline quality specifications and to be suitable for ultimate consumption. To
the 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). During periods of
extreme commodity price fluctuations, we reserve the right to withhold
processing services from a customer should we and the producer be unsuccessful
in reaching acceptable contractual arrangements.
Our gas processing business and NGL marketing 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
21
and NGL marketing as we do. Our competitive and/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 NGL marketing activities utilize a fleet of approximately 660
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 both our rail shipments and those of our customers.
This segment 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 the Gulf of Mexico. In
addition, we acquired four NGL terminals (primarily in propane service) from
CornerStone in November 2002. These terminals are located in Bakersfield and
Rocklin, California; Reno, Nevada and Albertville, Alabama and have an aggregate
storage capacity of 0.1 million barrels of NGLs.
OCTANE ENHANCEMENT
The Octane Enhancement segment consists of our 33.3% interest in BEF,
which owns a facility that produces motor gasoline additives to enhance octane.
Our partners in BEF are affiliates of Sunoco and Devon Energy. The BEF facility
currently produces MTBE and is located within our Mont Belvieu complex. The
gross production capacity of the MTBE facility is approximately 16.5 MBPD with a
net production capacity of 5.5 MBPD. For the years 2002, 2001 and 2000, BEF
operated at near capacity levels. 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 is the most
widely used due to its ready availability and history of acceptance by refiners.
MTBE demand is primarily 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 Sunoco under which Sunoco 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, Sunoco is required to
purchase all of the plant's MTBE production at spot-market related prices.
Sunoco 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 Sunoco 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 and legal developments" below within
this section).
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
isomerization 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. BEF's methanol feedstock originates
from a number of domestic and foreign producers, including those located in
Venezuela, Chile, New Zealand and the Caribbean. Lastly, BEF's MTBE production
is transported to a location on the Houston Ship Channel for delivery to Sunoco
using our HSC pipeline system.
22
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 Sunoco contract is in effect, BEF is not directly exposed to its
competition, although it is affected by market pricing through the Sunoco
off-take agreement. The large size 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 and legal 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.
BEF has not been named in any MTBE legal action to date. 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
28. For a brief discussion of recent significant legal challenges involving
MTBE, see "Uncertainties regarding our investment in facilities that produce
MTBE" under Item 7 of this report.
Alternative uses of the BEF facility. In light of these developments,
we and the other two owners of BEF are actively compiling a contingency plan for
the BEF facility should MTBE be banned. We are currently evaluating a possible
conversion of the facility from MTBE production to alkylate production. In
addition to MTBE's value in reducing air pollution, it is a significant source
of octane in the U.S. motor gasoline pool. Octane is a critical component of
motor gasoline. Therefore, 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 gasoline and that alkylate would be an
economic and effective substitute. We are currently conducting a detailed
engineering study that is expected to be completed by the end of 2003, at which
time we expect a more definitive conversion cost estimate will be available. The
cost to convert the facility will depend on the type of alkylate process chosen
and the level of production desired by the partnership.
OTHER
This operating segment is comprised of fee-based marketing services and
unallocated costs of engineering services, construction equipment rentals and
computer network services that support our operations and business activities.
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. 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 29 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.
EMPLOYEES
We do not have any employees. EPCO employs most of the persons
necessary for the operation of our business. At December 31, 2002, EPCO had
approximately 1,000 employees involved in the management and operations of our
business, none of whom were members of a union. We fully reimburse EPCO for the
costs of approximately 900 of these employees, with the remainder of this group
covered under the fixed-fee payments we make under the EPCO Agreement (for a
detailed discussion of the EPCO Agreement, please read Item 13 of this annual
report). In addition to EPCO employees, we have engaged approximately 150
contract maintenance and other personnel who support our operations.
On February 1, 2003, we assumed the operations of the Mid-America and
Seminole pipelines from Williams. As a result, EPCO hired from Williams
approximately 270 employees involved in the operations and administration of
these systems. We will fully reimburse EPCO for the costs associated with these
new employees.
MAJOR CUSTOMERS
Our revenues are derived from a wide customer base. Our largest
customer, Shell and its affiliates, accounted for 7.8%, 10.5% and 9.5% of
consolidated revenues in 2002, 2001 and 2000, respectively.
23
Approximately 88% of our revenue from Shell and its affiliates during 2002 was
attributable to the sale of NGL products which are recorded in our Processing
segment.
REGULATION AND ENVIRONMENTAL MATTERS
Regulation of our interstate common carrier liquids pipelines
Our Mid-America, Seminole, Chunchula, Lou-Tex Propylene, Lou-Tex NGL
and Lake Charles/Bayport and certain pipelines in which we own equity interests
(Dixie, Tri-States, Wilprise and Belle Rose) 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
Mid-America, Seminole, Chunchula and Lake Charles/Bayport pipelines and portions
of the Louisiana Pipeline System are covered by the grandfathering provisions of
the Energy Policy Act.
The Energy Policy Act required the FERC to issue rules establishing a
simplified and generally applicable ratemaking methodology for petroleum
pipelines, and to streamline procedures in petroleum pipeline proceedings. The
FERC responded to this mandate by issuing Order No. 561, which, among other
things, adopted a new indexing rate methodology for petroleum pipelines. Under
the new regulations, which became effective January 1, 1995, petroleum pipelines
are able to change their rates within prescribed ceiling levels that are tied to
an inflation index. Rate increases made within the ceiling levels will be
subject to protest, but such protests must show that the portion of the rate
increase resulting from application of the index is substantially in excess of
the pipeline's increase in costs. If the indexing methodology results in a
reduced ceiling level that is lower than a pipeline's filed rate, Order No. 561
requires the pipeline to reduce its rate to comply with the lower ceiling. Under
Order No. 561, a pipeline must as a general rule utilize the indexing
methodology to change its rates. The FERC, however, retained cost-of-service
ratemaking, market-based rates, and settlement as alternatives to the indexing
approach. These alternatives may be used in certain specified circumstances.
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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 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. 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). While it is not possible to predict the likelihood that such a
challenge would succeed at the FERC, if such a challenge 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 limited 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
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. The U.S. Court of
Appeals for the District of Columbia Circuit recently issued a decision that
either upheld or declared premature for review most major aspects of Order No.
637. Order No. 637 required interstate natural gas pipelines to implement the
policies mandated by the Order through individual compliance filings. The FERC
has now ruled on a number of the individual compliance filings, although its
decisions in such proceedings remain subject to the outcome of pending rehearing
requests and possible court appeals. 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
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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 and Nemo, 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 the majority of
the Acadian Gas natural gas pipeline systems 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. Intrastate movements of
products on the Seminole, Mid-America, Belle Rose and Wilprise pipelines are
provided by them as intrastate common carriers that are subject to various other
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 produce 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 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
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operations and facilities have all required permits and 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 discharges 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 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.
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
27
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 ten 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 have required 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 were challenged under state law in litigation filed on
January 19, 2001 against the predecessor of the Texas Commission on
Environmental Quality ("TCEQ") and its principal officials in the District Court
of Travis County, Texas, by a coalition of major Houston-Galveston area
industries that included us. This litigation was stayed by a settlement under
which the TCEQ agreed to reassess the December 2000 rules in light of certain
scientific studies of the sources and mechanisms of air pollution in the
Houston-Galveston area that were undertaken during the summer of 2001.
As a result of these studies, the TCEQ promulgated new rules on
December 13, 2002 that require less restrictive nitrogen oxide reductions for
certain industrial sources in the Houston-Galveston area, including some of
those we operate, than were required under the December 2000 rules. The December
2002 rules, however, require additional controls on emission sources of
so-called highly reactive volatile organic compounds, a class of chemicals that
includes certain types of hydrocarbons handled at our facilities in the
Houston-Galveston area. We believe that the result of the new rules will be to
decrease our projected capital outlays and operating costs for air pollution
control in the Houston-Galveston area compared to what would have been required
under the December 2000 rules. There is no guarantee that the EPA will approve
the new rules as part of the state implementation plan for the Houston-Galveston
area, and there may be additional legal challenges to the new rules, either of
which could result in additional rulemaking that could affect our operations.
As a result of our evaluation of the December 2002 rules, however, we
expect that 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 2003 to
continue making modifications begun in 2002 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 in BEF, which owns a facility currently
producing MTBE. The production of MTBE is driven primarily by oxygenated fuels
programs established under the federal Clean Air Amendments of 1990 and other
legislation. On March 25, 1999, the governor of California ordered the phase-out
of MTBE in California based on 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. California's deadline for the complete phase-out of MTBE is
December 31, 2003. At least twelve other states are following California's lead
and either have banned or currently are considering legislation to ban MTBE.
Congress is also contemplating a federal ban on MTBE. On April 25, 2002, the
Senate approved an energy bill that in part would have banned the use of MTBE
within four years of enactment and require the use of ethanol as a substitute
for MTBE; this legislation was not enacted into law. Similar legislation is
expected to be considered in the new Congress that convened in January 2003, but
the outlook for passage is uncertain. Several refiners have taken an early
initiative to phase out the production of MTBE in response to this legislative
pressure and the possibility of additional groundwater contamination lawsuits.
If MTBE is banned or if its use is significantly limited, the revenue
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BEF derives from MTBE production would be reduced or eliminated, which in turn
would affect the equity earnings we record from BEF in our Octane Enhancement
segment. Also, to the extent isobutane is used as a feedstock in the production
of MTBE and this demand is reduced or eliminated due to a ban on MTBE
production, the revenues we record in our Fractionation segment for
isomerization services and in our Processing segment for sales of isobutane
could be unfavorably impacted.
Legislation introduced in the U.S. Senate in 2001 and 2002, as part of
an Energy Bill, would have eliminated 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. This legislation, as well as legislation to allow California to ban
MTBE, was defeated. The outlook for the new Congress that convened in January
2003 is uncertain, and no assurance can be given as to whether or not 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 regulate potential discharges of contaminants into
federal and state waters. Regulations pursuant to these laws require companies
that discharge into federal and state waters to 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. The Clean
Water Act also requires operators of facilities with underground or above ground
oil storage capacity in excess of certain prescribed amounts to prepare and
implement spill prevention, control and countermeasure ("SPCC") plans. 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 formations in Texas, Oklahoma, Louisiana and
Mississippi. We also own and operate underground storage caverns that have been
created in subsurface limestone formations in Iowa and Nebraska. 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 the other states in which such facilities are located. 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 oil and gas pipelines are subject to the pipeline safety program
established by the 1996 federal Pipeline Safety Act and its implementing
regulations. The U.S. Department of Transportation, through the Office of
Pipeline Safety ("OPS"), is responsible for developing, issuing and enforcing
regulations relating to the design, construction, inspection, testing,
operation, replacement and management of natural gas and hazardous liquid
pipelines. On November 15, 2002, Congress passed the Pipeline Safety Improvement
Act, which contains requirements for the development of integrity management
programs or gas pipelines located in certain "high consequence areas." On
January 28, 2003, the OPS issued a proposed rulemaking that would require gas
pipeline operators to develop integrity management programs for gas transmission
pipelines that, in the event of a failure, could impact high consequence areas.
The proposed rulemaking has not been finalized and is still subject to public
comment. Similar integrity management program requirements have already been
implemented for oil pipelines located in or near high consequence areas. We
believe that our pipeline operations are in substantial compliance with
applicable regulations. Furthermore, we believe the implementation of currently
proposed pipeline safety regulations would not have a significant impact on our
results of operations or financial position.
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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 we have 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 we have satisfactory title to all of our material leases,
easements, rights-of-way and licenses.
OUR SEC REPORTING
As an accelerated filer, we electronically file certain documents with
the SEC. We file combined annual reports for both registrants on Form 10-K;
combined quarterly reports for both registrants on Form 10-Q; combined and
separate current reports on Form 8-K (as appropriate); along with any related
amendments and supplements thereto. From time-to-time, we may also file
registration and related statements pertaining to equity or debt offerings of
our registrants. You may read and copy any materials we file with the SEC at the
SEC's Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You
may obtain information regarding the Public Reference Room by calling the SEC at
1-800-SEC-0330. In addition, the SEC maintains an internet website at
www.sec.gov that contains reports, proxy and information statements, and other
information regarding issuers that file electronically with the SEC.
We provide electronic access to our periodic and current reports on our
internet website, www.epplp.com. These reports are available on our website as
soon as reasonably practicable after we electronically file such materials with
the SEC. You may also contact our investor relations department at 713-880-6500
for paper copies of these reports free of charge.
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
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 2002.
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PART II
ITEM 5. MARKET FOR REGISTRANTS' 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
--------------------------------------------------------------------
PRICE RANGES (1) PER PER
----------------------------- COMMON SUBORDINATED RECORD PAYMENT
HIGH LOW UNIT (1) UNIT (1) DATE DATE
--------------------------------------------------------------------------------------------------
2001
----
1st Quarter $18.40 $13.25 $0.2750 $0.2750 Apr. 30, 2001 May 10, 2001
2nd Quarter $21.88 $16.60 $0.2938 $0.2938 Jul. 31, 2001 Aug. 10, 2001
3rd Quarter $24.18 $19.75 $0.3125 $0.3125 Oct. 31, 2001 Nov. 9, 2001
4th Quarter $26.30 $21.80 $0.3125 $0.3125 Jan. 31, 2002 Feb. 11, 2002
2002
----
1st Quarter $25.79 $24.94 $0.3350 $0.3350 Apr. 30, 2002 May 10, 2002
2nd Quarter $24.50 $16.25 $0.3350 $0.3350 Jul. 31, 2002 Aug. 12, 2002
3rd Quarter $22.23 $15.00 $0.3450 $0.3450 Oct. 31, 2002 Nov. 12, 2002
4th Quarter $19.80 $16.41 $0.3450 $0.3450 Jan. 31, 2003 Feb. 12, 2003
- -------------------------------------------------------------------------------------------------------------------
(1) As appropriate, the historical pricing and other data presented within this
table have been adjusted for the two-for-one Unit split that occurred in May
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 February 28, 2003, there were approximately 24,667 beneficial
owners of our Common Units, which includes an estimated 223 Unitholders of
record.
ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth for the periods and at the dates
indicated, selected historical financial data for the Company and Operating
Partnership. The selected historical financial data have been derived from the
audited financial statements of each registrant for the periods indicated. The
selected historical income statement data for each of the three years ended
December 31, 2002, 2001 and 2000 and the selected balance sheet data as of
December 31, 2002 and 2001 should be read in conjunction with the audited
financial statements for such periods included under Item 8 of this report for
both entities. In addition, combined information regarding results of operations
and capital resources and liquidity can be found under Item 7 of this report,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
31
The dollar amounts in each table, except per Unit data for the Company,
are in thousands. Additionally, certain reclassifications have been made to
prior years financial statements to conform to the current year presentation.
ENTERPRISE PRODUCTS PARTNERS L.P. AND SUBSIDIARIES, CONSOLIDATED
2002 2001 2000 1999 1998
-------------------------------------------------------------------------
INCOME STATEMENT DATA:
Revenues $ 3,584,783 $ 3,154,369 $ 3,049,020 $ 1,332,979 $ 738,902
Operating income $ 194,585 $ 287,688 $ 243,734 $ 132,351 $ 50,473
Extraordinary charge related to the
extinguishment of debt $ (27,176)
Net income $ 95,500 $ 242,178 $ 220,506 $ 120,295 $ 10,077
Basic net income per Unit (1) $ 0.55 $ 1.70 $ 1.62 $ 0.90 $ 0.09
Diluted net income per Unit (2) $ 0.48 $ 1.39 $ 1.32 $ 0.82 $ 0.09
BALANCE SHEET DATA (AT PERIOD END):
Total assets $ 4,230,272 $ 2,424,692 $ 1,951,368 $ 1,494,952 $ 741,037
Long-term and current maturities of
debt $ 2,246,463 $ 855,278 $ 403,847 $ 295,000 $ 90,000
Partners' equity $ 1,200,904 $ 1,146,922 $ 935,959 $ 789,465 $ 562,536
OTHER FINANCIAL DATA:
Cash distributions declared per
Common Unit (3) $ 1.3600 $ 1.1940 $ 1.0500 $ 0.9250 $ 0.3850
Commodity hedging income (losses) $ (51,344) $ 101,290 $ 26,743 $ (5,208) N/A
- ---------------------------------------------------------------------------------------------------------------------
(1) Net income allocable to our Limited Partners divided by the weighted-average
number of Common and Subordinated Units outstanding during the period.
(2) Net income allocable to our Limited Partners divided by the weighted-average
number of Common, Subordinated and Special Units outstanding during the period.
(3) Cash distributions began after our initial public offering of Common Units
on July 27, 1998. See Item 5 of this annual report for additional information
regarding cash distributions.
OPERATING PARTNERSHIP AND SUBSIDIARIES, CONSOLIDATED
2002 2001 2000 1999 1998
-------------------------------------------------------------------------
INCOME STATEMENT DATA:
Revenues $ 3,584,783 $ 3,154,369 $ 3,049,020 $ 1,332,979 $ 738,902
Operating income $ 194,811 $ 287,172 $ 243,734 $ 132,351 $ 50,473
Extraordinary charge related to the
extinguishment of debt $ (27,176)
Net income $ 96,952 $ 244,178 $ 223,068 $ 121,730 $ 10,057
BALANCE SHEET DATA (AT PERIOD END):
Total assets $ 4,231,561 $ 2,424,722 $ 1,948,610 $ 1,492,712 $ 741,037
Long-term and current maturities of
debt $ 2,246,463 $ 855,278 $ 403,847 $ 295,000 $ 90,000
Partners' equity $ 1,211,736 $ 1,153,618 $ 942,671 $ 794,626 $ 567,273
OTHER FINANCIAL DATA:
Commodity hedging income (losses) $ (51,344) $ 101,290 $ 26,743 $ (5,208) N/A
Since we are the parent of the Operating Partnership, we consolidate
its operations and financial results with our own. The Operating Partnership
owns substantially all of our consolidated assets and conducts substantially all
of our business and operations. As a result, there is very little difference
between our financial information and that of the Operating Partnership. In
general, our consolidated results of operations and financial position have been
materially affected by acquisitions since 1999. Our more significant
acquisitions during this period were:
32
o William's Mid-America and Seminole pipelines in July 2002 for $1.2
billion;
o Diamond-Koch's propylene fractionation business in February 2002 for
$239 million ;
o Diamond-Koch's NGL and petrochemical storage business in January
2002 for $129.6 million;
o Shell's Acadian Gas pipeline business in April 2001 for $243.7
million;
o El Paso's equity interests in four Gulf of Mexico natural gas
pipelines in January 2001 for $113 million; and
o Shell's TNGL natural gas processing and related businesses in August
1999 for $528.8 million.
With the exception of our purchase of TNGL and Diamond-Koch's storage
business, our acquisitions have been financed primarily through borrowings. In
October 2002 and January 2003, we completed two public Common Unit offerings
from which we received $442.1 million, which we subsequently used to repay a
portion of the debt we incurred in the Mid-America and Seminole acquisitions. We
used cash on hand to acquire Diamond-Koch's storage business. Our acquisition of
TNGL was accomplished through cash payments and the issuance of partnership
equity to Shell.
Operating income and net income include the results of our commodity
hedging activities. We entered into these activities as a result of acquiring
TNGL's natural gas processing and related businesses from Shell in August 1999.
To manage the risks associated with our Processing segment activities, we may
enter into various commodity financial instruments. The primary purpose of these
risk management activities is to hedge our exposure to price risks associated
with natural gas, NGL production and inventories, firm commitments and certain
anticipated transactions. As a matter of policy, we do not use financial
instruments for speculative (or trading) purposes. For additional information
regarding our use of financial instruments, please read Item 7A of this annual
report. In addition, please see our footnote titled "Financial Instruments" in
the Notes to Consolidated Financial Statements under Item 8 of this annual
report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATION.
We are a publicly traded limited partnership (NYSE symbol, "EPD") that
was formed in April 1998 to acquire, own, and operate all of the NGL processing
and distribution assets of Enterprise Products Company, or EPCO. We conduct all
of our business through our 98.9899% owned subsidiary, Enterprise Products
Operating L.P., our "Operating Partnership" and its subsidiaries and joint
ventures. Our general partner, Enterprise Products GP, LLC, owns a 1.0% interest
in us and a 1.0101% interest in our Operating Partnership. Unless the context
requires otherwise, references to "we," "us," "our" or the "Company" are
intended to mean the consolidated business and operations of Enterprise Products
Partners L.P., which includes Enterprise Products Operating L.P. and its
subsidiaries.
The following discussion and analysis should be read in conjunction
with the audited consolidated financial statements and notes thereto of the
Company and Operating Partnership included under Item 8 of this report on Form
10-K. In addition, the reader should review "Cautionary Statement Regarding
Forward-Looking Information and Risk Factors" under Item 1 of this annual 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
Risk" beginning on page 55 of this report. Additionally, please see Part III,
Item 13 for a discussion of related-party matters, including our relationship
with Shell.
OUR RESULTS OF OPERATION
We have five reportable operating segments: Pipelines, Fractionation,
Processing, Octane Enhancement and Other. Pipelines consists of NGL,
petrochemical and natural gas pipeline systems, storage and import/export
terminal services. Fractionation primarily includes NGL fractionation,
isomerization and propylene fractionation. Processing includes our natural gas
processing business and related NGL marketing activities. Octane Enhancement
represents our interest in a facility that produces motor gasoline additives to
enhance octane (currently producing MTBE). The Other operating segment consists
of fee-based marketing services and various operational support activities.
33
Our management evaluates segment performance based on our measurement
of segment gross operating 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 and administrative expenses. Segment gross operating margin is
exclusive of other income and expense transactions, provision for income taxes,
minority interest and extraordinary charges.
We include equity earnings from unconsolidated affiliates in our
measurement of segment gross operating margin. Our equity investments with
industry partners are a vital component of our business strategy. They are a
means by which we conduct our operations to align our interests with a supplier
of raw materials or a consumer of finished products. 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 additional information regarding our
business segments, see the Notes to our Consolidated Financial Statements under
Item 8 of this annual report.
Under the terms of an agreement we executed with EPCO at our formation
in 1998 (the "EPCO Agreement", see Item 13), EPCO subleases to us certain
equipment located at our Mont Belvieu facility and 100 railcars for one dollar
per year (the "retained leases"). EPCO holds these items pursuant to operating
leases for which it has agreed to retain the corresponding lease payment
obligation. Operating costs and expenses (as shown in the Statements of
Consolidated Operations and Comprehensive Income) treat the lease payments being
made by EPCO as a non-cash related party operating expense, with the offset to
Partners' Equity on the Consolidated Balance Sheets recorded as a general
contribution to the partnership. EPCO does not receive any additional ownership
rights as a result of its contribution to us of the retained leases. In
addition, EPCO has assigned to us the purchase options associated with these
leases. These purchase options are based on the estimated fair market values of
the equipment at the end of their respective lease terms. For additional
information regarding these retained leases, see Item 13 of this annual report
and our "Capital Spending" disclosure on page 68.
The following table shows our measurement of total gross operating
margin for the periods indicated (dollars in thousands):
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
Revenues (1) $ 3,584,783 $ 3,154,369 $ 3,049,020
Operating costs and expenses (1) (3,382,561) (2,861,743) (2,801,060)
Equity in income of unconsolidated affiliates (2) 35,253 25,358 24,119
---------------------------------------------------
Subtotal 237,475 317,984 272,079
Add: Depreciation and amortization in
operating costs and expenses (3) 86,029 48,775 35,621
Retained lease expense, net in
operating costs and expenses (4) 9,124 10,414 10,645
(Gain) loss on sale of assets in
operating costs and expenses (3) (1) (390) 2,270
---------------------------------------------------
Total segment gross operating margin $ 332,627 $ 376,783 $ 320,615
===================================================
- -------------------------------------------------------------------------------
(1) Amounts are comprised of both third party and related party totals from the
Statements of Consolidated Operations and Comprehensive Income
(2) Amount taken from Statements of Consolidated Operations and Comprehensive
Income
(3) Amount taken from Statements of Consolidated Cash Flows
(4) Amount represents leases paid by EPCO and the related contribution by the
minority interest as reflected on the Statements of Consolidated Cash Flows
34
Our measurement of gross operating margin amounts by segment along with
a reconciliation to consolidated operating income were as follows for the
periods indicated (dollars in thousands):
FOR YEAR ENDED DECEMBER 31,
----------------------------------------------------
2002 2001 2000
----------------------------------------------------
Gross operating margin by segment:
Pipelines $ 214,932 $ 96,569 $ 56,099
Fractionation 129,000 118,610 129,376
Processing (17,633) 154,989 122,240
Octane enhancement 8,569 5,671 10,407
Other (2,241) 944 2,493
----------------------------------------------------
Total segment gross operating margin 332,627 376,783 320,615
Depreciation and amortization (86,029) (48,775) (35,621)
Retained lease expense, net (9,124) (10,414) (10,645)
Gain (loss) on sale of assets 1 390 (2,270)
Selling, general and administrative expenses (42,890) (30,296) (28,345)
----------------------------------------------------
Consolidated operating income $ 194,585 $ 287,688 $ 243,734
====================================================
Our significant plant production and other volumetric data were as
follows for the periods indicated:
FOR YEAR ENDED DECEMBER 31,
----------------------------------------------------
2002(1) 2001(1) 2000(1)
----------------------------------------------------
MBPD, Net
---------
Propylene Fractionation 55 31 33
Isomerization 84 80 74
NGL Fractionation 235 204 213
Equity NGL Production 73 63 72
Octane Enhancement 5 5 5
NGL and petrochemical pipelines (2) 1,357 453 367
BBtus per day, Net
------------------
Natural gas pipelines 1,207 1,349 n/a
Equivalent MBPD, Net
--------------------
NGL, petrochemical and natural gas pipelines (3) 1,675 808 367
---------------------------------------------------------------------------------------------------------
(1) Volumetric data shown in the table above reflect operating rates of the
underlying assets for the periods in which we owned them
(2) In addition to NGL and petrochemical pipeline volumes, this operating
statistic also includes NGL import and export volumes
(3) Aggregate pipeline volumes are shown on an energy-equivalent basis where 3.8
MMBtus of natural gas throughput are equivalent to one barrel of NGL throughput
35
The following table illustrates selected average quarterly prices for
natural gas, crude oil and selected NGL and petrochemical products since the
first quarter of 2000:
POLYMER REFINERY
NATURAL NORMAL GRADE GRADE
GAS, CRUDE OIL, ETHANE, PROPANE, BUTANE, ISOBUTANE, PROPYLENE, PROPYLENE,
$/MMBTU $/BARREL $/GALLON $/GALLON $/GALLON $/GALLON $/POUND $/POUND
------------------------------------------------------------------------------------------------------
(a) (b) (a) (a) (a) (a) (a) (a)
2000
1st Quarter $2.49 $28.84 $0.38 $0.54 $0.64 $0.64 $0.21 $0.17
2nd Quarter $3.41 $28.79 $0.36 $0.52 $0.60 $0.68 $0.26 $0.24
3rd Quarter $4.22 $31.61 $0.40 $0.60 $0.68 $0.67 $0.26 $0.18
4th Quarter $5.22 $31.98 $0.49 $0.67 $0.75 $0.73 $0.24 $0.19
- ----------------------------------------------------------------------------------------------------------------------
Average $3.84 $30.31 $0.41 $0.58 $0.67 $0.68 $0.24 $0.19
- ----------------------------------------------------------------------------------------------------------------------
2001
1st Quarter $7.05 $28.77 $0.49 $0.63 $0.70 $0.74 $0.23 $0.17
2nd Quarter $4.65 $27.86 $0.37 $0.50 $0.56 $0.66 $0.19 $0.12
3rd Quarter $2.90 $26.64 $0.27 $0.41 $0.49 $0.49 $0.16 $0.13
4th Quarter $2.43 $21.04 $0.21 $0.34 $0.40 $0.39 $0.18 $0.13
- ----------------------------------------------------------------------------------------------------------------------
Average $4.26 $26.07 $0.33 $0.47 $0.54 $0.57 $0.19 $0.14
- ----------------------------------------------------------------------------------------------------------------------
2002
1st Quarter $2.34 $21.41 $0.22 $0.30 $0.38 $0.44 $0.16 $0.12
2nd Quarter $3.38 $26.26 $0.26 $0.40 $0.48 $0.51 $0.20 $0.17
3rd Quarter $3.16 $28.30 $0.26 $0.42 $0.52 $0.58 $0.21 $0.16
4th Quarter $3.99 $28.33 $0.31 $0.49 $0.60 $0.63 $0.20 $0.15
- ----------------------------------------------------------------------------------------------------------------------
Average $3.22 $26.08 $0.26 $0.40 $0.50 $0.54 $0.19 $0.15
- ----------------------------------------------------------------------------------------------------------------------
(a) Natural gas, NGL, polymer grade propylene and refinery grade propylene
prices represent an average of various commercial index prices including OPIS
and CMAI
(b) Crude Oil price is representative of the index price for West Texas
Intermediate
Year ended December 31, 2002 compared to year ended December 31, 2001
The following table shows our consolidated revenues, costs and
expenses, and operating income for the years ended December 31, 2002 and 2001
(dollars in thousands):
FOR YEAR ENDED DECEMBER 31,
----------------------------------------
2002 2001
----------------------------------------
Revenues $ 3,584,783 $ 3,154,369
Costs and expenses $ 3,425,451 $ 2,892,039
Operating income $ 194,585 $ 287,688
Revenues for 2002 increased $430.4 million over those of 2001. The
increase is primarily due to acquisitions we completed during 2002 such as the
purchase of Mid-America and Seminole from Williams and Splitter III from
Diamond-Koch. Costs and expenses increased $533.4 million year-to-year primarily
due to the addition of costs and expenses of acquired businesses and an
unfavorable change in the results of our commodity hedging activities. Operating
income decreased $93.1 million primarily as a result of such changes.
Pipelines. Gross operating margin from our Pipelines segment was $214.9
million for 2002 compared to $96.6 million for 2001. On an energy-equivalent
basis, net pipeline throughput volume for 2002 was 1,669 MBPD compared to 809
MBPD during 2001. Our acquisition of the Mid-America and Seminole NGL pipelines
in July 2002 accounted for $81.1 million of the improvement in segment gross
operating margin and 843 MBPD of the increase in throughput rates. Gross
operating margin from our Mont Belvieu storage businesses improved $17.9
36
million in 2002 primarily due to the acquisition of Diamond-Koch's storage
business in January 2002. Another $10.5 million of the improvement in
year-to-year gross operating margin results from 2002 including a full year's
results of operations from Acadian Gas, whereas 2001 included only nine months.
We acquired Acadian Gas in April 2001.
Fractionation. Gross operating margin from our Fractionation segment
was $129.0 million for 2002 compared to $118.6 million for 2001. We expanded our
propylene fractionation business in February 2002 with the acquisition of
Splitter III from Diamond-Koch. Our propylene fractionation volumes increased to
55 MBPD during 2002 from 31 MBPD during 2001. Gross operating margin from these
businesses increased $22.6 million year-to-year. Splitter III accounted for 25
MBPD of the increase in volumes and $24.7 million of the increase in gross
operating margin. Our isomerization business posted a $4.6 million decrease in
gross operating margin for 2002 when compared to 2001. Isomerization volumes
increased to 84 MBPD during 2002 versus 80 MBPD during 2001. The positive effect
of the higher isomerization volumes was offset by a decrease in isomerization
revenues. Certain of our isomerization fees are indexed to historical natural
gas prices (which were higher in 2001 relative to 2002). Lastly, gross operating
margin from our NGL fractionation businesses decreased $8.1 million in 2002 when
compared to 2001. NGL fractionation volumes increased to 235 MBPD during 2002
from 204 MBPD during 2001. The year-to-year decrease in NGL fractionation gross
operating margin is primarily due to lower revenues from our Mont Belvieu
facility caused by strong competition at this industry hub, partially offset by
the addition of earnings from the Toca-Western facility we acquired in June
2002. Of the 31 MBPD increase in NGL fractionation volumes, 14 MBPD is due to
our purchase of an additional 12.5% interest in the Mont Belvieu facility and 9
MBPD is due to the acquisition of Toca-Western.
Processing. Gross operating margin from our Processing segment was a
loss of $17.6 million for 2002 compared to income of $155.0 million for 2001. Of
the $172.6 million change in gross operating margin, $152.6 million is due to a
decrease in results from our commodity hedging activities. We recorded a loss of
$51.3 million from these activities during 2002 versus income of $101.3 million
during 2001. Also, gross operating margin from NGL marketing activities included
in this segment benefited from unusually strong demand for propane and isobutane
during early and mid-2001 which did not repeat during 2002. The year-to-year net
decline in commodity hedging results and earnings from our NGL marketing
activities was partially offset by a favorable decrease in NGL inventory
valuation adjustments. Also, gross operating margin for 2001 includes the $10.6
million expense we recorded related to amounts owed to us by Enron, which filed
for bankruptcy in December 2001. Our equity NGL production was 73 MBPD during
2002 versus 63 MBPD during 2001. The 10 MBPD increase in equity NGL production
rates is primarily due to improved gas processing conditions.
As noted above, the $152.6 million decrease in commodity hedging
results was the primary reason for the year-to-year decline in gross operating
margin from this segment. In order to manage the risks associated with our
Processing segment, we may enter into short-term, highly liquid commodity
financial instruments to hedge our exposure to price risks associated with
natural gas, NGL production and inventories, firm commitments and certain
anticipated transactions. We have employed various hedging strategies to
mitigate the effects of fluctuating commodity prices (primarily NGL and natural
gas prices) on our earnings from Processing segment businesses.
Beginning in late 2000 and extending through March 2002, a large
number of our commodity hedging transactions were based on the historical
relationship between natural gas prices and NGL prices. This type of hedging
strategy utilized 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 marketing activities and the market
values of our equity NGL production. Throughout 2001, this strategy proved very
successful (as the price of natural gas declined relative to our fixed
positions) and was responsible for most of the $101.3 million in commodity
hedging income we recorded during 2001.
In late March 2002, the effectiveness of this strategy was reduced due
to an unexpected rapid increase in natural gas prices whereby the loss in the
value of our fixed-price natural gas financial instruments was not offset by
increased gas processing margins. Due to the inherent uncertainty surrounding
natural gas prices at the time, we decided that it was prudent to exit this
strategy, and we did so by late April 2002. The increased ineffectiveness of
this strategy is the primary reason for the $51.3 million in commodity hedging
losses recorded during 2002. A variety of factors influence whether or not our
hedging strategies are successful. For additional information regarding our
financial instrument portfolios, see Item 7A of this report.
37
Octane Enhancement. Our equity earnings from BEF were $8.6 million for
2002 compared to $5.7 million for 2001. The improvement is primarily due to
increased MTBE production attributable to less maintenance downtime. On a gross
basis, BEF's MTBE production increased to 15 MBPD during 2002 compared to 14
MBPD during 2001.
Other. Gross operating margin from this segment decreased $3.2 million
year-to-year primarily due to an increase in information technology-related
facility support costs.
Selling, general and administrative expenses. These expenses increased
to $42.9 million during 2002 compared to $30.3 million during 2001. The increase
is primarily due to the additional staff and resources needed to support our
expansion activities resulting from acquisitions and other business development.
The majority of the additional costs for 2002 are attributable to amounts we
paid Williams for transition services associated with our acquisition of
Mid-America and Seminole.
Interest expense. Interest expense increased to $101.6 million during
2002 compared to $52.5 million during 2001. The increase is primarily due to
debt obligations we incurred as a result of business acquisitions and
investments in inventory. Of the $49.1 million increase in interest expense,
$21.4 million is attributable to the debt incurred to finance the Mid-America
and Seminole acquisitions. In addition, income from our interest rate hedging
activities (which is recorded as a reduction in interest expense) decreased
$12.3 million in 2002 when compared to 2001. The change in interest rate hedging
results is primarily due to certain elections by counterparties during 2001 to
terminate interest rate hedging agreements.
Year ended December 31, 2001 compared to year ended December 31, 2000
The following table shows our consolidated revenues, costs and
expenses, and operating income for the years ended December 31, 2001 and 2000
(dollars in thousands):
FOR YEAR ENDED DECEMBER 31,
----------------------------------------
2001 2000
----------------------------------------
Revenues $ 3,154,369 $ 3,049,020
Costs and expenses $ 2,892,039 $ 2,829,405
Operating income $ 287,688 $ 243,734
Revenues for 2001 increased $105.3 million over those of 2000. The
increase in revenue is primarily due to the acquisition of Acadian Gas from
Shell during 2001. The higher pipeline revenues were offset by a decline in NGL
product prices during 2001 relative to 2000 which lowered revenues from our NGL
marketing activities. Costs and expenses during 2001 were $62.6 million higher
than 2000 primarily due to the addition of costs and expenses of acquired
businesses offset by decreased NGL product purchase prices and improved results
from commodity hedging activities. Operating income increased $44.0 million
year-to-year primarily as a result of such changes.
Pipelines. Gross operating margin from our Pipelines segment was $96.6
million for 2001 compared to $56.1 million for 2000. On an energy equivalent
basis, net pipeline throughput volume for 2001 was 809 MBPD compared to 367 MBPD
during 2000. Of the $40.5 million increase in segment gross operating margin,
$20.0 million is due to the addition of earnings from natural gas pipelines we
acquired during 2001. Specifically, we acquired Acadian Gas from Shell in April
2001 and equity ownership interests in four Gulf of Mexico systems from El Paso
in January 2001. The natural gas throughput on these systems accounted for 355
MBPD of the 442 MBPD increase in segment volumes, on an energy equivalent basis.
An additional $12.2 million of the year-to-year increase in segment
gross operating margin is attributable to our Lou-Tex NGL pipeline, which was
completed and began operations during the fourth quarter of 2000. Gross
operating margin from our Houston Ship Channel NGL import facility and related
HSC pipeline increased $5.2 million in 2001 due to a rise in commercial butane
imports related to isobutane production. The increase in NGL
38
import activity and related pipeline movements accounted for 63 MBPD of the
year-to-year increase in segment volumes.
Fractionation. Gross operating margin from our Fractionation segment
was $118.6 million for 2001 compared to $129.4 million for 2000. Our propylene
fractionation volumes declined slightly in 2001 to 31 MBPD from 33 MBPD in 2000.
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 the third quarter of 2000. Our isomerization business posted an
$8.4 million increase in gross operating margin during 2001 when compared to
2000. Isomerization volumes increased to 80 MBPD during 2001 from 74 MBPD during
2000. The increase in isomerization earnings is primarily due to certain of our
isomerization fees being indexed to historical natural gas prices (which were
higher in 2001 relative to 2000). Lastly, gross operating margin from our NGL
fractionation business in 2001 declined $21.0 million from 2000 levels,
primarily as a result of lower in-kind fees at Norco. In-kind fee arrangements
expose us to commodity price risk in that our revenues are dependent upon NGL
market prices, which were generally lower in 2001 as compared to 2000. NGL
fractionation volumes decreased to 204 MBPD during 2001 from 213 MBPD during
2000. The year-to-year decrease in NGL fractionation volumes is primarily due to
lower mixed NGL extraction rates at regional gas plants during early 2001, which
in turn was caused by higher natural gas prices.
Processing. Gross operating margin from our Processing segment was
$155.0 million for 2001 compared to $122.2 million for 2000. Our equity NGL
production decreased 9 MBPD to 63 MBPD during 2001 versus 72 MBPD during 2000.
The decrease in our equity NGL production rate is primarily due to less
favorable gas processing economics during early 2001 caused by higher natural
gas prices. Segment gross operating margin for 2001 includes $101.3 million of
commodity hedging income, an increase of $74.5 million over such income in 2000.
The increase in our commodity hedging income mitigated or exceeded the loss in
value of our NGL production caused by commodity price movements during 2001. In
addition, our NGL marketing activities benefited from unusually strong demand
for propane and isobutane during early and mid-2001.
We are exposed to settlement risk (a form of credit risk) with the
counterparties of our financial instruments. On all transactions where we are
exposed to settlement risk, we analyze the counterparty's financial condition
prior to entering an agreement, establish credit limits and monitor 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 recorded a charge against 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.
Octane Enhancement. Our equity earnings from BEF were $5.7 million for
2001 compared to $10.4 million for 2000. The decrease in equity earnings is
primarily due to lower MTBE and by-product prices in 2001. On a gross basis,
BEF's MTBE production was 14 MBPD during 2001 and 2000.
Other. Gross operating margin from this segment decreased $1.5 million
year-to-year primarily due to an increase in information technology-related
facility support costs.
Selling, general and administrative expenses. These expenses increased
to $30.3 million during 2001 compared to $28.3 million during 2000. The increase
is primarily due to the additional staff and resources needed to support our
expansion activities resulting from acquisitions and other business development.
Interest expense. Interest expense increased to $52.5 million during
2001 compared to $33.3 million during 2000. The increase is primarily due to
debt obligations we incurred as a result of business acquisitions completed
during 2001. In addition, income from our interest rate hedging activities
(which is recorded as a reduction in interest expense) increased $3.2 million in
2001 when compared to 2000. The change in interest rate hedging results is
primarily due to certain elections by counterparties during 2001 and a general
decrease in interest rates.
39
General outlook for 2003
We expect our business to be affected by the following key trends and
events during 2003. Our expectations are based on assumptions made by us and
information currently available to us. To the extent our underlying assumptions
about or interpretations of available information prove to be incorrect, our
expectations may vary materially from actual results.
o As a result of abnormally high natural gas prices during the first
quarter of 2003, we anticipate that NGL extraction rates at natural
gas processing plants will be reduced. High natural gas prices may
result in the cost of energy consumed by our natural gas processing
facilities exceeding the market value of NGLs they extract. During
periods of unusually high natural gas prices, we discuss with
natural gas producers possible ways to limit the unfavorable impact
of these energy costs.
o The expected reduction in NGL extraction rates during the first
quarter of 2003 may also result in lower pipeline throughput rates
and NGL fractionation volumes.
o As a result of the lower NGL extraction rates noted above, the
demand for and price of certain NGL products increased. We expect
that gross operating margin for our Processing segment will benefit
from these market price increases as NGL inventories held by our NGL
marketing group are sold.
o The expansion of our Neptune gas processing facility (which began in
October 2002) is expected to be complete during the fourth quarter
of 2003. This expansion will increase Neptune's gross gas processing
capacity from 0.3 Bcf/d to 0.65 Bcf/d and will increase our NGL
production capacity by 25 MBPD.
o In late 2003, Starfish is scheduled to complete construction of a
41-mile Gulf of Mexico natural gas pipeline that will connect its
Stingray pipeline to new sources of deepwater Gulf of Mexico natural
gas production.
o In March 2003, we completed the purchase of the remaining 50%
ownership interests in EPIK from Idemitsu. As a result of this
acquisition, segment earnings from NGL export activities will
increase beginning in the first quarter of 2003 as we consolidate
100% of this operation.
o We expect a modest decline in demand for isomerization services
during 2003 as refiners reduce their MTBE production in advance of
California's ban on MTBE (of which isobutane is a feedstock) which
takes effect in January 2004. The decline in isobutane demand
attributable to MTBE production may be offset by increased demand
for isobutane in producing alkylate (which could act as a
replacement gasoline additive in place of MTBE).
o As a result of California's switch from using MTBE in its clean
fuels program to ethanol in January 2004, we expect that overall
demand for MTBE over the course of 2003 will be weaker than in prior
years. This development will probably lead to lower MTBE prices
which in turn will affect our equity earnings from BEF.
OUR LIQUIDITY AND CAPITAL RESOURCES
As noted at the beginning of Item 7 of this report, the following
represents a combined discussion of our liquidity and capital resources
requirements and those of the Operating Partnership. Within this section,
references to partnership equity pertains to limited partner interests issued by
us, whereas references to debt pertains to those obligations entered into by our
Operating Partnership.
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 our partners. We
expect to fund our short-term needs for such items as operating expenses and
sustaining capital expenditures 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 commercial bank credit facilities and the issuance of additional
partnership equity and public and private placement debt. We expect to fund cash
distributions to partners primarily with operating cash flows. Our debt service
requirements are expected to be funded by operating cash flows and/or
refinancing arrangements.
40
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 flow from operations is primarily based on earnings
from our business activities. As a result, 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, in the production of motor
gasoline and as fuel for residential, agricultural 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 Item
1 of this report.
As noted above, certain of our liquidity and capital resource
requirements are fulfilled by borrowings made under debt agreements and/or
proceeds from the issuance of additional partnership equity. At December 31,
2002, we had approximately $2.2 billion outstanding under various debt
agreements. On that date, total borrowing capacity under our commercial bank
credit facilities was $500 million of which $176 million of capacity was
available. For additional information regarding our debt, see "Our debt
obligations" on page 44.
In February 2001, we filed a universal shelf registration with the SEC
covering the issuance of an unspecified amount of partnership equity or public
debt obligations (separately or in combination). In October 2002, we sold 9.8
million Common Units under this shelf registration which generated net proceeds
to us of approximately $183.3 million before offering expenses. In January 2003,
we sold an additional 14.7 million Common Units under this shelf registration
which generated $258.9 million in net proceeds before offering expenses. We used
net proceeds before offering expenses from both equity issues to reduce debt
outstanding under our 364-Day Term Loan and for working capital purposes. Also,
in January and February 2003, we completed the issuance of $850 million of
private placement debt (Senior Notes C and D) that we expect to convert to
public debt. For additional information regarding the general use of proceeds
from the from Senior Notes C and D and the January 2003 equity offering, see our
footnote titled "Subsequent Events" in the Notes to Consolidated Financial
Statements under Item 8 of this annual report. In addition, please read the
section titled "Our debt obligations" within this "Our liquidity and capital
resources" discussion for information regarding our debt obligations.
In January 2003, we filed a new $1.5 billion universal shelf
registration statement with the SEC covering the issuance of an unallocated
amount of partnership equity or public debt obligations (separately or in
combination). In accordance with Rule 457(p) promulgated under the Securities
Act of 1933, as amended, the registration fee associated with the unsold portion
of the securities under the shelf registration statement filed in February 2001
was used to offset the registration fee due in connection with our $1.5 billion
universal shelf registration statement. As a result, at the time our $1.5
billion shelf registration statement is declared effective by the SEC, the
securities remaining under the shelf registration statement filed in February
2001 will be deemed deregistered.
We have the ability to issue an unlimited number of Common Units to
finance acquisitions and capital improvements if Adjusted Operating Surplus (as
defined within our partnership agreement) for each of the four fiscal quarters
immediately preceding the expenditure, on a pro forma basis, would have
increased as a result of such expenditure (i.e., would have been accretive on a
pro forma basis for each of the quarters in the test). For those acquisitions
and other transactions that do not qualify under the aforementioned pro forma
"accretive" test, we have 54,550,000 Units available for general partnership
purposes during the Subordination Period. The Subordination Period generally
extends until the first day of any quarter beginning after June 30, 2003 when
certain financial tests have been satisfied. After the Subordination Period
expires, we may prudently issue an unlimited number of Units for general
partnership purposes that do not meet the pro forma "accretive" test.
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.
41
The following discussions highlight significant year-to-year
comparisons in consolidated operating, investing and financing cash flows.
Year ended December 31, 2002 compared to year ended December 31, 2001
Operating cash flows. Cash flow from operating activities was an inflow
of $329.8 million during 2002 compared to $283.3 million during 2001. The
following table summarizes the major components of operating cash flows for 2002
and 2001 (dollars in thousands):
FOR YEAR ENDED DECEMBER 31,
----------------------------------
2002 2001
----------------------------------
Net income $ 95,500 $ 242,178
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities before changes in operating accounts:
Depreciation and amortization 94,925 51,903
Equity in income of unconsolidated affiliates (35,253) (25,358)
Distributions received from unconsolidated affiliates 57,662 45,054
Non-cash changes in fair market value of financial instruments 10,213 (5,697)
Other 14,059 12,391
----------------------------------
Cash flow from operating activities before changes in operating accounts $ 237,106 $ 320,471
Net effect of changes in operating accounts 92,655 (37,143)
----------------------------------
Operating activities cash flows $ 329,761 $ 283,328
==================================
As shown in the table above, cash flow before changes in operating
accounts was an inflow of $237.1 million during 2002 versus $320.5 million
during 2001. We believe that cash flow from operating activities before changes
in operating accounts is an important measure of our liquidity. We believe it
provides an indication of our ability to generate core cash flows from the
assets and investments we own or in which we have an interest. The $83.4 million
year-to-year decrease in this element of our cash flows is primarily due to net
hedging losses in 2002 versus net hedging income in 2001 offset by increased
distributions from unconsolidated affiliates and earnings from businesses we
acquired during 2002. The $43.0 million increase in depreciation and
amortization is primarily due to businesses we acquired during 2002. Changes in
operating accounts are generally the result of timing of cash receipts from
sales and cash payments for inventory, purchases and other expenses near the end
of each period. For additional information regarding changes in operating
accounts, please see our footnote titled "Supplemental Cash Flows Disclosure" in
the Notes to Consolidated Financial Statements under Item 8 of this annual
report.
Investing cash flows. During 2002, we used $1.7 billion in cash for
investing activities compared to $491.2 million during 2001. 2002 reflects $1.6
billion of business acquisitions including $1.2 billion paid to acquire
Mid-America and Seminole and $368.7 million paid to acquire Diamond-Koch's Mont
Belvieu, Texas propylene fractionation and NGL and petrochemical storage
businesses. 2001 includes $113.0 million paid to acquire equity interests in
four Gulf of Mexico natural gas pipelines from El Paso and $225.7 million paid
to acquire Acadian Gas from Shell. During 2002, our capital expenditures were
$72.1 million compared to $149.9 million during 2001. The majority of capital
expenditures made during both periods were for projects within our Pipelines
segment.
Financing cash flows. Our financing activities generated $1.3 billion
in cash inflows during 2002 compared to $279.5 million during 2001. Our net
borrowings were $1.3 billion in 2002 versus $449.7 million in 2001. The increase
in borrowings is primarily due to acquisitions, particularly the $1.2 billion
paid for Mid-America and Seminole and the $239.0 million for Diamond-Koch's
propylene fractionation business. The borrowing shown for 2001 reflects the
issuance of our Senior Notes B, which was primarily used to finance the
acquisition of Acadian Gas, Starfish, Neptune and Nemo.
Financing activities also reflect the net proceeds and related General
Partner contributions from our October 2002 issuance of 9.8 million new Common
Units. Net proceeds before offering expenses from the sale of the Common Units
were $183.3 million (from which offering expenses of approximately $0.8 million
were paid). This amount includes the General Partner's aggregate contribution to
us and our Operating Partnership of $3.6 million to maintain its combined 2%
general partner interest. Cash distributions to our partners increased $52.2
42
million year-to-year primarily due to increases in both the declared quarterly
distribution rates and the number of Units eligible for distributions. The
number of Units eligible for distributions was higher in 2002 due to the
conversion of 19.0 million of Shell's Special Units to an equal number of Common
Units in August 2002 and our issuance of the 9.8 million new Common Units in
October 2002. Debt issue costs increased $16.2 million year-to-year primarily
due to the $15.0 million in fees we paid to banks in July 2002 associated with
the short-term financing of the Mid-America and Seminole acquisitions.
Year ended December 31, 2001 compared to year ended December 31, 2000
Operating cash flows. Cash flow from operating activities was an inflow
of $283.3 million during 2001 compared to $360.9 million during 2000. The
following table summarizes the major components of operating cash flows for 2001
and 2000 (dollars in thousands):
FOR YEAR ENDED DECEMBER 31,
----------------------------------
2001 2000
----------------------------------
Net income $ 242,178 $ 220,506
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities before changes in operating accounts:
Depreciation and amortization 51,903 41,045
Equity in income of unconsolidated affiliates (25,358) (24,119)
Distributions received from unconsolidated affiliates 45,054 37,267
Non-cash changes in fair market value of financial instruments (5,697)
Other 12,391 15,060
----------------------------------
Cash flow from operating activities before changes in operating accounts $ 320,471 $ 289,759
Net effect of changes in operating accounts (37,143) 71,111
----------------------------------
Operating activities cash flows $ 283,328 $ 360,870
==================================
As shown in the table above, cash flow before changes in operating
accounts was an inflow of $320.5 million during 2001 versus $289.8 million
during 2000. The $30.7 million increase in this element of our operating cash
flows was primarily due to improved commodity hedging results offset by an
increase in interest expense. The $10.9 million increase in depreciation and
amortization is primarily due to businesses we acquired during 2001. Changes in
operating accounts are generally the result of timing of cash receipts from
sales and cash payments for inventory, purchases and other expenses near the end
of each period. For additional information regarding changes in operating
accounts, please see our footnote titled "Supplemental Cash Flows Disclosure" in
the Notes to Consolidated Financial Statements under Item 8 of this annual
report.
Investing cash flows. During 2001, we used $491.2 million in cash for
investing activities compared to $268.8 million during 2000. 2001 reflects the
$225.7 million paid to acquire Acadian Gas from Shell and $113.0 million paid to
acquire equity interests in four Gulf of Mexico natural gas pipelines from El
Paso. During 2001, our capital expenditures were $149.9 million compared to
$243.9 for 2000. The majority of capital expenditures made during both periods
were for projects within our Pipelines segment.
Financing cash flows. Our financing activities generated $279.5 million
of cash receipts in 2001 compared to cash payments of $36.9 million in 2000. Net
borrowings for 2001 reflect our issuance of Senior Notes B whereas 2000 includes
the issuance of Senior Notes A and the MBFC Loan and the associated repayments
on various commercial bank credit facilities. Cash distributions to our partners
increased $25.0 million year-to-year primarily due to increases in both the
declared quarterly distribution rates and the number of Units eligible for
distributions. When compared to 2000, the number of Units eligible for
distributions during 2001 increased due to the conversion of 10.0 million of
Shell's Special Units to an equal number of Common Units in August 2001.
43
Our debt obligations
Our debt consisted of the following at (dollars in thousands):
DECEMBER 31,
----------------------------------
2002 2001
----------------------------------
Borrowings under:
364-Day Term Loan, variable rate, due July 2003 $ 1,022,000
364-Day Revolving Credit facility, variable rate,
due November 2004 99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005 225,000
Senior Notes A, 8.25% fixed rate, due March 2005 $ 350,000 350,000
Senior Notes B, 7.50% fixed rate, due February 2011 450,000 450,000
MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
Seminole Notes, 6.67% fixed rate, $15 million due
each December, 2002 through 2005 45,000
----------------------------------
Total principal amount 2,245,000 854,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 1,774 1,653
Less unamortized discount on:
Senior Notes A (81) (117)
Senior Notes B (230) (258)
Less current maturities of debt (15,000) -
----------------------------------
Long-term debt $ 2,231,463 $ 855,278
==================================
The table above does not reflect the issuance of our $350 million
principal amount Senior Notes C in January 2003 and $500 million principal
amount Senior Notes D in February 2003 nor does it reflect the repayment of debt
using proceeds from our January 2003 equity offering. We used a combination of
proceeds from the issuance of Senior Notes C and D and the January 2003 equity
offering to completely repay the 364-Day Term Loan by the end of February 2003
(see the section titled "General description of debt--364-Day Term Loan" within
this "Our debt obligations" discussion for additional information regarding the
use of proceeds to extinguish this debt). In addition, also read the section
titled "New debt obligations issued during first quarter of 2003" within this
"Our debt obligations" discussion for information regarding our Senior Notes C
and D.
As to the assets of our subsidiary, Seminole Pipeline Company, our $2.2
billion in senior indebtedness at December 31, 2002 is structurally subordinated
and ranks junior in right of payment to the $45 million of indebtedness of
Seminole Pipeline Company. In accordance with SFAS No. 6, "Classification of
Short-Term Obligations Expected to Be Refinanced", long-term and current
maturities of debt at December 31, 2002 reflect the classification of such debt
obligations at March 7, 2003.
Letters of credit. At December 31, 2002, we had a total of $75 million
of standby letters of credit capacity under our Multi-Year Revolving Credit
facility, of which $2.4 million was outstanding.
Parent-Subsidiary guarantor relationships. Enterprise Products Partners
L.P. (the "MLP", on a stand-alone basis) acts as guarantor of certain of the
Operating Partnership's debt obligations. These parent-subsidiary guaranty
provisions exist under all of our debt obligations with the exception of the
Seminole Notes. The Seminole Notes are unsecured obligations solely of Seminole
Pipeline Company. If the Operating Partnership were to default on any guaranteed
debt obligation, the MLP would be responsible for full payment of that
obligation.
44
General description of debt
The following is a summary of the significant aspects of our debt
obligations at December 31, 2002.
364-Day Term Loan. The Operating Partnership entered into a $1.2
billion senior unsecured 364-day term loan to fund the Mid-America and Seminole
acquisitions in July 2002. We applied proceeds of $178.8 million from our
October 2002 equity offering to partially repay this loan. We used $252.8
million of the $258.9 million in proceeds from the January 2003 equity offering,
$347.0 million of the $347.7 million in proceeds from our issuance of Senior
Notes C and $421.4 million in proceeds from our issuance of Senior Notes D to
completely repay the 364-Day Term Loan by February 2003. Base variable interest
rates under this facility generally bore interest at either (1) the greater of
(a) the Prime Rate or (b) the Federal Funds Effective Rate plus one-half percent
or (2) a Eurodollar rate. Whichever base interest rate we selected, the rate was
increased by an appropriate applicable margin (as defined within the loan
agreement). During 2002, the weighted-average interest rate charged was 3.1%.
This facility contained various covenants similar to those of our revolving
credit facilities. We were in compliance with these covenants at December 31,
2002.
364-Day Revolving Credit facility. In November 2000, we entered in a
364-Day revolving credit agreement. Currently, the stand-alone borrowing
capacity under this credit facility is $230 million with the maturity date for
any amount outstanding being November 2003. We have the option to convert any
revolving credit balance outstanding at maturity to a one-year term loan (due
November 2004) in accordance with the terms of the credit agreement. This credit
facility is guaranteed by the MLP through an unsecured guarantee. In addition,
our borrowings under this bank credit facility are unsecured general obligations
and are non-recourse to the General Partner. We applied $60.0 million in
proceeds from our February 2003 issuance of Senior Notes D to reduce the balance
outstanding under this facility during 2003.
Variable interest rates charged under this facility generally bear
interest at either (1) the greater of (a) the Prime Rate or (b) the Federal
Funds Effective Rate plus one-half percent or (2) a Eurodollar rate plus an
applicable margin or (3) a Competitive Bid Rate. We elect the basis of the
interest rate at the time of each borrowing. During 2002, the weighted-average
interest rate charged for borrowings under this facility was 2.5%.
The 364-Day Revolving Credit facility contains various covenants
related to our ability to incur certain indebtedness; grant certain liens; enter
into certain merger or consolidation transactions; and make certain investments.
The loan agreement also requires us to satisfy certain financial covenants at
the end of each quarter. As defined within the agreement, we must maintain a
specified level of consolidated net worth and certain financial ratios. We were
in compliance with these covenants at December 31, 2002.
Multi-Year Revolving Credit facility. In conjunction with the 364-Day
Revolving Credit facility, we entered into a five-year revolving credit facility
(the "Multi-Year Revolving Credit facility") that includes a sublimit capacity
of $75 million for standby letters of credit. Currently, the stand-alone
borrowing capacity under this credit facility is $270 million. This credit
facility is guaranteed by the MLP through an unsecured guarantee. In addition,
our borrowings under this bank credit facility are unsecured general obligations
and are non-recourse to the General Partner. The interest rates charged under
this facility are determined in the same manner as that described under our
364-Day Revolving Credit facility. During 2002, the weighted-average interest
rate charged for borrowings under this facility was 2.4%.
This facility contains various covenants similar to those of our
364-Day Revolving Credit facility (please refer to our discussion regarding
restrictive covenants of the "364-Day Revolving Credit facility" within this
"General description of debt" section). We were in compliance with these
covenants at December 31, 2002.
Senior Notes A and B. These fixed-rate notes are an unsecured
obligation of the Operating Partnership and rank equally with its existing and
future unsecured and unsubordinated indebtedness and senior to any future
subordinated indebtedness. Both notes are guaranteed by the MLP through an
unsecured and unsubordinated guarantee and are non-recourse to the General
Partner. These notes were issued under an indenture containing certain covenants
and are subject to a make-whole redemption right. 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 covenants at
December 31, 2002.
45
MBFC Loan. In connection with the construction of our Pascagoula,
Mississippi natural gas processing plant, we entered into a ten-year fixed-rate
loan with the Mississippi Business Finance Corporation ("MBFC"). This loan is
subject to a make-whole redemption right and is guaranteed by MLP through an
unsecured and unsubordinated guarantee. The indenture agreement for this loan
contains an acceleration clause whereby the outstanding principal and interest
on the loan may become due and payable within 120 days 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 within the loan agreement) may, and if requested to do so by holders
of at least 25% of the principal amount of the underlying bonds, shall
accelerate the maturity of the MBFC Loan, whereby the principal and all accrued
and unpaid interest would become immediately due and payable. If such an event
occurred, we would have the option of (1) to redeem the MBFC Loan or (2) to
provide an alternate credit agreement to support our obligation under the MBFC
Loan. We would have 120 days to exercise these options upon receiving notice of
the decline in our credit ratings.
The MBFC Loan agreement contains certain covenants including the
maintenance of appropriate levels of insurance on the Pascagoula facility and
restrictions regarding mergers. We were in compliance with these covenants at
December 31, 2002.
Seminole Notes. As a result of our acquisition of 78.4% of Seminole in
July 2002, we are required to consolidate its debt with our other debt
obligations. At December 31, 2002, Seminole had $45 million in fixed-rate senior
unsecured notes, of which $15 million is due annually each December through
December 2005. The Seminole Notes contain various covenants, such as minimum net
worth requirements and those restricting Seminole's ability to borrow additional
funds. Seminole was in compliance with these covenants at December 31, 2002.
New debt obligations issued during first quarter of 2003
January 2003 Senior Notes Offering. In January 2003, we issued $350
million in principal amount of 6.375% Senior Notes due 2013 ("Senior Notes C"),
from which we received net proceeds before offering expenses of approximately
$347.7 million. We used the proceeds from this offering to repay a portion of
the indebtedness outstanding under the 364-Day Term Loan that we incurred to
finance the Mid-America and Seminole acquisitions.
February 2003 Senior Notes Offering. In February 2003, we issued $500
million in principal amount of 6.875% Senior Notes due 2033 ("Senior Notes D"),
from which we received net proceeds before offering expenses of approximately
$489.8 million. We used $421.4 million from this offering to repay the remaining
principal balance outstanding under the 364-Day Term Loan. In addition, we
applied $60.0 million of the proceeds to reduce the balance outstanding under
the 364-Day Revolving Credit facility. The remaining proceeds were used for
working capital purposes.
Credit ratings
Our current investment grade credit ratings are Baa2 by Moody's
Investor Service and BBB by Standard and Poors. Upon our acquisitions of the
Mid-America and Seminole pipelines, which were financed by the $1.2 billion
364-Day Term Loan, both agencies maintained our ratings; however, each placed us
on negative outlook pending the issuance of an appropriate amount of equity. The
agencies have responded positively to our recent equity and debt offerings. We
believe that the maintenance of an investment grade credit rating is important
in managing our liquidity and capital resource requirements. We maintain regular
communications with these ratings agencies which independently judge our
creditworthiness based on a variety of quantitative and qualitative factors.
Cash requirements for future growth
Acquisitions. 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 energy industry in which we operate. We
forecast that this trend will continue, and expect independent oil and natural
gas companies to consider similar divestures. 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 positioned to continue
46
to grow through acquisitions that will expand its platform of assets and through
internal growth projects. Our goal is to invest $500 million annually in such
opportunities to the extent we believe such investments will be accretive to our
Unitholders.
We expect that the funds needed to achieve this goal will be obtained
through a combination of operating cash flows; public and private placement
debt; and the issuance of partnership equity. Our $1.7 billion in business
acquisitions and internal growth projects we completed during 2002 were
initially funded with approximately $1.5 billion of debt. This will translate
into increased debt service costs in the future. To the extent proceeds from
future partnership equity offerings are used to reduce the principal amount of
debt, our interest expense will be reduced. To the extent we refinance our
existing debt with new debt, our interest expense will generally be affected by
differences in interest rates charged on the existing debt versus the new debt
and by any fees associated with the new debt.
Distributions. Another stated goal of management is to increase the
distribution rate to our partners by at least 10% annually. At the end of 2002,
the declared annual rate was $1.38 per Common Unit, which was 10.4% higher than
the rate in effect at the end of 2001. An increase in our distribution rate will
translate into additional cash payments to existing Unitholders. In addition, an
increase in the number of Units eligible for cash distributions will result in
higher payments. We issued 14.7 million new Common Units in January 2003 and
expect to convert Shell's remaining 10.0 million Special Units to
distribution-bearing Common Units in August 2003. Both of these transactions
will have the effect of increasing cash distributions over those paid during
2002. On an annualized basis assuming a distribution rate of $1.38 per Common
Unit, our distributions to partners would increase by $34.1 million as a result
of these additional 24.7 million Common Units. We believe that all cash
distributions will be paid out of operating cash flows over the long-term;
however, from time to time, we may temporarily borrow under our debt agreements
for the purpose of paying cash distributions until the full impact of our
operations are realized.
Capital spending. At December 31, 2002, we had $7.8 million in
estimated outstanding purchase commitments attributable to capital projects. Of
this amount, $1.5 million is related to the construction of assets that will be
recorded as property, plant and equipment and $6.3 million is associated with
our share of capital projects of our unconsolidated affiliates which will be
recorded as additional investments in unconsolidated affiliates.
During 2003, we expect capital spending on internal growth projects to
approximate $110.2 million, of which $22.8 million is forecasted for various
projects within our Pipelines segment; $38.6 million for the expansion of our
Norco NGL fractionator and $40.0 million for the expansion of our Neptune gas
processing facility. Our unconsolidated affiliates forecast a combined $63.1
million in capital expenditures during 2003, the majority of which relate to
expansion projects on our Gulf of Mexico natural gas pipeline systems. Our share
of these forecasted capital expenditures is estimated at $26.2 million.
At our formation, EPCO contributed various equipment leases to us for
which they have retained the liability for the lease payments (the "retained
leases"). These leases relate to an isomerization unit, a DIB tower, two
cogeneration units and approximately 100 railcars. EPCO has assigned to us the
purchase options associated with these leases. If we decide to exercise these
purchase options (which are at fair market value), up to $26.0 million is
expected to be payable in 2004, $3.4 million in 2008 and $3.1 million in 2016.
As a result of new regulations imposing stricter air emissions
requirements on petrochemical production and similar facilities in the
Houston-Galveston area, we are required to redesign and modify certain
components of our Mont Belvieu facility to comply with these new Clean Air Act
requirements. Based upon these newly approved regulations, we estimate capital
expenditures of $25 to $30 million (in the aggregate) will be required to modify
our Mont Belvieu facilities. Through December 31, 2002, we spent $0.2 million
related to this project. We forecast to spend between two and three million
dollars for such modifications during 2003. The remaining amount is expected to
be spent between 2004 and 2007. For additional information regarding these new
regulations, see "Business and Properties--Regulation and Environmental
Matters--General Impact of the Clean Air Act on our operations" under Items 1
and 2 of this annual report.
47
SUMMARY OF MATERIAL CONTRACTUAL OBLIGATIONS
The following table summarizes our material contractual obligations at
December 31, 2002 (dollars in thousands, volumes as stated):
2004 2006
THROUGH THROUGH AFTER
CONTRACTUAL OBLIGATIONS TOTAL 2003 2005 2007 2007
- --------------------------------------------------------------------------------------------------------------------
Scheduled principal payments to be made
under debt obligations $ 2,245,000 $ 1,037,000 $ 704,000 $ 504,000
Potential payments under
letter of credit agreements $ 2,400 $ 2,400
Payments due under operating leases $ 17,793 $ 7,148 $ 5,840 $ 1,182 $ 3,623
Capital expenditure commitments $ 7,797 $ 7,797
Long-term purchase commitments:
(Expressed in terms of minimum
volumes under contract per period:)
NGLs (MBbls) 60,848 15,986 22,752 11,310 10,800
Petrochemicals (MBbls) 82,096 25,428 42,144 14,524
Natural gas (BBtus) 190,282 23,053 39,084 36,895 91,250
Our scheduled principal payments reflect consolidated amounts due under
public and private placement debt obligations. Total principal amount
outstanding under debt obligations as shown in the table above does not reflect
the issuance of our $350 million Senior Notes C in January 2003 (due 2013) and
$500 million Senior Notes D in February 2003 (due 2033) nor does it reflect the
complete repayment of the 364-Day Term Loan in February 2003. Our potential
payments under letter of credit agreements are associated with our purchase of
hydrocarbon imports and the guarantee of our share of Evangeline's debt service
reserve requirements. For additional information regarding our debt obligations,
please see "Our debt obligations" on page 44 of this annual report.
We lease certain equipment and processing facilities under
noncancelable and cancelable operating leases. The payments due under these
leases (as shown above) represent our minimum future rental payments. The
operating lease commitments shown above exclude the non-cash related party
expense associated with various equipment leases contributed to us by EPCO at
our formation for which EPCO has retained the liability (the "retained leases").
We routinely invest in capital projects of our own and in those of our
unconsolidated affiliates. The amount shown above reflects the committed
expenditures under these projects at December 31, 2002. Lastly, we have
long-term purchase commitments for NGLs, petrochemicals and natural gas with
several suppliers. In general, the purchase prices contained within these supply
contracts approximate market prices at the time we take delivery of the volumes.
RECENT ACCOUNTING DEVELOPMENTS
We adopted SFAS No. 142, "Goodwill and Other Intangible Assets", on
January 1, 2002. This standard establishes accounting standards for all goodwill
and other intangible assets recognized in our consolidated balance sheet. In
addition, we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" on January 1, 2002. This statement addresses financial
accounting and reporting for the impairment and/or disposal of long-lived
assets. For information regarding our goodwill, intangible assets and long-lived
assets, please see the Notes to Consolidated Financial Statements included under
Item 8 of this annual report.
We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations,"
on January 1, 2003. This statement establishes accounting standards for the
recognition and measurement of a liability for an asset retirement obligation
("ARO") and the associated asset retirement cost. An ARO exists when a company
determines that it
48
has a clearly defined legal obligation upon retirement of a long-lived asset or
any component part thereof and that the legal obligation will lead to the future
payment of funds to a third party upon retirement of the asset. In general,
legal obligations underlying AROs result from enacted laws and regulations or
from contractual provisions related to long-lived assets. AROs can also arise
through the normal course of operating a long-lived fixed asset.
An ARO liability will be recorded on the balance sheet if a reasonable
estimate of fair value of the obligation can be made. Our estimate of fair value
for each ARO is primarily dependent upon a clearly defined plan of retirement
(dates, methods, etc.) and costs associated with the retirement activity. If a
reasonable estimate cannot be made (i.e., no current or required plans for
retirement of the asset, etc.), footnote disclosure is required but the ARO is
not recorded until a reasonable estimate can be made. Any earnings impact
resulting from the recognition of an ARO upon adoption of SFAS No. 143 should be
reflected as the cumulative effect of a change in accounting principle.
Upon adoption of SFAS No. 143, we reviewed our long-lived assets for
ARO's by segment. We identified, but have not recognized, ARO liabilities in
several operational areas. These include ARO liabilities related to easements
over property not currently owned by us. Our rights to the easements are
renewable and only require retirement action upon nonrenewal of the easement
agreements. We currently plan to renew all such easement agreements and use
these properties indefinitely. Therefore, the ARO liability is not estimable for
such easements. If we decide not to renew these agreements, an ARO liability
would be recorded at that time.
ARO liabilities related to statutory regulatory requirements for
abandonment or retirement of certain currently operated facilities were also
identified. We currently have no intention or legal obligation to abandon or
retire such facilities. An ARO liability would be recorded if future abandonment
or retirement occurred.
Certain Gulf of Mexico natural gas pipelines, in which we have an
equity interest, have identified ARO's relating to regulatory requirements.
There is no current intention to abandon or retire these pipelines. If these
pipelines were abandoned or retired, an ARO liability would then be disclosed.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." This standard requires companies
to recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to exit or disposal plan.
Examples of costs covered by the standard include lease termination costs and
certain employee severance costs that are associated with a restructuring,
discontinued operations, plant closing, or other exit or disposal activity.
Previous accounting guidance was provided by EITF Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146
replaces Issue 94-3. SFAS No. 146 is to be applied prospectively to exit or
disposal activities initiated after December 31, 2002. We adopted this statement
on January 1, 2003 and determined that it had no material impact on our
financial statements.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements from Guarantees, Including Indirect
Guarantees of Indebtedness of Others". This interpretation of SFAS No. 5, 57 and
107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures
to be made by a guarantor in its interim and annual financial statements about
its obligations under certain guarantees that it has issued. It also clarifies
that a guarantor is required to recognize, at the inception of a guarantee, a
liability for the fair value of the obligation undertaken in issuing the
guarantee. The initial recognition and measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements in this
interpretation are applicable for financial statements of interim or annual
periods after December 15, 2002. See "Our debt obligations" on page 44 for the
disclosure of Parent-Subsidiary guarantor relationships.
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation-Transition and Disclosure," which provides alternative
methods of transition from a voluntary change to the fair value based method of
accounting for stock-based employee compensation. In addition, SFAS No. 148
amends the disclosure requirements of SFAS No. 123 in both annual and interim
financial statements. SFAS No. 148 is effective for financial statements for
fiscal years ending after December 15, 2002, and financial reports containing
condensed financial statements for interim periods beginning after December 15,
2002. EPCO has stock-based
49
employee compensation plans for which we have a funding commitment for certain
employees. We do not believe that the adoption of this statement will have a
material effect on our financial statements.
OUR CRITICAL 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, methods employed to measure the fair value of goodwill, revenue
recognition policies and mark-to-market accounting procedures. The following
describes the estimation risk in each of these significant financial statement
items:
o 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 depreciation 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 or 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,
2002 and 2001, the net book value of our property, plant and
equipment was $2.8 billion and $1.3 billion, respectively.
o Intangible assets. The specific, identifiable intangible assets of a
business enterprise depend largely upon the nature of its
operations. Potential intangible assets include intellectual
property such as technology, patents, trademarks and trade names,
customer contracts and relationships, and non-compete agreements, as
well as other intangible assets. The approach to the valuation of
each intangible asset will vary depending upon the nature of the
asset, the business in which it is utilized, and the economic
returns it is generating or is expected to generate.
Our recorded intangible assets primarily include the estimated value
assigned to certain contract-based assets representing the rights we
own arising from contractual agreements. A contract-based intangible
with a finite useful life is amortized over its estimated useful
life, which is the period over which the asset is expected to
contribute directly or indirectly to the future cash flows of the
entity. It is based on an analysis of all pertinent factors
including (a) the expected use of the asset by the entity, (b) the
expected useful life of related assets (i.e., fractionation
facility, storage well, etc.), (c) any legal, regulatory or
contractual provisions, including renewal or extension periods that
would not cause substantial costs or modifications to existing
agreements, (d) the effects of obsolescence, demand, competition,
and other economic factors and (e) the level of maintenance required
to obtain the expected future cash flows.
At December 31, 2002, our significant intangible assets consisted of
the following (along with unamortized balances of each group at that
date):
o the Shell natural gas processing agreement that we acquired
as part of the TNGL acquisition in August 1999 ($183.2
million);
o certain storage and propylene fractionation contracts we
acquired in connection with the Diamond-Koch acquisitions in
January and February 2002 ($59.5 million); and
o certain natural gas processing and NGL fractionation
contracts we acquired in connection with the Toca-Western
acquisition in June 2002 ($30.3 million).
50
The Shell natural gas processing agreement is being amortized on a
straight-line basis over the remainder of its initial 20-year
contract term. The propylene fractionation and storage contracts
acquired from Diamond-Koch are being amortized on a straight-line
basis over the economic life of the assets to which they relate,
which is currently estimated at 35 years. The Toca-Western natural
gas processing contracts are being amortized on a straight-line
basis over the expected 20-year remaining life of the natural gas
supplies supporting these contracts. The Toca-Western NGL
fractionation contracts are being amortized on a straight-line basis
over the expected 20-year remaining life of the assets to which they
relate.
If the underlying assumption(s) governing the amortization of an
intangible asset were later determined to have significantly changed
(either favorably or unfavorably), we then might need to adjust the
amortization period of such asset to reflect any new estimate of its
useful life. Such a change would increase or decrease the annual
amortization charge associated with the asset at that time. During
2002, we did not find it necessary to adjust the estimated useful
life or amortization period of any of our intangible assets.
Should any of the underlying assumptions indicate that the value of
the intangible asset might be impaired, we then might need to reduce
its carrying value and subsequent useful life. Any such write-down
of the value and unfavorable change in the useful life (i.e.,
amortization period) of an intangible asset would increase operating
costs and expenses at that time. During 2002, we did not recognize
any impairment losses related to our intangible assets.
o Goodwill. At December 31, 2002, the recorded value of goodwill was
$81.5 million. Our goodwill is attributable to the excess of the
purchase price over the fair value of assets acquired and is
primarily comprised of the $73.6 million associated with the
purchase of propylene fractionation assets from Diamond-Koch in
February 2002. Since our adoption of SFAS No. 142 on January 1,
2002, our goodwill amounts are no longer amortized. Instead,
goodwill is tested at a reporting unit level annually, and more
frequently, if certain circumstances indicate it is more likely than
not that the fair value of goodwill is below its carrying amount. If
such indicators are present (i.e., loss of a significant customer,
economic obsolescence of plant assets, etc.), the fair value of the
reporting unit, including its related goodwill, is calculated and
compared to its combined book value. Currently, all of our goodwill
is recorded as part of the Fractionation operating segment (based on
the assets to which the goodwill relates).
If the fair value of the reporting unit exceeds its book value,
goodwill is not considered impaired and no adjustment to earnings
would be required. Should the fair value of the reporting unit
(including its goodwill) be less than its book value, a charge to
earnings would be recorded to adjust goodwill to its implied fair
value.
o 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 it 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 routine nature of these estimates and the stability of our
operations. Of the contracts that we enter into with customers, the
majority fall within five main categories as described below:
o 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);
o Product sales contracts where we sell products to customers
at market-related prices for cash;
o Storage agreements where we store volumes or reserve storage
capacity for customers for a cash fee; and
o 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.
51
A number of tolling arrangements are utilized in our Fractionation
and Pipeline segments. Examples include NGL fractionation,
isomerization and pipeline transportation agreements. Typically, we
recognize revenue 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. At certain of our NGL
fractionation facilities, an in-kind tolling arrangement is
utilized. An in-kind processing contract allows us to retain a
contractually-determined percentage of NGL products fractionated for
our customer in lieu of collecting a cash tolling fee per gallon.
Fractionation revenue is recognized and recorded on a monthly basis
for transfers of "in-kind" retained NGL products to the NGL working
inventory maintained within our Processing segment where it is then
held for sale. Transfer pricing for these retained NGLs is based
upon monthly market posted prices for such products. This
intersegment revenue and offsetting cost to the Processing segment
is eliminated in our reporting of consolidated revenues and
expenses.
Our Processing segment activities employ tolling and product sales
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 the natural gas processing contract stipulates that we
retain a percentage of the extracted NGLs as payment for our
services, revenue is recognized and recorded when the extracted NGLs
are delivered out of our inventory and sold to customers on sales
contracts. Our NGL marketing activities within this segment also use
product sales contracts to sell and deliver out of inventory the
NGLs transferred to it as a result of the Fractionation segment's
in-kind arrangements and those it purchases for cash in the open
market. These NGL sales contracts may include forward product sales
contracts from time-to-time. Revenues from NGL sales contracts are
recognized and recorded upon the delivery of the NGL products
specified in each individual contract. In addition to the Processing
segment, product sales contracts are utilized in the Fractionation
segment to record revenues from the sale of petrochemical products
and in the Pipelines segment to record revenues from the sale of
natural gas. Pricing terms in our product sales contracts are based
upon market-related prices for such products and can include pricing
differentials due to factors such as differing delivery locations.
o Fair value accounting for commodity 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 short-term, highly liquid 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. As of December 31, 2002,
none of our commodity 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 may cause our non-cash earnings to fluctuate based 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.
For the year ended December 31, 2002, we recognized losses from our
commodity hedging activities of $51.3 million. Of this loss, $5.6
million is attributable to the negative change in market value of
the commodity hedging portfolio since December 31, 2001 using the
mark-to-market method of accounting for our financial instruments.
The fair value of our commodity financial instrument portfolio at
December 31, 2002 was a payable of $26 thousand, based upon quoted
market prices. At that date, we had a limited number of open
positions that extend through December 2003. 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 the Processing segment discussion
under "Our results of operations" within this Item 7 and also read
Item 7A of this annual report.
Additional information regarding our financial statements and those of
the Operating Partnership can be found in the Notes to Consolidated Financial
Statements of each entity included elsewhere in this Form 10-K.
52
RELATED PARTY 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 D. 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 our General Partner is to act as our managing
partner. Collectively, EPCO and its affiliates (which includes the 1998 Trust,
2000 Trust and Dan L. Duncan) owned 61.4% of our limited partnership interests
and 70.0% of our General Partner at December 31, 2002.
We have no employees. All of our management, administrative and
operating functions are performed by employees of EPCO pursuant to the EPCO
Agreement (see Item 13). We reimburse EPCO for the costs of its employees who
perform operating functions for us. In addition, we reimburse EPCO for the costs
of certain of employees who manage our business and affairs.
EPCO is also the operator of certain facilities we own or have an
equity interest in. We have also entered into an agreement with EPCO to provide
trucking services to us for the loading and transportation of products. Lastly,
in the normal course of business, we buy from and sell NGL products to EPCO's
Canadian affiliate.
During 2002, our related party revenues from EPCO were $3.6 million and
our related party expenses with EPCO were $127.4 million. For additional
information regarding our relationship with EPCO, see Item 13 of this annual
report.
Relationship with Shell
We have an extensive and ongoing commercial relationship with Shell as
a partner, customer and vendor. Shell currently owns approximately 20.5% of our
limited partnership interests and 30.0% of our General Partner. Currently, three
members of the Board of Directors of the General Partner (J.A. Berget, J.R.
Eagan and A.Y. Noojin, III) are employees of Shell.
Shell and its affiliates are the Company's single largest customer.
During 2002, they accounted for 7.8% of our consolidated revenues. Our revenues
from Shell reflect the sale of NGL and petrochemical products to them and the
fees we charge them for pipeline transportation and NGL fractionation services.
Our operating costs and expenses with Shell primarily reflect the payment of
energy-related expenses related to the Shell natural gas processing agreement
(see the "Processing" segment discussion under Item 1 of this annual report) and
the purchase of NGL products from them. During 2002, our related party revenues
from Shell were $282.8 million and our related party expenses with Shell were
$531.7 million.
We have completed a number of business acquisitions and asset purchases
involving Shell since 1999. Among these transactions were:
o the acquisition of TNGL's natural gas processing and related
businesses in 1999 for $528.8 million (this purchase price includes
both the $166 million in cash we paid to Shell and the value of the
three issues of Special Units granted to Shell in connection with
this acquisition);
o the purchase of the Lou-Tex Propylene Pipeline System for $100
million in 2000; and,
o the acquisition of Acadian Gas in 2001 for $243.7 million.
Shell is also a partner with us in the Gulf of Mexico natural gas pipelines we
acquired from El Paso in 2001. We also lease from Shell its 45.4% interest in
our Splitter I propylene fractionation facility.
53
OTHER ITEMS
Uncertainties regarding our investment in facilities that produce MTBE
We have a 33.3% ownership interest in BEF, which owns a facility
currently producing MTBE. At December 31, 2002, the carrying value of our
investment in BEF was $54.9 million. Our equity earnings from BEF (which are
recorded under our Octane Enhancement segment) were $8.5 million, $5.7 million
and $10.4 million during 2002, 2001 and 2000, respectively. 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. BEF has not been named in any MTBE legal action to date. For additional
information regarding the impact of environmental regulation on BEF, see
"Business and Properties--Regulation and Environmental Matters--Impact of the
Clean Air Act's oxygenated fuels programs on our BEF investment" under Item 1 of
this annual report.
During 2000, the city of Santa Monica brought suit against seven major
oil companies and eleven other manufacturers, suppliers, refiners and pipeline
operators alleging the defendants had tainted much of the city's drinking water
supply with MTBE. In mid-July 2002, the city settled with two of the major oil
companies. Under the terms of this settlement, the two defendants agreed to pay
to design, build and operate a facility to treat the city's water (at a cost of
approximately $200 million) and to pay $30 million in other damages. The court
agencies involved in this case are reviewing this settlement. The city is still
pursuing legal action against the remaining defendants.
In April 2002, a jury in California found three energy companies liable
for polluting Lake Tahoe's drinking water with MTBE. While this decision sets no
legal precedent, this was the first time that a jury has defined gasoline
containing MTBE to be a "defective product". In August 2002, two of the
defendants were ordered to pay $28 million to a Lake Tahoe-area utility
district. The third defendant settled out of court for $4 million in July 2002.
In light of these developments, we and the other two owners of BEF are
actively compiling a contingency plan for the BEF facility should MTBE be
banned. We are currently evaluating a possible conversion of the facility from
MTBE production to alkylate production. In addition to MTBE's value in reducing
air pollution, it is a significant source of octane in the U.S. motor gasoline
pool. Octane is a critical component of motor gasoline. Therefore, 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 gasoline
and that alkylate would be an economic and effective substitute. We are
currently conducting a detailed engineering study that is expected to be
completed by the end of 2003, at which time we expect a more definitive
conversion cost estimate will be available. The cost to convert the facility
will depend on the type of alkylate process chosen and the level of production
desired by the partnership.
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 was accomplished by distributing one additional
partnership Unit for each partnership Unit outstanding to holders of record on
April 30, 2002. The Units were distributed on May 15, 2002. All references to
number of Units or earnings per Unit contained in this document relate to the
post-split Units, except if indicated otherwise.
Conversion of EPCO Subordinated Units and Shell Special Units to Common Units
As a result of the Company satisfying certain financial tests,
10,704,936 (or 25%) of EPCO's Subordinated Units converted to Common Units on
May 1, 2002. If the financial criteria continue to be satisfied through the
first quarter of 2003, an additional 25% of the Subordinated Units will undergo
an early conversion on a one-for-one basis to Common Units on May 1, 2003. The
remaining 50% of Subordinated Units will convert on August 1, 2003 if the
balance of the conversion requirements are met. Subordinated Units have limited
voting rights until converted to Common Units. The conversion(s) will have no
impact upon our distributions or earnings per unit
54
since the Subordinated Units are already distribution-bearing and included in
both the basic and fully diluted calculations.
In accordance with existing agreements with Shell, 19.0 million of
Shell's non-distribution bearing Special Units converted to distribution-bearing
Common Units on August 1, 2002. The remaining 10.0 million Special Units will
convert to Common Units on a one-for-one basis in August 2003. These conversions
have a dilutive impact on basic earnings per Unit since they increase the number
of Common Units used in the computation. As a result of the August 2002
conversion of the Shell Special Units to an equal number of Common Units, our
basic earnings per Unit for 2002 were reduced by $0.03. 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.
Facility and sensitive infrastructure security matters
Following the 2001 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 have 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 our 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.
SEC review
In connection with registration statements on Forms S-3 and S-4 that we
filed on January 28, 2003, we have received comments from the staff of the
Division of Corporation Finance of the Securities and Exchange Commission in
connection with a routine review. The comments covered the registration
statements and the documents incorporated by reference in the registration
statements, including our annual report on Form 10-K for the year ended December
31, 2001. On March 18, 2003, we formally responded to the staff's comments and
filed amendments to the Forms S-3 and S-4. We have also had informal discussions
with the staff concerning their comments and our responses. We believe that we
have been fully responsive to all of the staff's comments, and have incorporated
those comments into this annual report. However, the staff may have additional
comments that could affect the disclosure contained in this annual report and
previous filings.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are exposed to financial market risks, including changes in
commodity prices and interest rates. 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 within our Processing segment. In general, the types of
risks we attempt to hedge 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. For additional information regarding our
financial instruments, see the Notes to our Consolidated Financial Statements.
Commodity price risk
The prices of natural gas, NGLs, petrochemical products 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 our Processing segment activities, we may enter into
various commodity financial instruments. The primary purpose of these risk
management activities is to hedge our exposure to price risks associated with
natural gas, NGL production and inventories, firm commitments and certain
anticipated transactions. The commodity financial instruments we utilize may be
settled in cash or with another financial instrument.
55
We do not hedge our exposure related to MTBE price risks. In addition,
we generally do not hedge risks associated with the petrochemical marketing
activities that are part of our Fractionation segment. In our Pipelines segment,
we do utilize a limited number of commodity financial instruments to manage the
price Acadian Gas charges certain of its customers for natural gas. Lastly, due
to the nature of the transactions, we do not employ commodity financial
instruments in our fee-based marketing business accounted for in the Other
segment.
We have adopted a policy to govern our use of commodity financial
instruments to manage 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 limits 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 24 months. The
General Partner oversees 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.
Our commodity financial instruments may not qualify for hedge
accounting treatment under the specific guidelines of SFAS No. 133 because of
ineffectiveness. A financial instrument is generally regarded as "effective"
when changes in its fair value almost fully offset changes in the fair value of
the hedged item throughout the term of the instrument. Due to the complex nature
of risks we attempt to hedge, our commodity financial instruments have generally
not qualified as effective hedges under SFAS No. 133, with the result being that
changes in the fair value of these positions being recorded on the balance sheet
and in earnings through mark-to-market accounting. Mark-to-market accounting
results in a degree of non-cash earnings volatility that is dependent upon
changes in the commodity prices underlying these financial instruments. Even
though these financial instruments may not qualify for hedge accounting
treatment under SFAS No. 133, we view such contracts as hedges since this was
the intent when we entered into such positions. Upon entering into such
positions, our expectation is that the economic performance of these instruments
will mitigate (or offset) the commodity risk being addressed. The specific
accounting for these contracts, however, is consistent with the requirements of
SFAS No. 133.
We assess the risk of our commodity financial instrument portfolio
using a sensitivity analysis model. The sensitivity analysis performed on this
portfolio measures the potential income or loss (e.g., the change in fair value
of the portfolio) based upon a hypothetical 10% movement in the underlying
quoted market prices of the commodity financial instruments outstanding at the
dates noted within the following table. In general, the quoted market prices
used in the model are from those actively quoted on commodity exchanges (i.e.,
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.
The sensitivity analysis model takes into account the following primary
factors and assumptions:
o the current quoted market price of natural gas;
o the current quoted market price of NGLs;
o changes in the composition of commodities hedged (i.e., the mix
between natural gas and related NGLs);
o fluctuations in the overall volume of commodities hedged (for both
natural gas and related NGL hedges outstanding);
o market interest rates, which are used in determining the present
value; and
o 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:
56
o the commodity financial instruments function effectively as hedges
of the underlying risk;
o the commodity financial instruments are not closed out in advance of
their expected term; and
o as applicable, anticipated underlying transactions settle as
expected.
We routinely review our outstanding financial instruments in light of
current market conditions. If market conditions warrant, some financial
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.
The following table shows the effect of hypothetical price movements on
the fair value ("FV") of our commodity financial instrument portfolio and the
related potential impact on our earnings ("IE") at the dates indicated (values
in thousands of dollars):
RESULTING AT AT AT
SCENARIO CLASSIFICATION 12/31/01 12/31/02 03/03/03
---------------------------------------------------------------------------------------------------------------------
FV assuming no change in quoted market prices Asset (Liability) $ 6,786 $ (26) $ 84
FV assuming 10% increase in quoted market prices Asset (Liability) $ 844 $ (26) $ 380
IE assuming 10% increase in quoted market prices Income (Loss) $(5,942) $ - $ 296
FV assuming 10% decrease in quoted market prices Asset (Liability) $ 12,599 $ (26) $(211)
IE assuming 10% decrease in quoted market prices Income (Loss) $ 5,813 $ - $(295)
At December 31, 2001, the net fair value of our commodity financial
instruments portfolio was a $6.8 million asset, almost all of which was based
upon quoted market prices. At December 31, 2002, the net fair value of this
portfolio was a payable of $26 thousand, based entirely upon quoted market
prices. Due to commodity hedging losses we incurred during the first quarter of
2002, we exited most of our positions (see our Processing segment discussion
under "Our results of operations" in Item 7). At December 31, 2002, we had a
limited number of commodity financial instruments outstanding. The fair value of
the portfolio at March 3, 2003 was a $84 thousand asset and was again comprised
of a limited number of positions.
During 2002, we recognized a loss of $51.3 million from our commodity
hedging activities that was recorded as an increase in our operating costs and
expenses in the Statements of Consolidated Operations. Of the loss recognized in
2002, $5.6 million is related to non-cash mark-to-market income recorded on open
positions at December 31, 2001. During 2001, we posted income of $101.3 million
from our commodity hedging activities, which served to reduce operating costs
and expenses.
Product purchase commitments. We have long-term purchase commitments
for NGLs, petrochemicals and natural gas with several suppliers. The purchase
prices that we are obligated to pay under these contracts are based on market
prices at the time we take delivery of the volumes.
Interest rate risk
Our interest rate exposure results from variable-interest rate
borrowings and fixed-interest rate borrowings. We assess the cash flow risk
related to interest rates by identifying and measuring changes in our interest
rate exposures that may impact future cash flows and evaluating hedging
opportunities to manage these risks. We use analytical techniques to measure our
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
these financial risks and approves instruments that are appropriate for our
requirements.
Interest rate swaps. We manage a portion of our interest rate risks by
utilizing interest rate swaps. The objective of entering into 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.
In general, an interest rate swap requires one party to pay a fixed-interest
rate on a notional amount while the other party pays a floating-interest rate
57
based on the same notional amount. We believe that it is prudent to maintain an
appropriate balance of variable-rate and fixed-rate debt.
The following table shows the effect of hypothetical price movements on
the fair value ("FV") of our interest rate swap portfolio and the related
potential impact on our earnings ("IE") at the dates indicated (values in
thousands of dollars):
RESULTING AT AT
SCENARIO CLASSIFICATION 12/31/01 12/31/02
-----------------------------------------------------------------------------------------------------
FV assuming no change in quoted market prices Asset (Liability) $ 3,531 $ 1,634
FV assuming 10% increase in quoted market prices Asset (Liability) $ 3,345 $ 1,634
IE assuming 10% increase in quoted market prices Income (Loss) $ (186) $ -
FV assuming 10% decrease in quoted market prices Asset (Liability) $ 3,717 $ 1,634
IE assuming 10% decrease in quoted market prices Income (Loss) $ 186 $ -
At December 31, 2002 and 2001, we had one interest rate swap
outstanding having a notional amount of $54 million that extended through March
2010. Under the terms of the swap, the counterparty had the right to terminate
the swap on March 1, 2003. The fair value of this swap was a $3.5 million asset
at December 31, 2001. The fair value of this swap at December 31, 2002 was $1.6
million. The change in fair value of this swap during 2002 is primarily due to
settlements. A change in interest rates at December 31, 2002 would have
negligible effect on the fair value of this swap. The counterparty elected to
terminate this swap as of March 1, 2003 and we received $1.6 million associated
with the final settlement of this swap on that date.
We recognized income from our interest rate swaps of $0.9 million
during 2002 compared to $13.2 million during 2001. This income is recorded as a
reduction of interest expense in our Statements of Consolidated Operations.
Treasury Locks. During the fourth quarter of 2002, we entered into
seven treasury lock transactions with original maturities of either January 31,
2003 or April 15, 2003. A treasury lock is a specialized agreement that fixes
the price (or yield) on a specific U.S. treasury security for an established
period of time. The purpose of these transactions was to hedge the underlying
treasury interest rate associated with our anticipated issuance of debt in early
2003 to partially refinance the Mid-America and Seminole acquisitions. Our
treasury lock transactions are accounted for as cash flow hedges under SFAS No.
133. The notional amounts of these transactions totaled $550 million, with a
total treasury lock rate of approximately 4%.
We elected to settle all of the treasury locks by early February 2003
in connection with our issuance of Senior Notes C and D (see "Management's
Discussion and Analysis of Financial Condition and Results of Operations--Our
liquidity and capital resource--Our debt obligations" under Item 7 of this
annual report). The settlement of the treasury locks resulted in our receipt of
$5.4 million of cash.
The fair value of these instruments at December 31, 2002 was a current
liability of $3.8 million offset by a current asset of $0.2 million. The net
$3.6 million net liability was recorded as a component of comprehensive income
on that date, with no impact to current earnings. With the settlement of the
treasury locks, the $3.6 million net liability will be reclassified out of
accumulated other comprehensive income in Partners' Equity to offset the current
asset and liabilities we recorded at December 31, 2002, with no impact to
earnings. For additional information regarding our treasury lock transactions,
see our footnote titled "Financial Instruments" in the Notes to Consolidated
Financial Statements under Item 8 of this annual report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information for both registrants required hereunder is included in
this report as set forth in the "Index to Financial Statements" beginning on
page F-1.
58
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF OUR REGISTRANTS.
As is commonly the case with publicly-traded 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 69) 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 independent
nonexecutive directors, free from any relationship with the Company or any of
its subsidiaries 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. Richard S. Snell, a
certified public accountant, has been named by the Board of Directors of the
General Partner as the independent financial expert serving on the Audit and
Conflicts Committee. The other two members of the Audit and Conflicts Committee
are Dr. Ralph S. Cunningham and Lee W. Marshall, Sr.
In addition to ruling in cases involving conflicts of interest, the
primary responsibilities of the Audit and Conflicts Committee include:
o monitoring the integrity of the financial reporting process and its
related systems of internal control;
o ensuring legal and regulatory compliance of the General Partner and
the Company;
o overseeing the independence and performance of our independent
public accountants;
o approving all services performed by our independent public
accountants;
o providing for an avenue of communication among the independent
public accountants, management, internal audit function and the
Board of Directors;
o encouraging adherence to and continuous improvement of our policies,
procedures and practices at all levels;
o reviewing areas of potential significant financial risk to our
businesses; and
o 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.
59
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) 70 Director and Chairman of the Board
O.S. Andras (1,3) 67 Director, President and Chief Executive Officer
Richard H. Bachmann (1,3) 50 Director, Executive Vice President, Chief Legal Officer and
Secretary
Michael A. Creel (3) 49 Executive Vice President and Chief Financial Officer
A.J. Teague (3) 58 Executive Vice President
William D. Ray (3) 67 Executive Vice President
Charles E. Crain (3) 69 Senior Vice President
A. Monty Wells (3) 57 Senior Vice President
W. Ordemann (3) 43 Senior Vice President
Gil H. Radtke (3) 42 Senior Vice President
James M. Collingsworth (3) 48 Senior Vice President
James A. Cisarik (3) 45 Senior Vice President
Michael J. Knesek (3) 48 Vice President, Controller and Principal Accounting Officer
W. Randall Fowler (3) 46 Vice President and Treasurer
Randa D. Williams 41 Director
J.R. Eagan 48 Director
J.A. Berget (1) 50 Director
Dr. Ralph S. Cunningham (2) 62 Director
A. Y. Noojin, III (1) 55 Director
Lee W. Marshall, Sr. (2) 70 Director
Richard S. Snell (2) 60 Director
- ------------------------------------------------------------------------------------------------------------
(1) Member of Executive Committee
(2) Member of Audit and Conflicts Committee
(3) Executive Officer
Some officers of our General Partner spend portions of their time
managing the business and affairs of EPCO and its affiliates. Our General
Partner causes its officers to devote as much time as is necessary for the
proper conduct of our business and affairs in the event that these officers face
conflicts regarding the allocation of their time between our business and the
business interests of EPCO. Unless otherwise indicated below, each officer
devotes 100% of his time to our business and affairs.
Dan L. Duncan was elected Chairman and a Director of our General
Partner in April 1998. Mr. Duncan has served as Chairman of the Board of our
predecessor, EPCO, since 1979. Mr. Duncan devotes approximately 40% of his time
to our business and affairs.
O.S. Andras was elected President, Chief Executive Officer and a
Director of our General Partner in April 1998. Mr. Andras served as President
and Chief Executive Officer of EPCO from 1996 to February 2001 and currently
serves as Vice Chairman of the Board of EPCO. Mr. Andras devotes approximately
80% of his time to our business and affairs.
Richard H. Bachmann was elected a Director of our General Partner in
June 2000. He has served as Executive Vice President, Chief Legal Officer and
Secretary of our General Partner and EPCO since January 1999. Previously, he was
a partner with the Snell & Smith P.C. law firm in Houston, Texas, from 1993 to
1999 and prior
60
to that was a partner with the Butler & Binion law firm in Houston from 1988 to
1993. Mr. Bachmann devotes approximately 60% of his time to our business and
affairs.
Michael A. Creel was elected an Executive Vice President of our General
Partner and EPCO in February 2001, having served as a Senior Vice President of
our General Partner and EPCO since November 1999. In June 2000, Mr. Creel, a
certified public accountant, assumed the role of Chief Financial Officer of our
General Partner and EPCO along with his other responsibilities. Previously, he
served with Tejas Energy, LLC, a Shell affiliate, as Senior Vice
President-Finance from 1997 to 1998, Senior Vice President, Chief Financial
Officer and Treasurer from 1998 to 1999 and Senior Vice President from January
to September 1999. From 1995 to 1997, Mr. Creel was Vice President and Treasurer
of NorAm Energy Corp. Mr. Creel devotes approximately 55% of his time to our
business and affairs.
A.J. Teague was elected an Executive Vice President of our General
Partner in November 1999. From 1998 to 1999 he served as President of Tejas
Natural Gas Liquids, LLC, then 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 our General
Partner in April 1998. Mr. Ray served as EPCO's Executive Vice President of
Supply and Marketing from 1985 to 1998. Mr. Ray continues to hold managerial
responsibilities with respect to EPCO but devotes in excess of 95% of his time
to our business and affairs.
Charles E. Crain was elected a Senior Vice President of our General
Partner in April 1998. Mr. Crain served as Senior Vice President of Operations
for EPCO from 1991 to 1998.
A. Monty Wells was elected a Senior Vice President of our General
Partner in June 2000 after serving as Manager - Marketing and Supply since 1998.
Mr. Wells joined EPCO in 1980, and served as Manager of Marketing and Supply
from 1990 to 1999 and Vice President of Marketing and Supply from 1999 to 2000.
William Ordemann joined us as a Vice President in October 1999 and was
elected a Senior Vice President of our General Partner in September 2001. From
January 1997 to February 1998, Mr. Ordemann was a Vice President of Shell
Midstream Enterprises, LLC, and from February 1998 to September 1999 was a Vice
President of Tejas Natural Gas Liquids, LLC, both Shell affiliates.
Gil H. Radtke was elected a Senior Vice President of our General
Partner in February 2002. Mr. Radtke joined us in connection with our purchase
of Diamond-Koch's storage and propylene fractionation assets in January and
February 2002. Before joining us, Mr. Radtke served as President of the
Diamond-Koch joint venture from 1999 to 2002, where he was responsible for its
storage, propylene fractionation, pipeline and NGL fractionation businesses.
From 1997 to 1999 he was Vice President, Petrochemicals and Storage of
Diamond-Koch. Mr. Radtke was previously employed by Ultramar Diamond-Shamrock
Corporation (a partner in the Diamond-Koch joint venture) beginning in 1983.
James M. Collingsworth joined us as a Vice President in November 2001
and was elected a Senior Vice President of our General Partner in November 2002.
Previously, he served as a board member of Texaco Canada Petroleum Inc. from
July 1998 to October 2001 and was employed by Texaco from 1991 to 2001 in
various management positions, including Senior Vice President of NGL Assets and
Business Services from July 1998 to October 2001. Prior to joining Texaco, Mr.
Collingsworth was director of feedstocks for Rexene Petrochemical Company from
1988 to 1991 and served previously in the MAPCO, Inc. organization from 1973 to
1988 in various capacities including customer service and business development
manager of the Mid-America and Seminole pipelines.
James A. Cisarik was elected a Senior Vice President of our General
Partner in February 2003. Mr. Cisarik joined us in April 2001 when we acquired
Acadian Gas from Shell. His primary responsibility since joining us has been
oversight of the commercial activities of our natural gas businesses,
principally those of Acadian Gas and our Gulf of Mexico natural gas pipeline
investments. From February 1999 through March 2001, Mr. Cisarik was a Senior
Vice President of Coral Energy, LLC, and from 1997 to February 1999 was Vice
President, Market Development of Tejas Energy, LLC, both affiliates of Shell,
with responsibilities in market development for their
61
Texas and Louisiana natural gas pipeline systems. Prior to his employment at
Tejas Energy, LLC, he was employed from 1983 to 1997 by Tejas Gas Corporation
and other previous owners of Acadian Gas.
Michael J. Knesek was elected Principal Accounting Officer and a Vice
President of our General Partner in August 2000. Since 1990, Mr. Knesek, a
certified public accountant, has been the Controller and a Vice President of
EPCO. Mr. Knesek devotes approximately 70% of his time to our business and
affairs.
W. Randall Fowler joined us as Director of Investor Relations in
January 1999 and was elected to the additional positions of Treasurer and a Vice
President of our General Partner and EPCO in August 2000. From May 1995 to
December 1997, Mr. Fowler served as an Assistant Treasurer at NorAm Energy Corp.
From January 1998 through December 1998, Mr. Fowler served as Director of
Finance for Reliant Energy. Mr. Fowler devotes approximately 90% of his time to
our business and affairs.
Randa D. Williams was elected a Director of our 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. Eagan was elected a Director of our General Partner in October
2000. Ms. Eagan has served in various executive-level positions with Shell, and
since February 2002 she has held the office of Chief Financial Officer of Shell
Oil Company and Vice President Finance & Commercial Operations of Shell
Exploration and Production Company. From January 2000 to January 2002 she served
as Vice President, Finance & Commercial Operations of Shell Exploration and
Production Company. From January 1999 to December 1999 she was Vice President
Finance of Shell Exploration and Production Company. From January 1998 to
October 1998 she was Deputy Group Controller of Shell International Limited.
J.A. Berget was elected a Director of our General Partner in November
2000. Since 1995, Mr. Berget has served in various managerial capacities with
the Royal Dutch/Shell Group of Companies, including General Manager of the Brent
Business Unit of Shell U.K. from January 1997 to March 1999, General Manager,
New Markets of the Brent Business Unit of Shell U.K. from March 1999 to October
2000 and Vice President and General Manager of Shell Exploration and Production
Company from October 2000 to the present. 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 our 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 director of EPCO from 1987 to
1997. Dr. Cunningham serves as Chairman of our Audit and Conflicts Committee.
A. Y. Noojin, III, was elected a Director of our General Partner in May
2002. Mr. Noojin became President and Chief Executive Officer of Shell U.S. Gas
& Power, LLC, an affiliate of Shell, in May 2002. Previously, he served as
President and Chief Executive Officer of Shell Oil Products Company from October
2000 to May 2002, Executive Vice President of Shell Chemicals Company from
January 1998 to September 2000, and Vice President - Transportation of Shell Oil
Products Company from January 1996 to December 1997.
Lee W. Marshall, Sr. was elected a Director of our General Partner in
April 1998. Mr. Marshall has been the Managing Partner and principal owner of
Bison Resources, LLC, (a privately held oil and gas production company) since
1993. Previously, he held in senior management positions with Union Pacific
Resources, as Senior Vice President, Refining, Manufacturing and Marketing, with
Wolverine Exploration Company as Executive Vice President and Chief Financial
Officer and with Tenneco Oil Company as Senior Vice President, Marketing. Mr.
Marshall is a member of our Audit and Conflicts Committee.
Richard S. Snell was elected a Director of our General Partner in June
2000. Mr. Snell was an attorney with Snell & Smith, P.C. from the founding of
the firm in 1993 until May 2000. Since May 2000, he has been a partner with the
law firm of Thompson & Knight LLP in Houston, Texas. Mr. Snell is also a
certified public accountant and a member of our Audit and Conflicts Committee.
62
Section 16(a) Beneficial Ownership Reporting Compliance
Under the federal securities laws, our General Partner, the General
Partner's directors, executive (and certain other) officers, and any persons
holding more than ten percent of our Common Units are required to report their
ownership of Common Units and any changes in that ownership to us and the SEC.
Specific due dates for these reports have been established by regulation, and we
are required to disclose in this report any failure to file by these dates in
2002. We believe all of these filings were satisfied by our General Partner. We
believe that during 2002 our reporting persons complied with all applicable
filing requirements in a timely manner except: each of Dan L. Duncan and
Enterprise Products Company filed three late Form 4 reports covering three
transactions. Richard H. Bachmann filed one late Form 4 report covering one
transaction. Each of Richard S. Snell, Lee S. Marshall and Dr. Ralph S.
Cunningham filed one late Form 4 report covering one transaction.
In order to eliminate or reduce administrative and record keeping
errors related to our Section 16(a) beneficial ownership reporting compliance,
we have purchased new software to enable electronic filing of Forms 3, 4 and 5
and have instituted a new policy that prescribes procedures Section 16(a)
officers must follow before engaging in transactions in our Units. The new
procedures require a Section 16(a) officer to submit a notice of intent to
engage in any reportable transaction to a Securities Transaction Committee
composed of senior management officials of the General Partner and obtain the
committee's clearance of the proposed transaction before it may take place.
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. We reimburse EPCO for our portion of the compensation
EPCO pays individuals it employs as a result of our expansion-related activities
(through business acquisitions, the construction of new facilities and the
like). In addition, we pay EPCO an annual Administrative Services Fee (currently
$17.6 million) to cover a portion of EPCO's total compensation costs for
approximately 100 other individuals it employs for the management and operation
of our businesses. For a more complete description of our relationship with
EPCO, see Item 13 of this report.
That portion of the compensation of O.S. Andras, the General Partner's
CEO, attributable to his services performed on our behalf is reimbursed to EPCO
through our payment of the Administrative Services Fee. Of the EPCO employees
serving our General Partner whose compensation is wholly or partially-reimbursed
by us, the next four most highly compensated at December 31, 2002 were A.J.
Teague, William D. Ray, Charles E. Crain and W. Ordemann. Collectively, these
five individuals represent our "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 may have also received certain equity-based awards as part of
their compensation from EPCO, the reimbursement of which by us is determined by
whether or not their compensation is considered part of the Administrative
Services Fee. As such, the cost of awards granted to Mr. Ray and Mr. Crain are
the sole responsibility of EPCO; however, we are responsible for all of the
costs associated with the awards granted to Mr. Teague and Mr. Ordemann. For
additional information regarding our responsibilities under EPCO's equity-based
award program, please see our footnote titled "Unit Option Plan Accounting" in
the Notes to Financial Statements under Item 8 of this annual report.
63
The following table sets forth certain compensation information for our
Named Executive Officers for the years ended December 31, 2002, 2001 and 2000.
The Administrative Services Fee paid to EPCO for the years ended December 31,
2002, 2001 and 2000 was $16.6 million, $15.1 million and $13.8 million,
respectively. Our payment of this annual fee is our maximum reimbursement to
EPCO for the costs it incurs in managing and operating our business, apart from
those expenses deemed attributable to our expansion and business development
activities.
Summary Compensation Table
LONG-TERM
COMPENSATION
SECURITIES
NAME AND ANNUAL COMPENSATION UNDERLYING ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS OPTIONS (#) COMPENSATION (1)
-----------------------------------------------------------------------------------------------------
O.S. Andras 2002(2) $ 864,000 $ - - $ 13,671
Chief Executive Officer 2001(2) $ 880,000 $ - - $ 10,078
2000(2) $ 880,000 $ - - $ 10,027
A. J. Teague, 2002 $ 370,000 $ 70,000 - $ 17,240
Executive Vice President 2001 $ 345,000 $ 80,000 100,000 $ 11,160
2000 $ 322,500 $ 35,000 100,000 $ 11,022
William D. Ray, 2002(2) $ 225,000 $ 30,000 - $ 17,089
Executive Vice President 2001(2) $ 210,833 $ 40,000 20,000 $ 13,384
2000(2) $ 198,750 $ 25,000 - $ 12,534
Charles E. Crain, 2002(2) $ 240,000 $ 50,000 - $ 17,089
Senior Vice President 2001(2) $ 218,542 $ 60,000 20,000 $ 13,173
2000(2) $ 203,583 $ 25,000 - $ 12,534
W. Ordemann, 2002 $ 209,000 $ 60,000 - $ 14,398
Senior Vice President 2001(3) $ 179,115 $160,000 40,000 $ 11,196
2000 $ 156,094 $ 15,000 - $ 10,428
-----------------------------------------------------------------------------------------------------
(1) These amounts primarily represent contributions made by EPCO to the
401(k) plan of the Named Executive Officers.
(2) These amounts are included within Administrative Services Fee we pay
to EPCO.
(3) Mr. Ordemann's 2001 bonuses include a $100,000 retention bonus agreed
to when he joined us in connection with the TNGL acquisition in 1999.
Common Unit Option Grants during 2002. There were no individual grants
of options to purchase Common Units granted to our Named Executive Officers
during 2002.
64
Unit Options Exercised and Fiscal Year-End Values. The following table
provides certain information concerning each exercise of options to purchase
Common Units during the year ended December 31, 2002 by each of the Named
Executive Officers and the value of unexercised options at December 31, 2002:
NUMBER OF VALUE OF
SECURITIES UNDERLYING UNEXERCISED
UNEXERCISED OPTIONS IN-THE-MONEY OPTIONS
UNITS VALUE AT DECEMBER 31, 2002 AT DECEMBER 31, 2002 (2)
ACQUIRED ON REALIZED ($) --------------------------- ---------------------------
NAME EXERCISE (#) (1) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
--------------------------------------------------------------------------------------------------------------
O. S. Andras - $ - - - $ - $ -
A. J. Teague - $ - - 200,000 $ - $ 1,106,250
William D. Ray - $ - 20,000 20,000 $ 208,000 $ 69,500
Charlie E. Crain - $ - 40,000 20,000 $ 416,000 $ 69,500
W. Ordemann - $ - 20,000 40,000 $ 208,000 $ 139,000
-------------------------------------------------------------------------------------------------------------------
(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 by the
beneficiary.
(2) The value is based on the $19.40 closing price of our Common Units at
December 31, 2002.
Compensation of Directors. No additional compensation is paid to
employees of EPCO or Shell who also serve as directors of the General Partner.
The three independent outside directors are compensated for their services at
the expense of the General Partner. During 2002, the three independent outside
directors were paid collectively $85,500 by the General Partner for their
service as directors.
The three independent outside directors have also been granted options
to acquire our Common Units. During 2002, 40,000 of these Common Unit options
were exercised by the independent directors at a cost of approximately $0.6
million to the General Partner. Collectively, these directors had 80,000
remaining Common Unit options outstanding at December 31, 2002.
Beginning in 2003, the compensation of our independent outside
directors will increase. Specifically, each will receive (i) an annual retainer
of $22,500, (ii) $1,250 for each meeting of the Board of Directors that they
attend, (iii) $625 for each meeting of a committee of the Board of Directors
that they attend and (iv) an annual retainer of $5,750 for those who serve as
the chairman of a committee of the Board of Directors.
65
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED UNITHOLDER MATTERS.
Security Ownership of Certain Beneficial Owners and Management
The following table sets forth certain information as of March 1, 2003,
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
------------------------ ------------------------ ------------------------
Dan L. Duncan:
Units owned by EPCO(1) 79,285,766 50.6%
Units owned by Trusts(2) 2,478,236 1.6%
Units owned directly 111,600 *
------------------------ ------------------------
Total for Dan L. Duncan 81,875,602 52.4% 32,114,804 100.0%
======================== ========================
Shell (3) 31,000,000 19.8% 10,000,000 100.0%
O.S. Andras (6) 2,941,200 1.9%
Randa D. Williams (4) 1,000,000 *
Lee W. Marshall, Sr. 13,340 *
Richard S. Snell 1,200 *
Richard H. Bachmann (5) 88,019 *
A. J. Teague (6) 55,769 *
William D. Ray (6,7) 40,108 *
Charles E. Crain (6,8) 123,320 *
W. Ordemann (6,9) 20,500 *
All directors and executive
officers as a group
(21 persons)(10) 86,307,236 55.1% 32,114,804 100.0%
* The beneficial ownership of each is less than 1% of our Common Units
outstanding.
- --------------------------------------------------------------------------------------------------------------
(1) EPCO owns its Units through a wholly-owned subsidiary, Enterprise Products
Delaware Holdings, L.P. Mr. Duncan owns 50.4% of the voting stock of EPCO and,
accordingly, exercises sole voting and dispositive power with respect to the
Units beneficially owned by EPCO. The remaining shares of EPCO capital stock are
owned primarily by trusts for the benefit of the members of Mr. Duncan's family,
including Randa D. Williams, a director of our General Partner. The address of
EPCO and Mr. Duncan is 2727 North Loop West, Houston, Texas, 77008.
(2) In addition to the Units owned by EPCO, Dan L. Duncan has beneficial
ownership of Common Units owned by the Duncan Family 1998 Trust and Duncan
Family 2000 Trust.
(3) We issued Units to Shell US Gas & Power LLC (an affiliate of Shell) as part
of the TNGL acquisition. The address of Shell US Gas & Power LLC is 1301
McKinney, Ste. 700, Houston, Texas 77010.
(4) Randa D. Williams is the trustee of four trusts set up for the benefit of
the children of Dan L. Duncan. Ms. Williams is the daughter of Mr. Duncan. Of
the 1,000,000 Common Units held by the four trusts, she has disclaimed
beneficial ownership of 750,000 of these Units.
(5) Mr. Bachmann's beneficial ownership amount includes 80,000 Common Unit
options issued under the equity compensation plan of EPCO that are exercisable
within 60 days of the filing date of this report.
(6) These individuals are Named Executive Officers (see Item 11).
(7) Mr. Ray's beneficial ownership amount includes 20,000 Common Unit options
issued under the equity compensation plan of EPCO that are exercisable within 60
days of the filing date of this report.
(8) Mr. Crain's beneficial ownership amount includes 40,000 Common Unit options
issued under the equity compensation plan of EPCO that are exercisable within 60
days of the filing date of this report.
(9) Mr. Ordemann's beneficial ownership amount includes 20,000 Common Unit
options issued under the equity compensation plan of EPCO that are exercisable
within 60 days of the filing date of this report.
(10) Cumulatively, this group's beneficial ownership amount includes 260,000
Common Unit options issued under the equity compensation plan of EPCO that are
exercisable within 60 days of the filing date of this report.
66
Subordinated Units and Special Units are non-voting until their
conversion in Common Units. At present, we are not aware of any pledge of our
securities or similar arrangement by owners our limited partnership interests,
the operation of which at some future date may result in a change of control of
our Company. For a discussion of our capital structure, see our footnote titled
"Capital Structure" in the Notes to Consolidated Financial Statements under Item
8 of this annual report.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets for certain information as of December 31,
2002 regarding the equity compensation plan of our affiliate, EPCO, under which
our Common Units are authorized for issuance to its key employees and to
directors of the General Partner.
NUMBER OF
SECURITIES
REMAINING
NUMBER OF AVAILABLE FOR
SECURITIES TO WEIGHTED- FUTURE ISSUANCE
BE ISSUED AVERAGE UNDER EQUITY
UPON EXERCISE EXERCISE PRICE COMPENSATION
OF OUTSTANDING OF OUTSTANDING PLANS (EXCLUDING
OPTIONS, OPTIONS, SECURITIES
WARRANTS AND WARRANTS AND REFLECTED IN
PLAN CATEGORY RIGHTS RIGHTS COLUMN (A))
- --------------------------------------------------------------------------------------------------
(A) (B) (C)
Equity compensation plans
approved by Unitholders:
None. - $ - -
Equity compensation plans
not approved by Unitholders:
1998 Plan 2,310,078 $ 14.57 1,689,922
Total for equity compensation
plans 2,310,078 $ 14.57 1,689,922
The Enterprise Products 1998 Long-Term Incentive Plan (the "1998 Plan")
is intended to promote our interests by encouraging employees and directors of
EPCO and its affiliates who perform services for us to acquire or increase their
ownership of our Common Units and to provide a means whereby they may develop a
sense of proprietorship and personal involvement in our development and
financial success through the award of Common Unit options. The 1998 Plan was
developed to encourage recipients of Common Unit options to remain with us and
to devote their best efforts to our business, thereby advancing the interests of
all Unitholders and the General Partner. The 1998 Plan also enhances our ability
to attract and retain the services of key individuals who are essential for our
growth and profitability.
The 1998 Plan is governed by a committee formed by EPCO whose
significant powers include, but are not limited to, (i) designating participants
in the plan; (ii) determining the number of Common Units to be covered by the
equity awards; (iii) determining the terms and conditions of any equity award;
and (iv) determining, whether, to what extent, and under what circumstances
participants may settle, exercise, cancel or forfeit any equity award. Subject
to adjustment as provided in the 1998 Plan documents, the number of Common Units
that may be awarded to participants is 4,000,000. The Common Units to be awarded
under this plan may be obtained through purchases made on the open market or
from affiliates of EPCO.
The exercise price of Common Unit options issued to participants is
determined by the committee (at its discretion) at the date of grant and may be
equal to, greater or less than its fair market value as of the date of grant.
The committee determines the time or times at which the awards may be exercised
in whole or in part, and the method or methods by which any payment of the
exercise price with respect thereto may be made or deemed to have been made,
which may include cash, notes receivable from the participant, or
cashless-broker transactions or other acceptable forms of payment. In addition,
to the extent provided by the committee, a Common Unit option grant may include
a contingent right to receive an amount in cash equal to any cash distributions
made by us with respect
67
to the underlying Common Units during the period the award is outstanding. The
1998 Plan also provides for the issuance of restricted (or phantom) Common
Units.
The 1998 Plan is effective until either all available Common Units
under the plan have been paid to participants or the earlier termination of the
Plan by EPCO. A second plan, the Enterprise Products 1999 Long-Term Incentive
Plan, is inactive and has no options outstanding. At present, we have no
intentions of issuing options under this second plan.
Commitments under equity compensation plans of EPCO
Categories of equity-based awards and our general commitments under
each
Equity-based awards granted to certain key operations employees. Under
the EPCO Agreement (see Item 13 of this annual report), we reimburse EPCO for
the compensation of all operations personnel it employs on our behalf. This
includes the costs attributable to equity-based awards granted to these
personnel. When these employees exercise Unit options, we reimburse EPCO for the
difference between the strike price paid by the employee and the actual purchase
price paid by EPCO for the Units awarded to the employee. We may reimburse EPCO
for these costs by either furnishing cash, reissuing Treasury Units or by
issuing new Common Units.
Equity-based awards granted to certain key expansion-related
administrative and management employees. We also reimburse EPCO for the
compensation of administrative and management personnel it hires in response to
our expansion and new business activities. This includes costs attributable to
equity-based awards granted to members of this "expansion" group of EPCO
employees. When these employees exercise Unit options, we reimburse EPCO for the
difference between the strike price paid by the employee and the actual purchase
price paid by EPCO for the Units awarded to the employee. We may reimburse EPCO
for these costs by either furnishing cash, reissuing Treasury Units or by
issuing new Common Units.
Equity-based awards granted to other key administrative and management
employees. In addition, we reimburse EPCO for our share of the costs of certain
of its employees in administrative and management positions that were active at
the time of our initial public offering in July 1998 who manage our business and
affairs. Our reimbursement for the cost of equity-based awards to this
"pre-expansion" group of employees is covered by the Administrative Services Fee
we pay to EPCO. EPCO is responsible for the actual costs when the Unit awards
granted to these pre-expansion employees are exercised. EPCO satisfies its
equity-award obligations to these employees by arranging for Common Units to be
purchased in the open market.
Our commitments at December 31, 2002
At December 31, 2002, there were 1,194,242 options outstanding to
purchase Common Units under the 1998 Plan that had been granted to operations
and expansion-related administrative and management employees for which we were
responsible for reimbursing EPCO for the costs of such awards. The
weighted-average strike price of the Unit option awards granted to this group
was $15.73 per Common Unit. At December 31, 2002, 275,242 of these Unit options
were exercisable. An additional 100,000, 570,000 and 249,000 of these Unit
options will be exercisable in 2003, 2004 and 2005, respectively.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Relationship with EPCO and its affiliates
We have an extensive and ongoing relationship with EPCO. 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 D. 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.
68
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 Ms. 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 us.
In addition, trust affiliates of EPCO (the 1998 Trust and 2000 Trust)
owned 2,478,236 Common Units at December 31, 2002. Collectively, EPCO, Dan L.
Duncan, the 1998 Trust and the 2000 Trust owned 61.4% of our limited partnership
interests at December 31, 2002.
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.
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. Under the terms of the EPCO Agreement, EPCO
agrees to:
o employ the personnel necessary to manage our business and affairs
(through the General Partner);
o employ the operating personnel involved in our business for which we
reimburse EPCO (based upon EPCO's actual salary and related fringe
benefits cost);
o 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;
o grant us an irrevocable, non-exclusive worldwide license to all of
the EPCO trademarks and trade names used in our business;
o indemnify us against any losses resulting from certain lawsuits; and
o 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 to us its purchase option under such
leases to us (the "retained leases"). EPCO remains liable for the
lease payments associated with these assets.
Operating costs and expenses (as shown in the Statements of Consolidated
Operations) treat the lease payments being made by EPCO as a non-cash related
party operating expense, with the offset to Partners' Equity on the Consolidated
Balance Sheets recorded a general contribution to the partnership. Should we
decide to exercise the purchase options associated with the retained leases
(which are at fair market value), up to $26.0 million will be payable in 2004,
$3.4 million in 2008 and $3.1 million in 2016. In addition, operating costs and
expenses include compensation charges for EPCO's employees who operate our
facilities.
Pursuant to the EPCO Agreement, we reimburse EPCO for our share of the
costs of certain of its employees in administrative positions that were active
at the time of our initial public offering in July 1998 who manage our business
and affairs. Our reimbursement of EPCO's administrative personnel expense is
capped (currently at $17.6 million annually). The General Partner, with the
approval and consent of the Audit and Conflicts Committee, may agree to
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 of administrative personnel (including costs associated with equity-based
awards granted to certain individuals within this group) and the fee we pay will
be born solely by EPCO. The actual amounts incurred by EPCO did not materially
exceed the capped amounts for any periods. We also reimburse EPCO for the
compensation of administrative personnel it hires in response to our expansion
and new business activities. This includes costs attributable to equity-based
awards granted to members of this group.
69
Other related party transactions with EPCO. The following is a summary
of other significant related party transactions between EPCO and us, including
those between EPCO and our unconsolidated affiliates.
o EPCO is the operator of the facilities owned by BEF, of which we own
33.3%. In lieu of charging BEF for the actual cost of providing
management services, EPCO charges BEF a management fee. EPCO charged
BEF $0.6 million for such services during each of 2002, 2001 and
2000.
o EPCO is also operator of the facilities owned by EPIK, of which we
now wholly own. Prior to February 2003, we owned only 50% of EPIK.
In lieu of charging EPIK for the actual cost of management services,
EPCO charges EPIK a management fee. During 2002, 2001 and 2000, EPCO
charged EPIK $0.3 million, $0.2 million and $0.3 million,
respectively, for such services.
o We have entered into an agreement with EPCO to provide trucking
services to us for the loading and transportation of products.
o In the normal course of business, we also buy from and sell NGL
products to EPCO's Canadian affiliate.
The following table summarizes our various related party transactions
with EPCO for the years ended December 31, 2002, 2001 and 2000:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
REVENUES FROM CONSOLIDATED OPERATIONS
EPCO $ 3,630 $ 5,439 $ 4,750
OPERATING COSTS AND EXPENSES
EPCO 103,210 62,919 52,861
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES
Base fees payable under EPCO Agreement 16,638 15,125 13,750
Other EPCO compensation reimbursement 7,566 4,824 1,930
Relationship with Shell
We have an extensive and ongoing commercial relationship with Shell as
a partner, customer and vendor. Shell, through its subsidiary Shell US Gas &
Power LLC, currently owns approximately 20.5% of our limited partnership
interests and 30.0% of the General Partner. Currently, three members of the
Board of Directors of the General Partner (J. A. Berget, J.R. Eagan, and A.Y.
Noojin, III) are employees of Shell.
Shell is our single largest customer. During 2002, it accounted for
7.8% of our consolidated revenues. Our revenues from Shell reflect the sale of
NGL and petrochemical products to them and the fees we charge them for pipeline
transportation and NGL fractionation services. Our operating costs and expenses
with Shell primarily reflect the payment of energy related-expenses related to
the Shell natural gas processing agreement (see below) and the purchase of NGL
products from them. The following table shows our revenues and operating costs
and expenses with Shell for the years ended December 31, 2002, 2001 and 2000:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
REVENUES FROM CONSOLIDATED OPERATIONS
Shell $ 282,820 $ 333,333 $ 292,741
OPERATING COSTS AND EXPENSES
Shell 531,712 705,440 736,655
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 state and federal waters of
the Gulf of Mexico on a keepwhole basis. This is a life of lease dedication,
which may extend the agreement well beyond 20 years. Generally, this contract
has the following rights and obligations:
70
o the exclusive right, but not the obligation, to process
substantially all of Shell's Gulf of Mexico natural gas production;
plus
o the exclusive right, but not the obligation, to process all natural
gas production from leases dedicated by Shell for the life of such
leases; plus
o 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
o the obligation to re-deliver to Shell the natural gas stream after
the mixed NGL stream is extracted.
Under this contract, we are responsible for reimbursing Shell for the market
value of the energy we extract from their natural gas stream in the course of
performing natural gas processing services for them. Our reimbursement to Shell
(which we record as an operating cost) is generally based upon the energy value
of the fuel we consume and the NGLs we extract from their natural gas stream (in
terms of its Btu content, a measure of heating value). In lieu of collecting a
cash fee for our services under this contract, we take ownership of the NGLs we
extract from their natural gas stream. These volumes (our "equity NGL
production") become part of our inventory held for sale. We derive a profit to
the extent that the revenues from the ultimate sale and delivery of these NGLs
to customers exceeds the costs of extraction and any other ancillary costs such
as fractionation fees.
We have completed a number of business acquisitions and asset purchases
involving Shell since 1999. Among these transactions were:
o the acquisition of TNGL's natural gas processing and related
businesses in 1999 for approximately $529 million (this purchase
price includes both the $166 million in cash we paid to Shell and
the value of the three issues of Special Units granted to Shell in
connection with this acquisition);
o the purchase of the Lou-Tex Propylene Pipeline System for $100
million in 2000; and,
o the acquisition of Acadian Gas in 2001 for $244 million.
Shell is also a partner with us in the Gulf of Mexico natural gas pipelines we
acquired from El Paso in 2001. We also lease from Shell its 45.4% interest in
our Splitter I propylene fractionation facility.
Relationships with Unconsolidated Affiliates
Our investment in unconsolidated affiliates with industry partners is a
vital component of our business strategy. These investments are a means by which
we conduct our operations to align our interests with a supplier of raw
materials or a consumer of finished products. 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. The following summarizes significant related
party transactions we have with our unconsolidated affiliates:
o We sell natural gas to Evangeline, which, in turn, uses the natural
gas to satisfy supply commitments it has with a major Louisiana
utility. We have also furnished $2.2 million in letters of credit on
behalf of Evangeline.
o We pay EPIK for export services to load product cargoes for our NGL
and petrochemical marketing customers.
o We pay Dixie transportation fees for propane movements on their
system initiated by our NGL marketing activities.
o We sell high purity isobutane to BEF as a feedstock and purchase
certain of BEF's by-products. We also receive transportation fees
for MTBE movements on our HSC pipeline and fractionation revenues
for reprocessing mixed feedstock streams generated by BEF.
o We pay Promix for the transportation, storage and fractionation of
certain of our mixed NGL volumes. In addition, we sell natural gas
to Promix for their fuel requirements.
71
The following table summarizes our related party transactions with
unconsolidated affiliates for the years ended December 31, 2002, 2001 and 2000:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
REVENUES FROM CONSOLIDATED OPERATIONS
Evangeline $ 131,635 $ 117,283 $
EPIK 259 297 5,070
BEF 50,494 45,778 56,216
Promix 12,697 8,952 57
Other unconsolidated affiliates 1,182 1,374 645
OPERATING COSTS AND EXPENSES
EPIK 19,788 7,438 17,600
Dixie 12,184 12,695 11,763
BEF 9,794 8,073 10,640
Promix 18,408 12,676 18,200
Other unconsolidated affiliates 428 181
As part of Other Income and Expense as shown in our Statements of
Consolidated Operations and Comprehensive Income, we record dividend income from
our investment in VESCO.
ITEM 14. CONTROLS AND PROCEDURES.
In the 90-day period before the filing of this report, the CEO and CFO
of the General Partner of Enterprise Products Partners L.P. and Enterprise
Products Operating L.P. (collectively the "registrants") have evaluated the
effectiveness of the registrants' disclosure controls and procedures. These
disclosure controls and procedures are those controls and other procedures we
maintain, which are designed to insure that all of the information required to
be disclosed by the registrants in all of their combined and separate periodic
reports filed with the SEC is recorded, processed, summarized and reported,
within the time periods specified in the SEC's rules and forms. Disclosure
controls and procedures include, without limitation, controls and procedures
designed to ensure that information required to be disclosed by the registrants
in their reports filed or submitted under the Securities Exchange Act of 1934 is
accumulated and communicated to our management, including the CEO and CFO of the
General Partner, as appropriate to allow those persons to make timely decisions
regarding required disclosure.
Subsequent to the date when the disclosure controls and procedures were
evaluated, there have not been any significant changes in the registrants'
controls or procedures or in other factors that could significantly affect such
controls or procedures. No significant deficiencies or material weaknesses were
detected, so no corrective actions needed to be taken.
72
ITEM 15. 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.
EXHIBIT NO. EXHIBIT*
- ----------- --------------------------------------------------------------------------------------------------
2.1 -- Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P.
dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Form 8-K filed September
26, 2000).
2.2 -- Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and
Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to
Exhibit 10.1 to Form 8-K filed February 8, 2002.)
2.3 -- Purchase and Sale Agreement dated 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 (incorporated by reference to Exhibit 10.2 to Form 8-K filed February 8, 2002).
2.4 -- Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated
July 31, 2002 (incorporated by reference to Exhibit 2.2 to Form 8-K filed August 12, 2002).
2.5 -- Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002
(incorporated by reference to Exhibit 2.1 to Form 8-K filed August 12, 2002).
3.1 -- First Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC
dated as of September 17, 1999 (incorporated by reference to Exhibit 99.8 to the Form 8-K/A-l
filed October 27, 1999).
3.2** -- Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of the
General Partner dated as of September 19, 2002.
3.3 -- Third Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P.
dated May 15, 2002 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 13, 2002).
3.4 -- Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Enterprise
Products Partners L.P. dated August 7, 2002 (incorporated by reference to Exhibit 3.3 to Form
10-Q filed August 13, 2002).
3.5 -- Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Enterprise
Products Partners L.P. dated December 17, 2002 (incorporated by reference to Exhibit 3.5 to Form
8-K filed December 17, 2002).
3.6 -- Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated
as of July 31, 1998 (incorporated by reference to Exhibit 3.2 to Registration Statement on Form
S-1/A filed July 21, 1998).
4.1 -- 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
(incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
4.2 -- First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating
L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National
Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on
Form S-4 filed January 28, 2003).
4.3** -- Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating
L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National
Association, as Trustee.
4.4 -- Global Note representing $350 million principal amount of 6.375% Series A Senior Notes due 2013
with attached Guarantee (incorporated by reference to Exhibit 4.3 to Registration Statement on
Form S-4 filed January 28, 2003).
4.5** -- Rule 144 A Global Note representing $499.2 million principal amount of 6.875% Series A Senior
Notes due 2033 with attached Guarantee.
73
4.6** -- Regulation S Global Note representing $800,000 principal amount of 6.875% Series A Senior Notes
due 2033 with attached Guarantee.
4.7 -- Form of Global Note representing $350 million principal amount of 6.375% Series B Senior Notes
due 2013 with attached Guarantee (included in Exhibit 4.2).
4.8** -- Form of Global Note representing $500 million principal amount of 6.875% Series B Senior Notes
due 2033 with attached Guarantee (included in Exhibit 4.3).
4.9 -- Registration Rights Agreement dated as of January 22, 2003, among Enterprise Products Operating
L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein (incorporated by
reference to Exhibit 4.5 to Registration Statement on Form S-4 filed January 28, 2003).
4.10** -- Registration Rights Agreement dated as of February 14, 2003, among Enterprise Products Operating
L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein.
4.11 -- Global Note representing $350 million principal amount of 8.25% Senior Notes due 2005
(incorporated by reference to Exhibit 4.2 to Form 8-K filed March 10, 2000).
4.12 -- Global Note representing $450 million principal amount of 7.50% Senior Notes due 2011
(incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001).
4.13 -- Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to Registration
Statement on Form S-1/A; File No. 333-52537, filed July 21, 1998).
4.14 -- $250 Million Multi-Year Revolving Credit Facility dated as of November 17, 2000, among Enterprise
Products Operating L.P., First Union National Bank, as Administrative Agent, Bank One, NA, as
Documentation Agent, the Chase Manhattan Bank, as Syndication Agent, and the several banks from
time to time parties thereto, with First Union Securities, Inc. and Chase Securities Inc. as
Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 4.2 to Form
8-K filed January 24, 2001).
4.15 -- $150 Million 364-Day Revolving Credit Facility November 17, 2000, among Enterprise Products
Operating L.P., First Union National Bank, as Administrative Agent, Bank One, NA, as
Documentation Agent, the Chase Manhattan Bank, as Syndication Agent, and the several banks from
time to time parties thereto, with First Union Securities, Inc. and Chase Securities Inc. as
Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 4.3 to Form
8-K filed January 24, 2001).
4.16 -- Guaranty Agreement dated as of November 17, 2000, by Enterprise Products Partners L.P. in favor
of First Union National Bank, as Administrative Agent, with respect to the $250 Million
Multi-Year Revolving Credit Facility included as Exhibit 4.4 above (incorporated by reference to
Exhibit 4.4 to Form 8-K filed January 24, 2001).
4.17 -- Guaranty Agreement dated as of November 17, 2000, by Enterprise Products Partners L.P. in favor
of First Union National Bank, as Administrative Agent, with respect to the $150 Million 364-Day
Revolving Credit Facility (incorporated by reference to Exhibit 4.5 to Form 8-K filed January 24,
2001).
4.18 -- First Amendment to Multi-Year Credit Facility dated April 19, 2001 (incorporated by reference to
Exhibit 4.12 to Form 10-Q filed May 14, 2001).
4.19 -- Second Amendment to Multi-Year Revolving Credit Facility dated April 14, 2002 (incorporated by
reference to Exhibit 4.14 to Form 10-Q filed May 14, 2002).
4.20 -- Third Amendment to Multi-Year Revolving Credit Facility dated July 31, 2002 (incorporated by
reference to Exhibit 4.1 to Form 10-Q filed August 12, 2002).
4.21 -- Fourth Amendment to Multi-Year Revolving Credit Facility dated effective as of November 15, 2002
(incorporated by reference to Exhibit 4.21 to Form 10-Q filed November 13, 2002).
4.22 -- First Amendment to 364-Day Credit Facility dated November 6, 2001, effective as of November 16,
2001 (incorporated by reference to Exhibit 4.13 to Form 10-Q filed August 13, 2002).
4.23 -- Second Amendment to 364-Day Revolving Credit Facility dated April 24, 2002 (incorporated by
reference to Exhibit 4.15 to Form 10-Q filed May 14, 2002).
4.24 -- Third Amendment to 364-Day Revolving Credit Facility dated July 31, 2002 (incorporated by
reference to Exhibit 4.2 to Form 8-K filed August 12, 2002).
4.25 -- Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit "B" to
Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.26 -- Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit "E"
to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.27 -- Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit "C" to
74
Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
10.1 -- $1.2 Billion 364-Day Term Credit Facility dated as of July 31, 2002, among Enterprise Products
Operating Partnership L.P., Wachovia Bank, National Association, as Administrative Agent, Lehman
Commercial Paper Inc., as Co-Syndication Agent, Royal Bank of Canada, as Co- Syndication Agent
and Arranger, with Wachovia Securities, Inc. and Lehman Brothers Inc., as Lead Arrangers and
Joint Bookrunners and RBC Capital Markets, as Arranger (incorporated by reference to Exhibit 4.3
to Form 8-K filed August 12, 2002).
10.2 -- Guaranty Agreement dated as of July 31, 2002 by Enterprise Products Partners L.P. in favor of
Wachovia Bank, National Association, as Administrative Agent, with respect to the $1.2 Billion
364-Day Term Credit Facility (incorporated by reference to Exhibit 4.4 to Form 8-K filed August
12, 2002).
10.3 -- EPCO Agreement among Enterprise Products Partners L.P., Enterprise Products Operating L.P.,
Enterprise Products GP, LLC and Enterprise Products Company dated July 31, 1998 (incorporated by
reference to Exhibit 10.3 to Registration Statement on Form S-4 filed January 28, 2003).
10.4 -- Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation
Company dated June 1, 1998 (incorporated by reference to Exhibit 10.3 to Registration Statement
Form S-1/A filed July 8,1998).
10.5 -- Partnership Agreement among Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise
Products Company dated May 1, 1992 (incorporated by reference to Exhibit 10.5 to Registration
Statement on Form S-1 filed May 13, 1998).
10.6 -- Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules
Incorporated dated December 13, 1978 (incorporated by reference to Exhibit 10.9 to Registration
Statement on Form S-l filed May 13, 1998).
10.7 -- 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 (incorporated by reference to Exhibit 10.10 to
Registration Statement on Form S-l/A filed July 8,1998).
10.8 -- 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 (incorporated by
reference to Exhibit 10.12 to Registration Statement on Form S-l/A filed July 8, 1998).
10.9 -- 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 (incorporated by
reference to Exhibit 10.13 to Registration Statement on Form S-l/A filed July 8, 1998).
10.10 -- 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 (incorporated by reference to Exhibit 10.14 to Form 10-Q filed November 15, 1999).
10.11 -- 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. (incorporated by reference to Exhibit 10.13 to Form 10-Q filed August 13, 2001).
10.12*** -- Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to
Post-Effective Amendment No. 1 to Registration Statement on Form S-8 filed March 13, 2003).
10.13*** -- Form of Option Grant Award under the 1998 Long-Term Incentive Plan (incorporated by reference
to Exhibit 4.2 to Post-Effective Amendment No. 1 to Registration Statement on Form S-8 filed
March 13, 2003).
12.1** -- Computation of ratio of earnings to fixed charges for each of the five years ended
December 31, 2002, 2001, 2000, 1999 and 1998 for Enterprise Products Partners L.P.
12.2** -- Computation of ratio of earnings to fixed charges for each of the five years ended
December 31, 2002, 2001, 2000, 1999 and 1998 for Enterprise Products Operating L.P.
21.1** -- List of Subsidiaries of the Registrants.
23.1** -- Consent of Deloitte & Touche LLP.
75
99.1** -- Audited Balance Sheet of Enterprise Products GP, LLC, as of December 31, 2002.
99.2** -- Section 1350 Certifications
* With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for
Enterprise Products Partners L.P. is 1-14323 and the Commission file number for Enterprise Products Operating L.P. is
333-93239-01.
** Filed with this report.
*** Identifies management contract and compensatory plan arrangements
(b) Reports on Form 8-K.
October 2, 2002 filing: (Items 5 and 7) We filed the General Partner's
audited balance sheet as of December 31, 2001 and unaudited balance sheet as of
June 30, 2002.
October 3, 2002 filing: (Items 5 and 7) On October 2, 2002, we entered
into an underwriting agreement for a public offering of 9,800,000 Common Units.
This included 1,809,200 common units to be offered to members of our senior
management and affiliates. The underwriters were granted an option to purchase
up to 1,470,000 additional partnership units to cover over-allotments.
December 11, 2002 filing: (Items 5 and 7) On December 11, 2002, we
filed the General Partner's September 30, 2002 unaudited balance sheet.
December 17, 2002 filing: (Items 5, 7 and 9) On December 17, 2002, we
announced that our partnership agreement was amended to eliminate the General
Partner's incentive distribution right to receive 50% of total cash
distributions with respect to that portion of quarterly cash distributions that
exceed $0.392 per unit.
December 31, 2002 filing: (Item 7) On December 31, 2002, we filed
certain pro forma consolidated financial statements and accompanying notes. The
pro forma financial statements included in this Form 8-K reflected strategic
acquisitions completed since January 2001 and the Common Unit offering we
completed in October 2002.
76
INDEX TO FINANCIAL STATEMENTS
Page
----
ENTERPRISE PRODUCTS PARTNERS L.P.
Independent Auditors' Report F-2
Consolidated Balance Sheets as of December 31, 2002 and 2001 F-3
Statements of Consolidated Operations and Comprehensive Income
for the Years Ended December 31, 2002, 2001 and 2000 F-4
Statements of Consolidated Cash Flows
for the Years Ended December 31, 2002, 2001 and 2000 F-5
Statements of Consolidated Partners' Equity
for the Years Ended December 31, 2002, 2001 and 2000 F-6
Notes to Consolidated Financial Statements F-7
Supplemental Schedules:
Schedule II - Valuation and Qualifying Accounts F-52
ENTERPRISE PRODUCTS OPERATING L.P.
Independent Auditors' Report F-53
Consolidated Balance Sheets as of December 31, 2002 and 2001 F-54
Statements of Consolidated Operations and Comprehensive Income
for the Years Ended December 31, 2002, 2001 and 2000 F-55
Statements of Consolidated Cash Flows
for the Years Ended December 31, 2002, 2001 and 2000 F-56
Statements of Consolidated Partners' Equity
for the Years Ended December 31, 2002, 2001 and 2000 F-57
Notes to Consolidated Financial Statements F-58
Supplemental Schedules:
Schedule II - Valuation and Qualifying Accounts F-97
All schedules, except those 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
To the Board of Directors of Enterprise Products GP, LLC
(the General Partner of 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, 2002 and 2001, and the related statements of consolidated
operations and comprehensive income, consolidated cash flows and consolidated
partners' equity for each of the three years in the period ended December 31,
2002. 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, 2002 and 2001, and the results of its consolidated operations and
its consolidated cash flows for each of the three years in the period ended
December 31, 2002 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.
The Company changed its method of accounting for goodwill in 2002 and
for derivative financial instruments in 2001. These changes are discussed in
Notes 8 and 1, respectively, to the consolidated financial statements.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 7, 2003
F-2
ENTERPRISE PRODUCTS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
DECEMBER 31,
------------------------------------
ASSETS 2002 2001
------------------------------------
CURRENT ASSETS
Cash and cash equivalents (includes restricted cash of $8,751 at
December 31, 2002 and $5,752 at December 31, 2001) $ 22,568 $ 137,823
Accounts and notes receivable - trade, net of allowance for doubtful accounts
of $21,196 at December 31, 2002 and $20,642 at December 31, 2001 399,187 256,024
Accounts receivable - affiliates 228 4,375
Inventories 167,369 62,942
Prepaid and other current assets 48,216 51,110
------------------------------------
Total current assets 637,568 512,274
PROPERTY, PLANT AND EQUIPMENT, NET 2,810,839 1,306,790
INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES 396,993 398,201
INTANGIBLE ASSETS, NET OF ACCUMULATED AMORTIZATION OF $25,546 AT
DECEMBER 31, 2002 AND $13,084 AT DECEMBER 31, 2001 277,661 202,226
GOODWILL 81,547
DEFERRED TAX ASSET 15,846
OTHER ASSETS 9,818 5,201
------------------------------------
TOTAL $ 4,230,272 $ 2,424,692
====================================
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt $ 15,000
Accounts payable - trade $ 67,283 $ 54,269
Accounts payable - affiliates 40,772 29,885
Accrued gas payables 489,562 227,035
Accrued expenses 35,760 22,460
Accrued interest 30,338 24,302
Other current liabilities 42,641 44,764
------------------------------------
Total current liabilities 721,356 402,715
LONG-TERM DEBT 2,231,463 855,278
OTHER LONG-TERM LIABILITIES 7,666 8,061
MINORITY INTEREST 68,883 11,716
COMMITMENTS AND CONTINGENCIES
PARTNERS' EQUITY
Common Units (141,694,766 Units outstanding at December 31, 2002 and
102,721,830 at December 31, 2001) 949,835 651,872
Subordinated Units (32,114,804 Units outstanding at December 31, 2002 and
42,819,740 at December 31, 2001) 116,288 193,107
Special Units (10,000,000 Units outstanding at December 31, 2002 and
29,000,000 December 31, 2001) 143,926 296,634
Treasury Units acquired by Trust, at cost (859,200 Common Units outstanding
at December 31, 2002 and 327,200 at December 31, 2001) (17,808) (6,222)
General Partner 12,223 11,531
Accumulated Other Comprehensive Loss (3,560)
------------------------------------
Total Partners' Equity 1,200,904 1,146,922
------------------------------------
TOTAL $ 4,230,272 $ 2,424,692
====================================
See Notes to Consolidated Financial Statements
F-3
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED OPERATIONS
AND COMPREHENSIVE INCOME
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
FOR YEAR ENDED DECEMBER 31,
-------------------------------------------------
2002 2001 2000
-------------------------------------------------
REVENUES
Revenues from consolidated operations
Third parties $ 3,102,066 $ 2,641,913 $ 2,689,541
Related parties 482,717 512,456 359,479
-------------------------------------------------
Total revenues 3,584,783 3,154,369 3,049,020
-------------------------------------------------
COST AND EXPENSES
Operating costs and expenses
Third parties 2,686,982 2,052,309 1,953,341
Related parties 695,579 809,434 847,719
Selling, general and administrative
Third parties 18,686 10,347 12,665
Related parties 24,204 19,949 15,680
-------------------------------------------------
Total costs and expenses 3,425,451 2,892,039 2,829,405
-------------------------------------------------
EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES 35,253 25,358 24,119
-------------------------------------------------
OPERATING INCOME 194,585 287,688 243,734
-------------------------------------------------
OTHER INCOME (EXPENSE)
Interest expense (101,580) (52,456) (33,329)
Interest income from related parties 139 31 1,787
Dividend income from unconsolidated affiliates 4,737 3,462 7,091
Interest income - other 2,313 7,029 3,748
Other, net (113) (1,104) (272)
-------------------------------------------------
Other income (expense) (94,504) (43,038) (20,975)
-------------------------------------------------
INCOME BEFORE PROVISION FOR
INCOME TAXES AND MINORITY INTEREST 100,081 244,650 222,759
PROVISION FOR INCOME TAXES (1,634)
-------------------------------------------------
INCOME BEFORE MINORITY INTEREST 98,447 244,650 222,759
MINORITY INTEREST (2,947) (2,472) (2,253)
-------------------------------------------------
NET INCOME 95,500 242,178 220,506
Cumulative transition adjustment related to financial instruments
recorded upon adoption of SFAS No. 133 (see Note 1) (42,190)
Reclassification of cumulative transition adjustment to earnings 42,190
Change in fair value of financial instruments
recorded as cash flow hedges (3,560)
-------------------------------------------------
COMPREHENSIVE INCOME $ 91,940 $ 242,178 $ 220,506
=================================================
ALLOCATION OF NET INCOME TO:
Limited partners $ 84,837 $ 236,570 $ 217,909
=================================================
General partner $ 10,663 $ 5,608 $ 2,597
=================================================
BASIC EARNINGS PER UNIT
Income before minority interest $ 0.56 $ 1.71 $ 1.64
=================================================
Net income per Common and Subordinated unit $ 0.55 $ 1.70 $ 1.62
=================================================
DILUTED EARNINGS PER UNIT
Income before minority interest $ 0.50 $ 1.40 $ 1.34
=================================================
Net income per Common, Subordinated
and Special unit $ 0.48 $ 1.39 $ 1.32
==================================================
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,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
OPERATING ACTIVITIES
Net income $ 95,500 $ 242,178 $ 220,506
Adjustments to reconcile net income to cash flows provided
by (used for) operating activities:
Depreciation and amortization in operating costs and expenses 86,029 48,775 35,621
Depreciation in selling, general and administrative costs 77 2,341 1,689
Amortization in interest expense 8,819 787 3,735
Equity in income of unconsolidated affiliates (35,253) (25,358) (24,119)
Distributions received from unconsolidated affiliates 57,662 45,054 37,267
Leases paid by EPCO 9,033 10,309 10,537
Minority interest 2,947 2,472 2,253
Loss (gain) on sale of assets (1) (390) 2,270
Deferred income tax expense 2,080
Changes in fair market value of financial
instruments (see Note 18) 10,213 (5,697)
Net effect of changes in operating accounts 92,655 (37,143) 71,111
---------------------------------------------------
Operating activities cash flows 329,761 283,328 360,870
---------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (72,135) (149,896) (243,913)
Proceeds from sale of assets 165 568 92
Business acquisitions, net of cash received (1,620,727) (225,665)
Acquisition of intangible asset (2,000)
Collection of note receivable from unconsolidated affiliate 6,519
Investments in and advances to unconsolidated affiliates (13,651) (116,220) (31,496)
---------------------------------------------------
Investing activities cash flows (1,708,348) (491,213) (268,798)
---------------------------------------------------
FINANCING ACTIVITIES
Borrowings under debt agreements 1,968,000 449,717 598,818
Repayments of debt (637,000) (490,000)
Debt issuance costs (19,329) (3,125) (4,043)
Distributions paid to partners (214,869) (164,308) (139,577)
Distributions paid to minority interest by Operating Partnership (3,324) (1,687) (1,429)
Contributions from minority interest 1,976 105 108
Common Units repurchased and retired (770)
Proceeds from issuance of Common Units 180,666
Treasury Units purchased (12,788) (18,003)
Treasury Units reissued 22,600
Increase in restricted cash (2,999) (5,752)
---------------------------------------------------
Financing activities cash flows 1,260,333 279,547 (36,893)
---------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (118,254) 71,662 55,179
CASH AND CASH EQUIVALENTS, JANUARY 1 132,071 60,409 5,230
---------------------------------------------------
CASH AND CASH EQUIVALENTS, DECEMBER 31 $ 13,817 $ 132,071 $ 60,409
===================================================
See Notes to Consolidated Financial Statements
F-5
ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED PARTNERS' EQUITY
(DOLLARS IN THOUSANDS, SEE NOTE 10 FOR UNIT HISTORY)
LIMITED PARTNERS
----------------------------------------
COMMON SUBORD. SPECIAL TREASURY GENERAL ACCUM.
UNITS UNITS UNITS UNITS PARTNER OCI TOTAL
----------------------------------------------------------------------------------------------
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
Special Units issued to Shell
under contingency agreement 55,241 557 55,798
Conversion of 2.0 million Shell
Special Units to Common Units 14,513 (14,513) -
Common Units repurchased
and retired (687) (43) (32) (8) (770)
Cash distributions to partners (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
Special Units issued to Shell
under contingency agreement 117,066 1,183 118,249
Conversion of 10.0 million
Shell Special Units to Common
Units 72,554 (72,554)
Cash distributions to partners (109,969) (49,510) (4,829) (164,308)
Treasury Units purchased (18,003) (18,003)
Treasury Units reissued 16,508 16,508
Gain on reissuance of Treasury
Units by consolidated Trust 3,518 1,461 990 61 6,030
Cumulative transition
adjustment recorded per
SFAS No. 133 $ (42,190) (42,190)
Reclassification of cumulative
transition adjustment to
earnings 42,190 42,190
----------------------------------------------------------------------------------------------
Balance, December 31, 2001 651,872 193,107 296,634 (6,222) 11,531 - 1,146,922
Net income 69,636 15,201 10,663 95,500
Leases paid by EPCO 6,872 2,071 90 9,033
Conversion of 19.0 million
Shell Special Units to
Common Units 152,708 (152,708) -
Conversion of 10.7 million EPCO
Subord. Units to Common Units 44,265 (44,265) -
Cash distributions to partners (153,449) (49,564) (11,856) (214,869)
Proceeds from issuance of
Common Units in October 2002 178,859 1,807 180,666
Treasury Units purchased (12,788) (12,788)
Treasury Units reissued to
satisfy EPCO Unit option plans (928) (262) 1,202 (12) -
Change in fair value of financial
instruments recorded as
cash flow hedges (see Note 18) (3,560) (3,560)
----------------------------------------------------------------------------------------------
Balance, December 31, 2002 $ 949,835 $ 116,288 $ 143,926 $ (17,808) $ 12,223 $ (3,560) $1,200,904
==============================================================================================
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" within these notes 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 24,000,000 Common Units at
$11 per unit. We received approximately $243.3 million net of underwriting
commissions and offering costs.
The consolidated financial statements include our accounts and those of
our majority-owned subsidiaries in which we have a controlling interest, after
elimination of all material intercompany accounts and transactions. The
majority-owned subsidiaries are identified based upon the determination that the
Company possesses a controlling financial interest through direct or indirect
ownership of a majority voting interest in the subsidiary. 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.
Equity method investments are evaluated for impairment whenever events
or changes in circumstances indicate that there is a loss in value of the
investment which is other than a temporary decline. The Company considers events
affecting its equity method investments such as if they had continuing operating
losses or significant and long-term changes in their industry conditions as
examples of indicators of potential impairment. In the event that we determine
that the loss in value of an investment is other than a temporary decline, we
would record a charge to earnings to adjust the carrying value to fair value. We
had no such impairment charges for 2002, 2001 and 2000.
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.
In May 2002, we completed a two-for-one split of each class of our
partnership Units. All references to number of Units or earnings per Unit
contained in this document reflect the Unit split, unless otherwise indicated.
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.
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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. Treasury Units are not considered to be outstanding;
therefore, they are excluded from the computation of both basic and diluted
earnings per Unit. See Notes 10 and 13 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, 2002 were not significant to the
consolidated financial statements. Costs of environmental compliance and
monitoring aggregated $1.7 million, $1.3 million and $1.3 million for the years
ended December 31, 2002, 2001 and 2000, 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 Promix, Dixie, Neptune, La Porte and Nemo. The excess cost of
these investments is reflected in our investments in and advances to
unconsolidated affiliates for these entities. See Note 7 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 accounts
receivable, and volumes loaned to us under such agreements are accrued as a
liability in accrued gas payables.
FINANCIAL INSTRUMENTS such as swaps, forward and other contracts to
manage the price risks associated with inventories, firm commitments, interest
rates and certain anticipated transactions are used by the Company. We recognize
our transactions on the balance sheet as assets and liabilities based on the
instrument's fair value. 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. Changes in fair value of
financial instrument contracts are recognized currently in earnings unless
specific hedge accounting criteria are met. If the financial instruments meet
those criteria, the instrument's gains and losses offset related results of the
hedge item in the income statement for a fair value hedge and are deferred in
other comprehensive income for a cash flow hedge. Gains and losses on a cash
flow hedge are reclassified into earnings when the forecasted transaction
occurs. A contract designated as a hedge of an anticipated transaction that is
no longer likely to occur is immediately recognized in earnings.
To qualify as a hedge, the item to be hedged must expose us to
commodity or interest rate risk and the hedging instrument must reduce the
exposure and meet the hedging requirements of SFAS No. 133. We must formally
designate the financial instrument as a hedge and document and assess the
effectiveness of the hedge at inception and on a quarterly basis. Any
ineffectiveness is recorded into earnings immediately.
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
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recorded in Other Comprehensive Income ("OCI"). The amount in OCI was fully
reclassified to earnings during 2001.
GOODWILL consists of the excess of amounts we paid for businesses and
assets over the respective fair value of the underlying net assets purchased
(see Note 8). Since adopting SFAS No. 142, "Goodwill and Other Intangible
Assets", on January 1, 2002, our goodwill amounts are no longer amortized but
will be assessed annually for recoverability. In addition, we will periodically
review the reporting units to which the goodwill amounts relate if impairment
indicators are evident. If such indicators are present (i.e., loss of a
significant customer, economic obsolescence of plant assets, etc.), the fair
value of the reporting unit, including its related goodwill, will be calculated
and compared to its combined book value. If the fair value of the reporting unit
exceeds its book value, goodwill is not considered impaired and no adjustment to
earnings would be required. Should the fair value of the reporting unit
(including its goodwill) be less than its book value, a charge to earnings would
be recorded to adjust goodwill to its implied fair value. We have not recognized
any impairment losses related to our goodwill for any of the periods presented.
INVENTORIES primarily consist of NGL, petrochemical and natural gas
volumes and are valued at the lower of average cost or market (see Note 5).
Shipping and handling charges directly related to volumes we purchase or to
which we take ownership are capitalized as costs of inventory. As these
inventories are sold and delivered out of inventory, the average cost of these
products (which includes freight-in charges which have been capitalized) are
charged to current period operating costs and expenses. Shipping and handling
charges for products we sell and deliver to customers are charged to operating
costs and expenses as incurred.
INTANGIBLE ASSETS consist primarily of the estimated value of contract
rights we own arising from agreements with customers (see Note 8). A
contract-based intangible asset with a finite useful life is amortized over its
estimated useful life, which is the period over which the asset is expected to
contribute directly or indirectly to the future cash flows of the entity. It is
based on an analysis of all pertinent factors including (a) the expected use of
the asset by the entity, (b) the expected useful life of related assets (i.e.,
fractionation facility, storage well, etc.), (c) any legal, regulatory or
contractual provisions, including renewal or extension periods that would not
cause substantial costs or modifications to existing agreements, (d) the effects
of obsolescence, demand, competition, and other economic factors and (e) the
level of maintenance required to obtain the expected future cash flows.
LONG-LIVED ASSETS (including intangible assets with finite useful lives
and property, plant and equipment) 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.
Long-lived assets with recorded values that are not expected to be
recovered through future cash flows are written-down to estimated fair value in
accordance with SFAS No. 144 "Accounting for the Impairment or Disposal of
Long-Lived Assets." Under SFAS No. 144, an asset shall be tested for impairment
when events or circumstances indicate that its carrying value may not be
recoverable. The carrying value of a long-lived asset is not recoverable if it
exceeds the sum of the undiscounted cash flows expected to result from the use
and eventual disposition of the asset. If the carrying value exceeds the sum of
the undiscounted cash flows, an impairment loss equal to the amount the carrying
value exceeds the fair value of the asset is recognized. Fair value is generally
determined from estimated discounted future net cash flows. We adopted SFAS No.
144 on January 1, 2002, and there have been no events or circumstances
indicating that the carrying value of any of our assets may not be recoverable.
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. 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) as expansion capital expenditures.
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PROVISION FOR INCOME TAXES is only applicable to the tax obligation of
our Seminole pipeline business, which is a corporation and the only entity
subject to income taxes in the consolidated group. The income tax provision
relates solely to Seminole's earnings before income taxes for the five month
period ended December 31, 2002. Deferred income tax assets and liabilities for
Seminole are recognized for temporary differences between the assets and
liabilities for financial reporting and tax purposes (see Note 12).
In and of itself, our limited partnership structure is not subject to
federal income taxes. As a result, our earnings or losses for Federal income
tax purposes are included in the tax returns of the individual partners. 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.
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, 2002 and
2001, cash and cash equivalents includes $8.8 million and $5.8 million of
restricted cash related to these requirements, respectively.
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. For additional information regarding our revenue recognition process,
please see Note 2.
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. Our allowance amount is generally determined as a
percentage of revenues for the last twelve months. Our procedure for recording
an allowance for doubtful accounts is based on historical experience, financial
stability of our customers and levels of credit granted to customers. In
addition, we may also increase the allowance account in response to specific
identification of customers involved in bankruptcy proceedings and those
experiencing financial uncertainties. We routinely review our estimates in this
area to ascertain that we have recorded sufficient reserves to cover forecasted
losses. Our allowance for doubtful accounts was $21.2 million and $20.6 million
at December 31, 2002 and 2001, respectively.
UNIT OPTION PLAN ACCOUNTING for reimbursement to EPCO under its 1998
Plan is accounted for by applying APB Opinion No. 25, "Accounting for Stock
Issued to Employees," in accounting for equity-based awards granted to EPCO's
employees whereby no compensation expense is recorded related to the options
granted when the exercise price equals the market price of the underlying
equity issue on the date of grant. See Note 15 for the pro forma effect on our
net income and earnings per unit, as if compensation expense had been
determined based on the Black-Scholes option pricing model value at the grant
date for Unit option awards consistent with the provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation." No compensation expense was recorded
during the years ended December 31, 2002, 2001 and 2000, since the options were
granted at exercise prices equal to the market prices at the date of grant.
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. REVENUE RECOGNITION
The following summarizes our revenue recognition process by business
segment:
Pipelines segment revenues. In our Pipelines segment, we enter into
pipeline, storage and product handling contracts. Under our NGL, petrochemical
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
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transported, whichever the case may be, multiplied by the volume delivered. The
throughput fee is generally contractual or as regulated by various governmental
agencies, including the Federal Energy Regulatory Commission ("FERC").
Additionally, we have product sales contracts associated with our natural gas
pipeline business whereby revenue is recognized when we sell and deliver a
volume of natural gas to a customer. These natural gas sales contracts are
based upon market-related prices as determined by the individual agreements.
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 product handling contracts (applicable to our
import and export operations) are recorded once the services have been
performed with the applicable fees stated in the individual contracts.
Fractionation segment revenues. In our Fractionation segment, we enter
into NGL fractionation, isomerization and propylene fractionation tolling
arrangements, NGL fractionation in-kind contracts and propylene fractionation
sales contracts. Under our tolling arrangements, we recognize revenue upon
completion of all contract services and obligations. These tolling arrangements
typically include a base processing fee per gallon (or other unit of
measurement) subject to adjustment for changes in natural gas, electricity and
labor costs, which are the principal variable costs of fractionation and
isomerization operations. At certain of our NGL fractionation facilities, an
in-kind tolling arrangement is utilized. An in-kind processing contract allows
us to retain a contractually-determined percentage of NGL products fractionated
for our customer in lieu of collecting a cash tolling fee per gallon.
Fractionation revenue is recognized and recorded on a monthly basis for
transfers of "in-kind" retained NGL products to the NGL working inventory
maintained within our Processing segment where it is then held for sale.
Transfer pricing for these retained NGLs is based upon monthly market posted
prices for such products. This intersegment revenue and offsetting cost to the
Processing segment is eliminated in our reporting of consolidated revenues and
expenses. In our propylene fractionation product sales contracts, we recognize
revenue once the products have been delivered to the customer. Pricing for
sales contracts is based upon market-related prices as determined by the
individual agreements.
Processing segment revenues. As part of our Processing business, we
have entered into a significant 20-year natural gas processing agreement with
Shell (the "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 natural gas processing 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 natural gas processing contract stipulates that we retain a
percentage of the extracted NGLs as payment for our services, revenue is
recognized and recorded when the extracted NGLs are delivered out of our
inventory and sold to customers on sales contracts. Our NGL marketing
activities within this segment also use product sales contracts to sell and
deliver out of inventory the NGLs transferred to it as a result of the
Fractionation segment's in-kind arrangements and those it purchases for cash in
the open market. These NGL sales contracts may include forward product sales
contracts from time-to-time. Revenues from NGL sales contracts are recognized
and recorded upon the delivery of the NGL products specified in each individual
contract. Pricing terms in these sales contracts are based upon market-related
prices for such products and can include pricing differentials due to factors
such differing delivery locations.
Octane Enhancement segment revenues. 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. Gross operating margin for this
segment consists of our equity earnings from BEF, which in turn is dependent
upon is BEF's general revenue recognition policy. BEF's operations primarily
occur as a result of a contract with Sunoco, Inc. ("Sun") whereby Sun is
obligated to purchase
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all of the facility's MTBE output at market-related prices through September
2004. BEF recognizes its revenue once the product has been delivered to Sun.
Other segment revenues. Revenues shown for our Other segment are
primarily derived from 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 in our revenue recognition process. 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 routine nature of these
estimates.
3. RECENTLY ISSUED ACCOUNTING STANDARDS
We adopted SFAS No. 142, "Goodwill and Other Intangible Assets", on
January 1, 2002. This standard establishes accounting standards for all
goodwill and other intangible assets recognized in our consolidated balance
sheet. In addition, we adopted SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" on January 1, 2002. This statement addresses
financial accounting and reporting for the impairment and/or disposal of
long-lived assets. For information regarding our goodwill and intangible assets
see Note 8. For information regarding our accounting policy for long-lived
assets, please see Note 1.
We adopted SFAS No. 143, "Accounting for Asset Retirement
Obligations," on January 1, 2003. This statement establishes accounting
standards for the recognition and measurement of a liability for an asset
retirement obligation ("ARO") and the associated asset retirement cost. An ARO
exists when a company determines that it has a clearly defined legal obligation
upon retirement of a long-lived asset or any component part thereof and that
the legal obligation will lead to the future payment of funds to a third party
upon retirement of the asset. In general, legal obligations underlying AROs
result from enacted laws and regulations or from contractual provisions related
to long-lived assets. AROs can also arise through the normal course of
operating a long-lived fixed asset.
An ARO liability will be recorded on the balance sheet if a reasonable
estimate of fair value of the obligation can be made. Our estimate of fair
value for each ARO is primarily dependent upon a clearly defined plan of
retirement (dates, methods, etc.) and costs associated with the retirement
activity. If a reasonable estimate cannot be made (i.e., no current or required
plans for retirement of the asset, etc.), footnote disclosure is required but
the ARO is not recorded until a reasonable estimate can be made. Any earnings
impact resulting from the recognition of an ARO upon adoption of SFAS No. 143
should be reflected as the cumulative effect of a change in accounting
principle.
Upon adoption of SFAS No. 143, we reviewed our long-lived assets for
ARO's by segment. We identified, but have not recognized, ARO liabilities in
several operational areas. These include ARO liabilities related to easements
over property not currently owned by us. Our rights to the easements are
renewable and only require retirement action upon nonrenewal of the easement
agreements. We currently plan to renew all such easement agreements and use
these properties indefinitely. Therefore, the ARO liability is not estimable
for such easements. If we decide not to renew these agreements, an ARO
liability would be recorded at that time.
ARO liabilities related to statutory regulatory requirements for
abandonment or retirement of certain currently operated facilities were also
identified. We currently have no intention or legal obligation to abandon or
retire such facilities. An ARO liability would be recorded if future
abandonment or retirement occurred.
Certain Gulf of Mexico natural gas pipelines, in which we have an
equity interest, have identified ARO's relating to regulatory requirements.
There is no current intention to abandon or retire these pipelines. If these
pipelines were abandoned or retired, an ARO liability would then be disclosed.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." This standard requires companies
to recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to exit or disposal plan.
Examples of costs covered by the
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standard include lease termination costs and certain employee severance costs
that are associated with a restructuring, discontinued operations, plant
closing, or other exit or disposal activity. Previous accounting guidance was
provided by EITF Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." SFAS No. 146 replaces Issue 94-3. SFAS No.
146 is to be applied prospectively to exit or disposal activities initiated
after December 31, 2002. We adopted this statement on January 1, 2003 and
determined that it had no material impact on our financial statements.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements from Guarantees, Including Indirect
Guarantees of Indebtedness of Others". This interpretation of SFAS No. 5, 57
and 107, and rescission of FASB Interpretation No. 34 elaborates on the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued.
It also clarifies that a guarantor is required to recognize, at the inception
of a guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. The initial recognition and measurement provisions of
this interpretation are applicable on a prospective basis to guarantees issued
or modified after December 31, 2002. The disclosure requirements in this
interpretation are applicable for financial statements of interim or annual
periods after December 15, 2002. See Note 9 for the disclosure of
Parent-Subsidiary guarantor relationships.
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation-Transition and Disclosure," which provides alternative
methods of transition from a voluntary change to the fair value based method of
accounting for stock-based employee compensation. In addition, SFAS No. 148
amends the disclosure requirements of SFAS No. 123 in both annual and interim
financial statements. SFAS No. 148 is effective for financial statements for
fiscal years ending after December 15, 2002, and financial reports containing
condensed financial statements for interim periods beginning after December 15,
2002. EPCO has stock-based employee compensation plans for which we have a
funding commitment for certain employees, see Note 15. We do not believe that
the adoption of this statement will have a material effect on our financial
statements.
4. BUSINESS ACQUISITIONS
ACQUISITION OF MID-AMERICA AND SEMINOLE IN JULY 2002
On July 31, 2002, we acquired equity interests in affiliates of
Williams, which in turn, own controlling interests in Mid-America Pipeline
Company, LLC ("Mid-America," formerly Mid-America Pipeline Company) and
Seminole Pipeline Company ("Seminole"). The purchase price of the acquisitions
was approximately $1.2 billion. The acquisition of Mid-America and Seminole
significantly enhances our existing asset base by:
o accessing NGL-rich natural gas production in major North American
natural gas producing regions;
o expanding our integrated natural gas and NGL network;
o providing access to new end markets for NGL products; and
o increasing our gross margins from fee-based businesses.
In addition to our current strategic position in the Gulf of Mexico,
we now have access to major supply basins throughout North America, including
the Rocky Mountain Overthrust, the San Juan and Permian basins, the
Mid-Continent region and, through third-party pipeline connections, north into
Canada's Western Sedimentary basin. The combination of these assets with our
existing assets also creates a significant link between Mont Belvieu, Texas and
Conway, Kansas, the two largest NGL hubs in the United States. They also
provide additional access to new end markets for NGL products.
The acquisitions include a 98% ownership interest in Mapletree, LLC,
which is the sole owner of Mid-America and certain propane terminals and
storage facilities. Mid-America owns a regulated 7,226-mile major NGL pipeline
system (the "Mid-America Pipeline System") consisting of three NGL pipelines:
the 2,548-mile Rocky Mountain pipeline, the 2,740-mile Conway North pipeline,
and the 1,938-mile Conway South pipeline. The Rocky Mountain system transports
mixed NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to the
Hobbs hub located on the Texas-New Mexico border. The Conway North segment
links the large NGL hub at Conway, Kansas to refineries and propane markets in
the upper Midwest. In addition, the Conway North segment has access to, through
third-party pipeline connections, NGL supplies from Canada's Western
Sedimentary basin.
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The Conway South system connects the Conway hub with Kansas refineries and
transports mixed NGLs from Conway, Kansas to the Hobbs hub (with
interconnections to the Seminole Pipeline System at the Hobbs hub).
We also acquired a 98% ownership interest in E-Oaktree, LLC, owner of
an 80% equity interest in Seminole. Seminole owns a regulated 1,281-mile
pipeline (the "Seminole Pipeline System") that transports mixed NGLs and NGL
products from the Hobbs hub on the Texas-New Mexico border and the Permian
Basin area to Mont Belvieu, Texas. The primary source of throughput for the
Seminole system are those volumes originating from the Mid-America system.
The initial funding for these acquisitions was accomplished by
entering into a $1.2 billion 364-day credit facility (the "364-Day Term Loan";
see Note 9 for a description of this debt). This temporary credit facility was
extinguished in February 2003 when we completed our plans for the permanent
financing of these acquisitions (see our discussion of subsequent events in
Note 21). These acquisitions did not require any material governmental
approvals.
ACQUISITION OF DIAMOND-KOCH PROPYLENE FRACTIONATION BUSINESS IN FEBRUARY 2002
In February 2002, we purchased various propylene fractionation assets
and certain inventories of refinery grade propylene, propane, and polymer grade
propylene from Diamond-Koch. These include a 66.7% interest in a polymer grade
propylene fractionation facility located in Mont Belvieu, Texas (the "Splitter
III" facility), a 50% 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. Splitter III has the capacity to produce approximately 41
MBPD of polymer grade propylene. These assets are part of our Mont Belvieu
propylene fractionation operations, which is part of the Fractionation segment.
The purchase price of $239.0 million was funded by a drawdown on our Multi-Year
and 364-Day Revolving Credit facilities.
ACQUISITION OF DIAMOND-KOCH STORAGE BUSINESS IN JANUARY 2002
In January 2002, we purchased various hydrocarbon storage assets from
Diamond-Koch. The storage facility consists of 25 operational salt dome storage
caverns with a useable capacity of 64 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
and serve the largest petrochemical and refinery complex in the United States.
These assets are part of our Mont Belvieu storage operations, which is part of
the Pipelines segment. The purchase price of $129.6 million was funded by
utilizing cash on hand.
OTHER MINOR ACQUISITIONS COMPLETED DURING 2002
We completed the purchase of an additional interest in our Mont
Belvieu NGL fractionator from ChevronTexaco, the acquisition of a gas
processing plant and NGL fractionator in Louisiana from Western Resources and
certain NGL terminal assets from CornerStone during 2002. Due to the immaterial
nature of each of these acquisitions, our discussion of each is limited to the
following:
Acquisition of ChevronTexaco's interest in our Mont Belvieu NGL
fractionator. Effective June 2002,, we finalized the acquisition of a 12.5%
undivided ownership interest in our Mont Belvieu, Texas NGL fractionator from
an affiliate of ChevronTexaco. The purchase price of approximately $8.1 million
was paid in May 2002. As a result of this transaction, our ownership interest
in the Mont Belvieu NGL fractionator increased to 75.0% from 62.5%.
Acquisition of gas processing and NGL fractionator assets from Western
Gas Resources, Inc. Effective June 2002, we acquired a 160 MMcf/d natural gas
processing plant, a 14.2 MBPD NGL fractionator and supporting assets (including
contracts) from Western Gas Resources, Inc. for approximately $32.6 million.
The "Toca-Western" facilities are located in St. Bernard Parish, Louisiana near
our existing Toca natural gas processing plant.
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Acquisition of NGL terminals from CornerStone. In November 2002, we
purchased four NGL terminals and existing propane inventories from an affiliate
of CornerStone for approximately $11.5 million. The terminals are located in
Bakersfield and Rocklin, California; Reno, Nevada and Albertville, Alabama. In
addition, we acquired storage facilities related to these terminals with a
capacity of 0.1 million barrels. These terminals will support our NGL marketing
activities and fee-based marketing services.
ACADIAN GAS POST-CLOSING ADJUSTMENTS COMPLETED IN APRIL 2002
In April 2002, we finalized the post-closing purchase price adjustment
associated with our April 2001 acquisition of Acadian Gas. Acadian Gas was
acquired from an affiliate of Shell and is involved in the purchase, sale,
transportation and storage of natural gas in Louisiana. As a result, we paid
Shell $18.0 million for various working capital items, the majority of which
were related to natural gas inventories.
ALLOCATION OF AMOUNTS PAID DURING 2002
The acquisitions and post-closing adjustments described previously
were accounted for under the purchase method of accounting and, accordingly,
the cost of each has been allocated to the assets acquired and liabilities
assumed based on their estimated fair values as follows:
D-K
D-K PROPYLENE MID-AMERICA
STORAGE FRACTIONATION AND SEMINOLE OTHER TOTAL
------------------------------------------------------------------------
Accounts and Notes receivable $ 11,777 $ (120) $ 11,657
Accounts receivable - affiliates 7,799 7,799
Inventories $ 4,994 10,776 4,403 20,173
Prepaids and other current assets $ 890 3,148 9,204 416 13,658
Property, plant and equipment 120,571 96,772 1,265,264 24,636 1,507,243
Investments in unconsolidated affiliates 7,550 7,550
Intangible assets 8,127 53,000 31,229 92,356
Goodwill 73,691 73,691
Deferred tax asset 17,307 17,307
Other assets 2,699 2,699
Accounts payable - affiliates (7,799) (7,799)
Accrued expenses (5,529) (5,529)
Accrued interest (667) (667)
Other current liabilities (107) (12,226) 8,581 (3,752)
Long-term debt (60,000) (60,000)
Other long-term (90) (90)
Minority interest (55,569) (55,569)
------------------------------------------------------------------------
Total purchase price $ 129,588 $ 239,048 $1,182,946 $ 69,145 $1,620,727
========================================================================
The fair value estimates for both Diamond-Koch transactions;
Mid-America and Seminole; the Toca-Western and CornerStone acquisitions were
developed by independent appraisers using recognized business valuation
techniques. The Mid-America, Seminole and CornerStone allocations are
preliminary pending completion of a final review of these businesses which is
expected to be completed during the first quarter of 2003. The purchase price
allocations related to the Acadian Gas post-closing adjustment and the
acquisition of ChevronTexaco's interest in our Mont Belvieu NGL fractionator
are based on previously issued fair value reports.
The purchase price paid for the propylene fractionation business
resulted in goodwill of $73.7 million. The goodwill primarily represents the
value management has attached to future earnings improvements and to the
strategic location of the assets. Earnings from the propylene business are
expected to improve substantially from the last few years with the years 2005
and 2006 projected to be peak years in the petrochemical business cycle based
on industry forecasts. The propylene fractionation assets are located in Mont
Belvieu, Texas on the Gulf Coast, the largest natural gas liquids and
petrochemical marketplace in the U.S. The assets have access to substantial
supply from major Gulf Coast and central U.S. producers of refinery grade
propylene. The polymer grade products
F-15
produced at the facility have competitive advantages because of distribution
direct to customers via affiliated pipelines and through an affiliated export
facility. For additional information regarding our goodwill, see Note 8.
COMBINED PRO FORMA EFFECT OF MID-AMERICA, SEMINOLE, DIAMOND-KOCH AND
ACADIAN GAS BUSINESS ACQUISITIONS
The following table presents unaudited pro forma financial information
incorporating the historical (pre-acquisition) financial results of the
following acquired businesses:
o D-K storage (acquired January 1, 2002) and propylene fractionation
(acquired February 1, 2002);
o Mid-America and Seminole (both acquired July 31, 2002); and
o Acadian Gas (acquired April 1, 2001).
Our historical Statements of Consolidated Operations and Comprehensive
Income reflect the operations of each acquired business since their respective
acquisition dates.
The following pro forma information has been prepared as if the
acquisitions had been completed on January 1 of the respective periods
presented as opposed to the actual dates that these acquisitions occurred. The
pro forma information is based upon data currently available to and certain
estimates and assumptions made by management. As a result, this information is
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.
Pro forma net income for each year includes (among other pro forma
adjustments) the impact of interest expense associated with the 364-Day Term
Loan we used to fund the Mid-America and Seminole acquisitions. The pro forma
results for 2001 assume that the initial $1.2 billion borrowed under this
facility was outstanding during the entire year. The pro forma results for 2002
reflect our actual repayment of a portion of this debt using proceeds and
contributions related to our October 2002 equity offering. The pro forma
earnings data do not reflect our January 2003 equity offering nor the Operating
Partnership's January 2003 issuance of Senior Notes C or February 2003 issuance
of Senior Notes D. The proceeds from these fiscal 2003 equity and debt
offerings were used to fully repay the 364-Day Term Loan by the end of February
2003. For additional information regarding these subsequent events, see Note
21.
F-16
FOR YEAR ENDED DECEMBER 31,
---------------------------------------
2002 2001
---------------------------------------
PRO FORMA EARNINGS DATA
Revenues $ 3,784,286 $ 3,952,896
Operating income 275,272 384,381
Net income $ 130,528 $ 252,241
Income before minority interest $ 137,391 $ 259,629
Less: General partner interest (11,013) (5,708)
---------------------------------------
Net income before minority interest available
to Limited Partners 126,378 253,921
Less: Minority interest (6,863) (7,387)
---------------------------------------
Net income available to Limited Partners $ 119,515 $ 246,534
=======================================
PRO FORMA BASIC EARNINGS PER UNIT
Numerator:
Net income before minority interest available
to Limited Partners $ 126,378 $ 253,921
Net income available to Limited Partners $ 119,515 $ 246,534
Denominator, weighted-average Units outstanding 155,454 139,452
Pro forma diluted earnings per Unit:
Net income before minority interest available
to Limited Partners $ 0.81 $ 1.82
Net income available to Limited Partners $ 0.77 $ 1.77
PRO FORMA DILUTED EARNINGS PER UNIT
Numerator:
Net income before minority interest available
to Limited Partners $ 126,378 $ 253,921
Net income available to Limited Partners $ 119,515 $ 246,534
Denominator, weighted-average Units outstanding 176,490 170,786
Pro forma basic earnings per Unit:
Net income before minority interest available
to Limited Partners $ 0.72 $ 1.49
Net income available to Limited Partners $ 0.68 $ 1.44
5. INVENTORIES
Our inventories were as follows at the dates indicated:
DECEMBER 31,
-------------------------------------
2002 2001
-------------------------------------
Working inventory $ 131,769 $ 29,393
Forward-sales inventory 35,600 33,549
-------------------------------------
Inventory $ 167,369 $ 62,942
=====================================
A description of each inventory is as follows:
o Our regular trade (or "working") inventory is comprised of inventories of
natural gas, NGLs and petrochemical products that are available for sale.
This inventory is valued at the lower of average cost or market, with
"market" being determined by industry-related posted prices such as those
published by OPIS and CMAI.
o The forward-sales inventory is comprised of segregated NGL volumes
dedicated to the fulfillment of forward sales contracts and is valued at
the lower of average cost or market, with "market" being defined as
F-17
the weighted-average sales price for NGL volumes to be delivered in future
months on the forward sales contracts.
In general, our inventory values reflect amounts we have paid for
product purchases, freight charges associated with such purchase volumes,
terminal and storage fees, vessel inspection and demurrage charges and other
handling and processing costs. In those instances where we take ownership of
inventory volumes through in-kind and similar arrangements (as opposed to
actually purchasing volumes for cash from third parties, see Note 2), these
volumes are valued at market-related prices during the month in which they are
acquired. Like the third-party purchases described above, we inventory the
various ancillary costs such as freight-in and other handling and processing
amounts associated with owned volumes obtained through our in-kind and similar
contracts.
Due to fluctuating market conditions in the NGL, natural gas and
petrochemical industry, we occasionally recognize lower of average cost or
market ("LCM") adjustments when the cost of our inventories exceed their net
realizable value. These non-cash adjustments are charged to operating costs and
expenses in the period they are recognized and generally affect our segment
operating results in the following manner:
o NGL inventory write-downs are recorded as a cost of the Processing
segment's NGL marketing activities;
o Natural gas inventory write downs are recorded as a cost of the
Pipeline segment's Acadian Gas operations; and
o Petrochemical inventory write downs are recorded as a cost of the
Fractionation segment's petrochemical marketing activities.
For the years ended December 31, 2002, 2001 and 2000, we recognized LCM
adjustments of approximately $6.3 million, $40.7 million and $6.9 million,
respectively. The majority of these write-downs were taken against NGL
inventories. To the extent our commodity hedging strategies address
inventory-related risks and are successful, these inventory valuation
adjustments are mitigated (or in some cases, offset). See Note 18 for a
description of our commodity hedging activities.
6. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment and accumulated depreciation were as
follows at the dates indicated:
ESTIMATED DECEMBER 31,
USEFUL LIFE -------------------------------------
IN YEARS 2002 2001
---------------------------------------------------
Plants and pipelines 5-35 $ 2,860,180 $ 1,398,843
Underground and other storage facilities 5-35 283,114 127,900
Transportation equipment 3-35 5,118 3,736
Land 23,817 15,517
Construction in progress 49,586 98,844
-------------------------------------
Total 3,221,815 1,644,840
Less accumulated depreciation 410,976 338,050
-------------------------------------
Property, plant and equipment, net $ 2,810,839 $ 1,306,790
=====================================
Depreciation expense for the years ended December 31, 2002, 2001 and
2000 was $72.5 million, $43.4 million and $33.3 million, respectively.
7. 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 business segments, see Note
20. The following table shows our investments in and advances to unconsolidated
affiliates at:
F-18
DECEMBER 31,
OWNERSHIP ----------------------------------------
PERCENTAGE 2002 2001
----------------------------------------------------------
Accounted for on equity basis:
Fractionation:
BRF 32.25% $ 28,293 $ 29,417
BRPC 30.00% 17,616 18,841
Promix 33.33% 41,643 45,071
La Porte 50.00% 5,737
OTC 50.00% 2,178
Pipeline:
EPIK 50.00% 11,114 14,280
Wilprise 37.35% 8,566 8,834
Tri-States 33.33% 25,552 26,734
Belle Rose 41.67% 11,057 11,624
Dixie 19.88% 36,660 37,558
Starfish 50.00% 28,512 25,352
Neptune 25.67% 77,365 76,880
Nemo 33.92% 12,423 12,189
Evangeline 49.50% 2,383 2,578
Octane Enhancement:
BEF 33.33% 54,894 55,843
Accounted for on cost basis:
Processing:
VESCO 13.10% 33,000 33,000
----------------------------------------
Total $ 396,993 $ 398,201
========================================
The following table shows our equity in income (loss) of
unconsolidated affiliates for the periods indicated:
FOR YEAR ENDED DECEMBER 31,
OWNERSHIP ---------------------------------------------------
PERCENTAGE 2002 2001 2000
--------------------------------------------------------------------
Fractionation:
BRF 32.25% $ 2,427 $ 1,583 $ 1,369
BRPC 30.00% 997 1,161 (284)
Promix 33.33% 3,936 4,201 5,306
La Porte 50.00% (559)
OTC 50.00% 378
Pipelines:
EPIK 50.00% 4,688 345 3,273
Wilprise 37.35% 948 472 497
Tri-States 33.33% 1,959 1,565 2,499
Belle Rose 41.67% 203 103 301
Dixie 19.88% 1,231 2,092 751
Starfish 50.00% 7,346 4,122
Ocean Breeze 25.67% - 32
Neptune 25.67% 2,111 4,081
Nemo 33.92% 1,077 75
Evangeline 49.50% (58) (145)
Octane Enhancement:
BEF 33.33% 8,569 5,671 10,407
---------------------------------------------------
Total $ 35,253 $ 25,358 $ 24,119
===================================================
F-19
At December 31, 2002, our share of accumulated earnings of equity
method unconsolidated affiliates that had not been remitted to us was
approximately $15.4 million. In addition, our initial investment in Promix, La
Porte, Dixie, Neptune and Nemo exceeded our share of the historical cost of the
underlying net assets of such entities ("excess cost"). The excess cost of
these investments is reflected in our investments in and advances to
unconsolidated affiliates for these entities. The excess cost amounts related
to Promix, La Porte and Nemo are attributable to the tangible plant and
pipeline assets of each entity, and are amortized against equity earnings from
these entities in a manner similar to depreciation. The excess cost of Dixie
includes amounts attributable to both goodwill and tangible pipeline assets,
with the portion assigned to the pipeline assets being amortized in a manner
similar to depreciation. The goodwill inherent in Dixie's excess cost is
subject to periodic impairment testing; therefore, it and is not amortized. The
following table summarizes our excess cost information:
UNAMORTIZED BALANCE AT AMORTIZATION
INITIAL --------------------------------------- CHARGED AGAINST
EXCESS DECEMBER 31, DECEMBER 31, EQUITY EARNINGS AMORTIZATION
COST 2002 2001 DURING 2002 PERIOD
------------------------------------------------------------------------------------------
Fractionation segment:
Promix $ 7,955 $ 6,596 $ 7,083 $ 398 20 years
La Porte 873 833 n/a 40 35 years
Pipelines segment:
Dixie
Attributable to pipeline assets 28,448 26,074 26,887 813 35 years
Goodwill 9,246 8,827 8,827 n/a n/a
Neptune 12,768 12,039 12,404 365 35 years
Nemo 727 697 718 21 35 years
As used in the following condensed financial data, gross operating
margin represents operating income before applicable depreciation and
amortization expense and selling, general and administrative costs. Gross
operating margin is an important measure of the profitability of assets owned
by our unconsolidated affiliates. We regularly evaluate our consolidated
operations on the same basis. Operating income represents earnings before
non-operating income and expense items such interest expense and interest
income. The equity earnings we record from these investments represent our
share of the net income of each.
FRACTIONATION SEGMENT:
At December 31, 2002, the Fractionation segment included the following
unconsolidated affiliates accounted for using the equity method:
o Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25%
interest in an NGL fractionator located in southeastern Louisiana.
o Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% interest
in a propylene fractionator located in southeastern Louisiana.
o K/D/S Promix LLC ("Promix") - a 33.33% interest in an NGL
fractionator and related storage and pipeline assets located in south
Louisiana.
o La Porte Pipeline Company, L.P. and La Porte Pipeline GP, LLC
(collectively "La Porte") - an aggregate 50% interest in a private
polymer grade propylene pipeline extending from Mont Belvieu, Texas
to La Porte, Texas. We do not exercise management control over La
Porte and are precluded from consolidating its financial statements
with our financial statements.
o Olefins Terminal Corporation ("OTC") - a 50% interest in a polymer
grade propylene export facility located in Seabrook, Texas. As with
La Porte, we do not exercise management control over OTC and are
precluded from consolidating its financial statements with our
financial statements.
F-20
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 OF OR FOR THE
YEAR ENDED DECEMBER 31,
-----------------------------------------------
2002 2001 2000
-----------------------------------------------
BALANCE SHEET DATA:
Current assets $ 23,496 $ 27,424
Property, plant and equipment, net 250,096 251,519
--------------------------------
Total assets $ 273,592 $ 278,943
================================
Current liabilities $ 11,229 $ 9,950
Other liabilities 6,800
Combined equity 255,563 268,993
--------------------------------
Total liabilities and combined equity $ 273,592 $ 278,943
================================
INCOME STATEMENT DATA:
Revenues $ 78,350 $ 76,480 $ 71,287
Gross operating margin 40,215 36,321 33,240
Operating income 23,464 22,396 19,997
Net income 23,399 22,738 20,661
PIPELINES SEGMENT:
At December 31, 2002, our Pipelines operating segment included the
following unconsolidated affiliates accounted for using the equity method:
o EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively,
"EPIK") - a 50% aggregate interest in an NGL export terminal located
in southeast Texas. In March 2003, we purchased the remaining
ownership interests in EPIK for $19 million plus certain post-closing
purchase price adjustments, at which time EPIK became a consolidated
subsidiary of ours (see Note 21). Prior to our purchase of the
remaining interests, we did not exercise management control over EPIK
and were precluded from consolidating its financial statements with
our financial statements.
o Wilprise Pipeline Company, LLC ("Wilprise") - a 37.35% interest in an
NGL pipeline system located in southeastern Louisiana.
o Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33%
interest in an NGL pipeline system located in Louisiana, Mississippi
and Alabama.
o Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.67% interest in an
NGL pipeline system located in south Louisiana.
o 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.
o 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. We do not exercise management control over Starfish and
are precluded from consolidating its financial statements with our
financial statements.
o 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.
o 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.
o 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.
F-21
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,
-----------------------------------------------
2002 2001 2000
-----------------------------------------------
BALANCE SHEET DATA:
Current assets $ 76,930 $ 68,325
Property, plant and equipment, net 510,483 515,327
Other assets 47,501 50,265
--------------------------------
Total assets $ 634,914 $ 633,917
================================
Current liabilities $ 60,484 $ 62,347
Other liabilities 56,230 57,965
Combined equity 518,200 513,605
--------------------------------
Total liabilities and combined equity $ 634,914 $ 633,917
================================
INCOME STATEMENT DATA:
Revenues $ 303,567 $ 305,404 $ 96,270
Gross operating margin 112,455 98,682 51,414
Operating income 65,855 54,459 41,757
Net income 56,736 41,015 31,241
OCTANE ENHANCEMENT SEGMENT:
At December 31, 2002, 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 will reduce
the demand for MTBE and could have an adverse effect on our results of
operations.
In recent years, MTBE has been detected in municipal and private water
supplies resulting in various legal actions. BEF has not been named in any MTBE
legal action to date. In light of these developments, we and the other two
partners of BEF are actively compiling a contingency plan for the BEF facility
should MTBE be banned. We are currently evaluating a possible conversion of the
facility from MTBE production to alkylate production. In addition to MTBE's
value in reducing air pollution, it is a significant source of octane in the
U.S. motor gasoline pool. Octane is a critical component of motor gasoline.
Therefore, 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 gasoline and that alkylate would be an economic and effective
substitute. We are currently conducting a detailed engineering study that is
expected to be completed by the end of 2003, at which time we expect a more
definitive conversion cost estimate will be available. The cost to convert the
facility will depend on the type of alkylate process chosen and level of
alkylate production desired by the partnership.
F-22
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,
-----------------------------------------------
2002 2001 2000
-----------------------------------------------
BALANCE SHEET DATA:
Current assets $ 37,237 $ 29,301
Property, plant and equipment, net 129,019 140,009
Other assets 9,050 10,067
--------------------------------
Total assets $ 175,306 $ 179,377
================================
Current liabilities $ 16,787 $ 13,352
Other liabilities 4,017 3,438
Partners' equity 154,502 162,587
--------------------------------
Total liabilities and Partners' equity $ 175,306 $ 179,377
================================
INCOME STATEMENT DATA:
Revenues $ 229,358 $ 213,734 $ 258,180
Gross operating margin 71,537 28,701 43,328
Operating income 25,461 15,984 30,529
Net income 25,707 17,014 31,220
PROCESSING SEGMENT:
At December 31, 2002, 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 natural gas processing plant, fractionation facilities, storage, and
gas gathering pipelines in the Gulf of Mexico. We account for this investment
using the cost method. As part of Other Income and Expense as shown in our
Statements of Consolidated Operations and Comprehensive Income, we record
dividend income from our investment in VESCO.
8. INTANGIBLE ASSETS AND GOODWILL
INTANGIBLE ASSETS
The following table summarizes our intangible assets at December 31,
2002 and 2001:
AT DECEMBER 31, 2002 AT DECEMBER 31, 2001
-------------------------- --------------------------
GROSS ACCUM. CARRYING ACCUM. CARRYING
VALUE AMORT. VALUE AMORT. VALUE
------------- -------------------------- --------------------------
Shell natural gas processing agreement $ 206,331 $ (23,015) $ 183,201 $ (11,962) $ 194,369
Mont Belvieu Storage II contracts 8,127 (232) 7,895
Mont Belvieu Splitter III contracts 53,000 (1,388) 51,612
Toca-Western natural gas processing contracts 11,096 (326) 10,861
Toca-Western NGL fractionation contracts 20,041 (585) 19,457
Venice contracts (a) 4,639 4,635
MBA acquisition goodwill (b) 8,979 (1,122) 7,857
------------- -------------------------- --------------------------
Total $ 312,213 $ (25,546) $ 277,661 $ (13,084) $ 202,226
============= ========================== ==========================
- ------------------------------------------------------------------------------
(a) Amortization will commence when contracted-volumes begin to be processed
in 2003.
(b) Amount reclassified to Goodwill on January 1, 2002 per transition
provisions of SFAS 142.
F-23
At December 31, 2002, our intangible assets consisted of:
o the Shell natural gas processing agreement that we acquired as part
of the TNGL acquisition in August 1999;
o certain storage and propylene fractionation contracts we acquired in
connection with the Diamond-Koch acquisitions in January and February
2002;
o certain natural gas processing and NGL fractionation contracts we
acquired in connection with the Toca-Western acquisition in June
2002; and
o certain NGL-related contracts (the "Venice contracts") we acquired
during the third quarter of 2002.
The following table shows amortization expense associated with our
intangible assets for the years ended December 31, 2002, 2001 and 2000:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------
2002 2001 2000
---------------------------------------
Shell natural gas processing agreement $ 11,054 $ 7,260 $ 3,576
Mont Belvieu Storage II contracts 232
Mont Belvieu Splitter III contracts 1,388
Toca-Western natural gas processing contracts 326
Toca-Western NGL fractionation contracts 585
MBA acquisition goodwill (a) 449 453
---------------------------------------
Total $ 13,585 $ 7,709 $ 4,029
=======================================
- -------------------------------------------------------------------------------
(a) Our MBA acquisition goodwill is no longer subject to amortization under
SFAS 142 guidelines.
The value of the Shell natural gas processing agreement is being
amortized on a straight-line basis over the remainder of its initial 20-year
contract term (currently $11.1 million annually from 2002 through 2019). The
values of the propylene fractionation and storage contracts acquired from
Diamond-Koch are being amortized on a straight-line basis over the economic
life of the assets to which they relate, which is currently estimated at 35
years. The Toca-Western natural gas processing contracts are being amortized
over the expected 20-year remaining life of the natural gas supplies supporting
these contracts. The value of the Toca-Western NGL fractionation contracts is
being amortized over the expected 20-year remaining life of the assets to which
they relate. The value of the Venice contracts will be amortized over 14 years
beginning in the third quarter of 2003.
For 2003, amortization expense attributable to these intangible assets
is currently estimated at $14.5 million. Based on information currently
available, we expect that amortization expense relating to existing intangibles
will increase to $14.7 million during each of the years 2004 through 2007.
GOODWILL
At December 31, 2002, the value of goodwill was $81.5 million. Our
goodwill is attributable to the excess of the purchase price over the fair
value of assets acquired and is comprised of the following (values as of
December 31, 2002):
o $73.6 million associated with the purchase of propylene fractionation
assets from Diamond-Koch in February 2002; and,
o $7.9 million related to the July 1999 purchase of an additional
ownership interest in MBA, which in turn owned an interest in our
Mont Belvieu NGL fractionation facility.
Our goodwill amounts are classified as part of the Fractionation
segment since they are related to assets recorded in this operating segment. At
December 31, 2001, the goodwill associated with the MBA acquisition was
recorded as part of our intangible assets.
Since our adoption of SFAS No. 142 on January 1, 2002, our goodwill
amounts are no longer amortized but are assessed annually for recoverability.
Prior to adoption of SFAS No. 142, the only goodwill amortization we recorded
was that associated with the MBA acquisition from July 1999. Due to the
immaterial nature of such
F-24
amortization expense (approximately $0.4 million per year), the pro forma effect
of not amortizing this goodwill in 2001 or 2000 would have had a negligible
effect on our net income and earnings per Unit (both basic and diluted).
9. DEBT OBLIGATIONS
Our debt consisted of the following at:
DECEMBER 31,
----------------------------------
2002 2001
----------------------------------
Borrowings under:
364-Day Term Loan, variable rate, due July 2003 $ 1,022,000
364-Day Revolving Credit facility, variable rate,
due November 2004 99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005 225,000
Senior Notes A, 8.25% fixed rate, due March 2005 350,000 $ 350,000
Senior Notes B, 7.50% fixed rate, due February 2011 450,000 450,000
MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
Seminole Notes, 6.67% fixed rate, $15 million due
each December, 2002 through 2005 45,000
----------------------------------
Total principal amount 2,245,000 854,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 1,774 1,653
Less unamortized discount on:
Senior Notes A (81) (117)
Senior Notes B (230) (258)
Less current maturities of debt (15,000) -
----------------------------------
Long-term debt $ 2,231,463 $ 855,278
==================================
The table above does not reflect the issuance of our $350 million
principal amount Senior Notes C in January 2003 and $500 million principal
amount Senior Notes D in February 2003 nor does it reflect the repayment of
debt using proceeds from our January 2003 equity offering. We used a
combination of proceeds from the issuance of Senior Notes C and D and the
January 2003 equity offering to completely repay the 364-Day Term Loan by the
end of February 2003 (see the section titled "General description of
debt--364-Day Term Loan" within this note for additional information regarding
the use of proceeds to extinguish this debt). For additional information
regarding subsequent events affecting our debt balances, see Note 21.
As to the assets of our subsidiary, Seminole Pipeline Company, our
$2.2 billion in senior indebtedness at December 31, 2002 is structurally
subordinated and ranks junior in right of payment to the $45 million of
indebtedness of Seminole Pipeline Company. In accordance with SFAS No. 6,
"Classification of Short-Term Obligations Expected to Be Refinanced", long-term
and current maturities of debt at December 31, 2002 reflect the classification
of such debt obligations at March 7, 2003.
LETTERS OF CREDIT
At December 31, 2002, we had a total of $75 million of standby letters
of credit capacity under our Multi-Year Revolving Credit facility, of which
$2.4 million was outstanding.
PARENT-SUBSIDIARY GUARANTOR RELATIONSHIPS
Enterprise Products Partners L.P. (the "MLP", on a stand-alone basis)
acts as guarantor of certain of the Operating Partnership's debt obligations.
These parent-subsidiary guaranty provisions exist under all of our debt
obligations with the exception of the Seminole Notes. The Seminole Notes are
unsecured obligations solely of
F-25
Seminole Pipeline Company. If the Operating Partnership were to default on any
guaranteed debt obligation, the MLP would be responsible for full payment of
that obligation.
GENERAL DESCRIPTION OF DEBT
The following is a summary of the significant aspects of our debt
obligations at December 31, 2002.
364-Day Term Loan. The Operating Partnership entered into a $1.2
billion senior unsecured 364-day term loan to fund the Mid-America and Seminole
acquisitions in July 2002. We applied proceeds of $178.8 million from our
October 2002 equity offering to partially repay this loan. We used $252.8
million of the $258.9 million in proceeds from the January 2003 equity
offering, $347.0 million of the $347.7 million in proceeds from our issuance of
Senior Notes C and $421.4 million in proceeds from our issuance of Senior Notes
D to completely repay the 364-Day Term Loan by end of February 2003 (see Note
21). Base variable interest rates under this facility generally bore interest
at either (1) the greater of (a) the Prime Rate or (b) the Federal Funds
Effective Rate plus one-half percent or (2) a Eurodollar rate. Whichever base
interest rate we selected, the rate was increased by an appropriate applicable
margin (as defined within the loan agreement). During 2002, the
weighted-average interest rate charged was 3.10%, with the range of rates being
between 4.88% and 2.88%. This facility contained various covenants similar to
those of our revolving credit facilities. We were in compliance with these
covenants at December 31, 2002.
364-Day Revolving Credit facility. In November 2000, , our Operating
Partnership entered in a 364-Day revolving credit agreement. Currently, the
stand-alone borrowing capacity under this credit facility is $230 million with
the maturity date for any amount outstanding being November 2003. We have the
option to convert any revolving credit balance outstanding at maturity to a
one-year term loan (due November 2004) in accordance with the terms of the
credit agreement. This credit facility is guaranteed by the MLP through an
unsecured guarantee. In addition, our borrowings under this bank credit
facility are unsecured general obligations and are non-recourse to the General
Partner. We applied $60.0 million in proceeds from our February 2003 issuance
of Senior Notes D to reduce the balance outstanding under this facility during
2003 (see Note 21).
As defined by the credit agreement, variable interest rates charged
under this facility generally bear interest at either (1) the greater of (a)
the Prime Rate or (b) the Federal Funds Effective Rate plus one-half percent or
(2) a Eurodollar rate plus an applicable margin or (3) a Competitive Bid Rate.
We elect the basis of the interest rate at the time of each borrowing. During
2002, the weighted-average interest rate charged for borrowings under this
facility was 2.51%, with the range of rates being between 4.75% and 2.37%.
The 364-Day Revolving Credit facility agreement contains various
covenants related to our ability to incur certain indebtedness; grant certain
liens; enter into certain merger or consolidation transactions; and make
certain investments. The loan agreement also requires us to satisfy certain
financial covenants at the end of each quarter. As defined within the
agreement, we must maintain a specified level of consolidated net worth and
certain financial ratios. We were in compliance with these covenants at
December 31, 2002. The MLP has entered into an unsecured and unsubordinated
guarantee of this debt. This debt is non-recourse to the General Partner.
Multi-Year Revolving Credit facility. In conjunction with the 364-Day
Revolving Credit facility, our Operating Partnership entered into a five-year
revolving credit facility that includes a sublimit capacity of $75 million for
standby letters of credit. Currently, the stand-alone borrowing capacity under
this credit facility is $270 million. This credit facility is guaranteed by the
MLP through an unsecured guarantee. In addition, our borrowings under this bank
credit facility are unsecured general obligations and are non-recourse to the
General Partner. The interest rates charged under this facility are determined
in the same manner as that described under our 364-Day Revolving Credit
facility. During 2002, the weighted-average interest rate charged for
borrowings under this facility was 2.37%, with the range of rates being between
4.75% and 2.00%.
This facility contains various covenants similar to those of our
364-Day Revolving Credit facility. (please refer to our discussion regarding
restrictive covenants of the "364-Day Revolving Credit facility" within this
"General description of debt" section). We were in compliance with these
covenants at December 31, 2002.
F-26
Senior Notes A and B. These fixed-rate notes are an unsecured
obligation of the Operating Partnership and rank equally with its existing and
future unsecured and unsubordinated indebtedness. They are senior to any future
subordinated indebtedness. Both notes are guaranteed by the MLP through an
unsecured and unsubordinated guarantee and are non-recourse to the General
Partner. These notes were issued under an indenture containing certain
covenants and are subject to a make-whole redemption right. 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
covenants at December 31, 2002.
MBFC Loan. In connection with the construction of our Pascagoula,
Mississippi natural gas processing plant, our Operating Partnership entered
into a ten-year fixed-rate loan with the Mississippi Business Finance
Corporation ("MBFC"). This loan is subject to a make-whole redemption right and
is guaranteed by MLP through an unsecured and unsubordinated guarantee. The
indenture agreement for this loan contains an acceleration clause whereby the
outstanding principal and interest on the loan may become due and payable
within 120 days 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 within the loan agreement)
may, and if requested to do so by holders of at least 25% of the principal
amount of the underlying bonds, accelerate the maturity of the MBFC Loan.
Should this acceleration occur, the entire principal balance of the MBFC Loan
and all related accrued and unpaid interest would become immediately due and
payable. If such an event occurred, we would have the option of (1) to redeem
the MBFC Loan or (2) to provide an alternate credit agreement to support our
obligation under the MBFC Loan. We would have 120 days to exercise these
options upon receiving notice of the decline in our credit ratings.
The MBFC Loan agreement contains certain covenants including the
maintenance of appropriate levels of insurance on the Pascagoula facility and
restrictions regarding mergers. We were in compliance with these covenants at
December 31, 2002.
Seminole Notes. As a result of our acquisition of 78.4% of Seminole in
July 2002, we are required to consolidate its debt with our other debt
obligations. At December 31, 2002, Seminole had $45 million in fixed-rate
senior unsecured notes, of which $15 million is due annually each December
through December 2005. The Seminole notes contain various covenants, such as
minimum net worth requirements and those restricting Seminole's ability to
borrow additional funds. Seminole was in compliance with these covenants at
December 31, 2002.
10. CAPITAL STRUCTURE
Our Common Units, Subordinated Units and the convertible Special Units
represent limited partner interests in the Company, which entitle the holders
thereof to participate in distributions and exercise the rights or privileges
available to limited partners under our Third Amended and Restated Agreement of
Limited Partnership (the "Partnership Agreement"; together with any amendments
thereto). Our outstanding Common Units are listed on the New York Stock
Exchange under the symbol "EPD". Subordinated Units and Special Units are
non-voting until their conversion to Common Units.
On February 27, 2002, our General Partner approved a two-for-one split
of each class of the partnership Units. The partnership Unit split was
accomplished by distributing one additional partnership Unit for each
partnership Unit outstanding to holders of record on April 20, 2002. The Units
were distributed on May 15, 2002. In October 2002, we completed a public
offering of 9,800,000 Common Units from which we received net proceeds before
offering expenses of approximately $183.3 million, including our General
Partner's $3.6 million in capital contributions. The proceeds from this
offering were primarily used to repay debt. In January 2003, we completed a
public offering of 14,662,500 Common Units from which we received net proceeds
of approximately $258.9 million, including our General Partner's $5.3 million
in capital contributions (see Note 21).
Our 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
F-27
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. On December 17, 2002, we amended our Partnership Agreement to eliminate
the General Partner's right to receive 50% of the total cash distributions with
respect to that portion of quarterly cash distributions that exceeds $0.392 per
Unit. Under the terms of this amendment, our General Partner capped its
incentive distribution rights at 25% of the total cash distributions with
respect to that portion of quarterly cash distributions that exceeds $0.3085
per Unit. No consideration was paid to the General Partner to give up this
right. As amended, the General Partner's quarterly incentive distribution
thresholds are as follows:
o 1% of quarterly cash distributions up to $0.253 per Units;
o 14.1% of quarterly cash distributions that exceed $0.253 per
Unit up to $0.3085 per Unit; and
o 24.2% of quarterly cash distributions that exceed $0.3085 per
Unit.
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 or an
equivalent number of securities ranking on a parity with our Common Units,
without the approval of the holders of at least a Unit Majority. This
limitation does not apply to the issuance of Common Units upon conversion of
EPCO's Subordinated Units, issuances pursuant to employee benefit plans, the
conversion of the General Partner interest as a result of its withdrawal, or
issuances in connection with acquisitions or capital improvements that are
accretive on a pro forma per Unit basis (as defined within the Partnership
Agreement). 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. For those
acquisitions and other transactions that do not meet the aforementioned
exceptions, we have 54,550,000 Units available (and unreserved) at December 31,
2002 for general partnership purposes during the Subordination Period.
Subordinated Units. The 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 these may undergo an
early conversion into Common Units should certain criteria be satisfied. As a
result of meeting the initial criteria, 10,704,936 Subordinated Units (or 25%)
converted into Common Units on May 1, 2002. Should the remaining criteria
continue to be satisfied through the first quarter of 2003, an additional 25%
of these Units would undergo an early conversion into Common Units on May 1,
2003. After that, the remaining 50% would convert on August 1, 2003 if the
balance of the conversion requirements are 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 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 29 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 12 million
Special Units to Shell - 6.0 million were issued in August 2000 and 6.0 million
in August 2001 under a contingent unit agreement. Of the cumulative 41 million
Special Units issued, 31 million have already converted
F-28
to Common Units (2.0 million in August 2000, 10.0 million in August 2001 and
19.0 million in August 2002). The remaining 10.0 million Special Units will
convert to Common Units on a one for one basis in August 2003. These
conversions have a dilutive impact on basic earnings per Unit since they
increase the number of Common Units used in the computation. 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.
Under the rules of the New York Stock Exchange, the conversion of
Special Units into Common Units required the approval of a majority of Common
Unitholders. An affiliate of EPCO, which owns in excess of 55% of the
outstanding Common Units, voted its Units in favor of such conversion, which
provided the necessary votes for approval.
Treasury Units. During the first quarter of 1999, the Operating
Partnership established the EPOLP 1999 Grantor Trust (the "1999 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 1999 Trust is included in
our consolidated financial statements. The Common Units purchased by the 1999
Trust are accounted for in a manner similar to treasury stock under the cost
method of accounting. For the purpose of calculating both basic and diluted
earnings per Unit (see Note 13), Treasury Units held by the Company and the
1999 Trust are not considered to be outstanding.
The 1999 Trust purchased 792,800 Common Units during 2001 at a cost of
$18.0 million and 100,000 Common Units during 2002 at a cost of $2.4 million.
In November 2001, the 1999 Trust sold 1,000,000 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 was credited to Partners' Equity accounts in a manner similar to additional
paid-in capital. At December 31, 2002, the 1999 Trust held 427,200 Common Units
that are classified as Treasury Units.
Beginning in July 2000 and later modified in September 2001, the
General Partner authorized the Company (specifically, "Enterprise Products
Partners L.P.", in this context) and the 1999 Trust to repurchase up to two
million of our publicly-held Common Units (the "Buy-Back Program"). The
repurchases will be made during periods of temporary market weakness at price
levels that would be accretive to our remaining Unitholders. Under the terms of
the original Buy-Back Program, Common Units repurchased by the Company were to
be retired and Common Units repurchased by the 1999 Trust were to remain
outstanding and be accounted for as Treasury Units.
In April 2002, management modified the Buy-Back Program to treat
Common Units repurchased by the Company as Treasury Units. For accounting
purposes, Units repurchased by the Company will be held in treasury . The
Company purchased 432,000 Common Units during 2002 at a cost of $10.3 million.
At December 31, 2002, an additional 618,400 Common Units could be repurchased
under the Buy-Back Program.
During 2002, 51,959 Common Units were reissued from treasury at their
weighted-average cost of $1.2 million to fulfill our obligations under certain
employee Common Unit option agreements of EPCO.
F-29
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, 1999 90,571,430 42,819,740 29,000,000 534,400
Additional Special Units issued to
Coral Energy, LLC in connection
with contingency agreement 6,000,000
Conversion of 2.0 million Coral
Energy, LLC Special Units to
Common Units 2,000,000 (2,000,000)
Units repurchased and retired in
connection with buy-back program (56,800)
--------------------------------------------------------------
Balance, December 31, 2000 92,514,630 42,819,740 33,000,000 534,400
Additional Special Units issued to
Coral Energy, LLC in connection
with contingency agreement 6,000,000
Conversion of 10.0 million Coral
Energy, LLC Special Units to
Common Units 10,000,000 (10,000,000)
Treasury Units purchased by
consolidated Trust (792,800) 792,800
Treasury Units reissued by
consolidated Trust 1,000,000 (1,000,000)
--------------------------------------------------------------
Balance, December 31, 2001 102,721,830 42,819,740 29,000,000 327,200
Conversion of 19.0 million Coral
Energy, LLC Special Units to
Common Units 19,000,000 (19,000,000)
Conversion of 10.7 million Subordinated
Units to Common Units 10,704,936 (10,704,936)
Common Units issued in October 2002 9,800,000
Treasury Units purchased by
consolidated Trust and Company (532,000) 532,000
--------------------------------------------------------------
Balance, December 31, 2002 141,694,766 32,114,804 10,000,000 859,200
==============================================================
11. 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
$0.2250 per Common Unit. The minimum quarterly distribution is not guaranteed
and is subject to adjustment as set forth in the Partnership Agreement. With
respect to each quarter during the Subordination Period, the Common Unitholders
will generally have the right to receive the minimum quarterly distribution,
plus any arrearages thereon, and the General Partner will have the right to
receive the related distribution on its interest before any distributions of
available cash from Operating Surplus are made to the Subordinated Unitholders.
As an incentive, the General Partner's interest in our quarterly
distributions is increased after certain specified target levels are met. We
made incentive distributions to the General Partner of $9.8 million, $3.2
million and $0.4 million during the years ended December 31, 2002, 2001 and
2000, respectively.
F-30
The following table is a summary of cash distributions per Common and
Subordinated Unit and related record and payment dates since January 1, 2000:
CASH DISTRIBUTION HISTORY
-------------------------------------------------------------------
PER PER
COMMON SUBORDINATED RECORD PAYMENT
UNIT UNIT DATE DATE
-------------------------------------------------------------------
2000
1st Quarter $0.2500 $0.2500 Apr. 28, 2000 May 10, 2000
2nd Quarter $0.2625 $0.2625 Jul. 31, 2000 Aug. 10, 2000
3rd Quarter $0.2625 $0.2625 Oct. 31, 2000 Nov. 10, 2000
4th Quarter $0.2750 $0.2750 Jan. 31, 2001 Feb. 9, 2001
2001
1st Quarter $0.2750 $0.2750 Apr. 30, 2001 May 10, 2001
2nd Quarter $0.2938 $0.2938 Jul. 31, 2001 Aug. 10, 2001
3rd Quarter $0.3125 $0.3125 Oct. 31, 2001 Nov. 9, 2001
4th Quarter $0.3125 $0.3125 Jan. 31, 2002 Feb. 11, 2002
2002
1st Quarter $0.3350 $0.3350 Apr. 30, 2002 May 10, 2002
2nd Quarter $0.3350 $0.3350 Jul. 31, 2002 Aug. 12, 2002
3rd Quarter $0.3450 $0.3450 Oct. 31, 2002 Nov. 12, 2002
4th Quarter $0.3450 $0.3450 Jan. 31, 2003 Feb. 12, 2003
The quarterly cash distribution amounts shown in the table correspond
to the cash flows for the quarters indicated. The actual cash distributions
occur within 45 days after the end of such quarter.
12. PROVISION FOR INCOME TAXES
Provision for income taxes is only applicable to the tax obligation of
our Seminole pipeline business, which is a corporation and the only entity
subject to income taxes in the consolidated group. The following is a summary
of the provision for income taxes for Seminole for the period August 1, 2002
through December 31, 2002:
Current:
Federal tax benefit ($391)
State tax benefit (55)
--------------
(446)
--------------
Deferred:
Federal 1,812
State 268
--------------
2,080
--------------
Provision for Income Taxes $1,634
==============
The following is a reconciliation of the provision for income taxes at
the federal statutory rate to the provision for income taxes:
Taxes computed by applying the federal statutory rate $1,488
State income taxes (net of federal benefit) 138
Other 8
--------------
Provision for income taxes $1,634
==============
F-31
Significant components of deferred income tax assets and liabilities
at December 31, 2002 are as follows:
Deferred tax assets:
Property, plant and equipment $15,846
Deferred tax liabilities:
Other (619)
--------------
Net deferred tax assets $15,227
==============
Based upon the periods in which taxable temporary differences are
anticipated to reverse, we believe it is more likely than not that the Company
will realize the benefits of these deductible differences. Accordingly, we
believe that no valuation allowance is required for the deferred tax assets.
However, the amount of the deferred tax asset considered realizable could be
adjusted in the future if estimates of reversing taxable temporary differences
are revised.
13. 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. In general, 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. In a period of net operating losses, the
Special Units are excluded from the calculation of diluted earnings per Unit
due to their antidilutive effect. Treasury Units are not considered to be
outstanding Units; therefore, they are excluded from the computation of both
basic and diluted earnings per Unit. The amount of Common Units outstanding in
the following table does not include Treasury Units (either owned by the
Company or the Trust, see Note 10). The following table reconciles the number
of Units used in the calculation of basic earnings per Unit and diluted
earnings per Unit for the years ended December 31, 2002, 2001 and 2000. See
Note 21 for information regarding our January 2003 issuance of 14.7 million
Common Units.
F-32
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
Income before minority interest $ 98,447 $ 244,650 $ 222,759
General partner interest (10,663) (5,608) (2,597)
---------------------------------------------------
Income before minority interest
available to Limited Partners 87,784 239,042 220,162
Minority interest (2,947) (2,472) (2,253)
---------------------------------------------------
Net income available to Limited Partners $ 84,837 $ 236,570 $ 217,909
===================================================
BASIC EARNINGS PER UNIT
NUMERATOR
Income before minority interest
available to Limited Partners $ 87,784 $ 239,042 $ 220,162
===================================================
Net income available
to Limited Partners $ 84,837 $ 236,570 $ 217,909
===================================================
DENOMINATOR
Common Units outstanding 119,820 96,633 91,395
Subordinated Units outstanding 35,634 42,820 42,820
---------------------------------------------------
Total 155,454 139,453 134,215
===================================================
BASIC EARNINGS PER UNIT
Income before minority interest
available to Limited Partners $ 0.56 $ 1.71 $ 1.64
===================================================
Net income available
to Limited Partners $ 0.55 $ 1.70 $ 1.62
===================================================
DILUTED EARNINGS PER UNIT
NUMERATOR
Income before minority interest
available to Limited Partners $ 87,784 $ 239,042 $ 220,162
===================================================
Net income available
to Limited Partners $ 84,837 $ 236,570 $ 217,909
===================================================
DENOMINATOR
Common Units outstanding 119,820 96,633 91,395
Subordinated Units outstanding 35,634 42,820 42,820
Special Units outstanding 21,036 31,334 30,672
---------------------------------------------------
Total 176,490 170,787 164,887
===================================================
DILUTED EARNINGS PER UNIT
Income before minority interest
available to Limited Partners $ 0.50 $ 1.40 $ 1.34
===================================================
Net income available
to Limited Partners $ 0.48 $ 1.39 $ 1.32
===================================================
14. RELATED PARTY 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 D. Williams and Richard
H. Bachmann) and the remaining executive and other officers of the General
Partner are employees of EPCO. The principal business activity of the General
Partner is to act as our managing partner.
F-33
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 Ms. 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 us.
In addition, trust affiliates of EPCO (the 1998 Trust and 2000 Trust)
owned 2,478,236 Common Units at December 31, 2002. Collectively, EPCO, Dan L.
Duncan, the 1998 Trust and the 2000 Trust owned 61.4% of our limited
partnership interests at December 31, 2002. We neither direct the actions of
either the 1998 Trust or the 2000 Trust nor exercise any measure of control over
their actions. Accordingly, these two trusts are not consolidated with our
businesses and their Common Unit holdings are deemed to be outstanding for
purposes of our earnings per Unit computations.
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.
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. Under the terms of the EPCO Agreement,
EPCO agrees to:
o employ the personnel necessary to manage our business and
affairs (through the General Partner);
o employ the operating personnel involved in our business for
which we reimburse EPCO (based upon EPCO's actual salary and
related fringe benefits cost);
o 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;
o grant us an irrevocable, non-exclusive worldwide license to all
of the EPCO trademarks and trade names used in our business;
o indemnify us against any losses resulting from certain lawsuits;
and
o 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 to us its
purchase option under such leases to us (the "retained leases").
EPCO remains liable for the lease payments associated with these
assets.
Operating costs and expenses (as shown in the Statements of
Consolidated Operations) treat the lease payments being made by EPCO as a
non-cash related party operating expense, with the offset to Partners' Equity
on the Consolidated Balance Sheets recorded as a general contribution to the
partnership. In addition, operating costs and expenses include compensation
charges for EPCO's employees who operate our facilities.
Pursuant to the EPCO Agreement, we reimburse EPCO for our share of the
costs of certain of its employees in administrative positions that were active
at the time of our initial public offering in July 1998 who manage our business
and affairs. Our reimbursement of EPCO's administrative personnel expense is
capped (currently at $17.6 million annually - the "Administrative Services
Fee"). The General Partner, with the approval and consent of the Audit and
Conflicts Committee, may agree to 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 of administrative personnel
(including costs associated with equity-based awards granted to certain
individuals within this group) and the fee we pay will be borne solely by EPCO.
The actual amounts incurred by EPCO did not materially exceed the capped
amounts for any periods. We also reimburse EPCO for the compensation of
administrative personnel it hires in response to our expansion and new business
activities. This includes costs attributable to equity-based awards granted to
members of this group.
F-34
Other related party transactions with EPCO. The following is a summary
of other significant related party transactions between EPCO and us, including
those between EPCO and our unconsolidated affiliates.
o EPCO is the operator of the facilities owned by BEF, of which we
own 33.3%. In lieu of charging BEF for the actual cost of
providing management services, EPCO charges BEF a management
fee. EPCO charged BEF $0.6 million for such services during each
of 2002, 2001 and 2000.
o EPCO is also operator of the facilities owned by EPIK, which we
now wholly own. Prior to February 2003, we owned only 50% of
EPIK. In lieu of charging EPIK for the actual cost of management
services, EPCO charges EPIK a management fee. During 2002, 2001
and 2000, EPCO charged EPIK $0.3 million, $0.2 million and $0.3
million, respectively, for such services.
o We have entered into an agreement with EPCO to provide trucking
services to us for the loading and transportation of products.
o In the normal course of business, we also buy from and sell NGL
products to EPCO's Canadian affiliate.
The following table summarizes our various related party transactions
with EPCO for the years ended December 31, 2002, 2001 and 2000:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
REVENUES FROM CONSOLIDATED OPERATIONS
EPCO $ 3,630 $ 5,439 $ 4,750
OPERATING COSTS AND EXPENSES
EPCO 103,210 62,919 52,861
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES
Base fees payable under EPCO Agreement 16,638 15,125 13,750
Other EPCO compensation reimbursement 7,566 4,824 1,930
Relationship with Shell
We have an extensive and ongoing commercial relationship with Shell as
a partner, customer and vendor. Shell, through its subsidiary Shell US Gas &
Power LLC, currently owns approximately 20.5% of our limited partnership
interests and 30.0% of the General Partner. Currently, three members of the
Board of Directors of the General Partner (J. A. Berget, J.R. Eagan, and A.Y.
Noojin, III) are employees of Shell.
Shell is our single largest customer. During 2002, it accounted for
7.8% of our consolidated revenues. Our revenues from Shell reflect the sale of
NGL and petrochemical products to them and the fees we charge them for pipeline
transportation and NGL fractionation services. Our operating costs and expenses
with Shell primarily reflect the payment of energy related-expenses related to
the Shell natural gas processing agreement (see below) and the purchase of NGL
products from them. The following table shows our revenues and operating costs
and expenses with Shell for the years ended December 31, 2002, 2001 and 2000:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
REVENUES FROM CONSOLIDATED OPERATIONS
Shell $ 282,820 $ 333,333 $ 292,741
OPERATING COSTS AND EXPENSES
Shell 531,712 705,440 736,655
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 state and federal waters
of the Gulf of Mexico on a keepwhole basis. This is a life of lease dedication,
which may extend the agreement well beyond 20 years. Generally, this contract
has the following rights and obligations:
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o the exclusive right, but not the obligation, to process
substantially all of Shell's Gulf of Mexico natural gas
production; plus
o the exclusive right, but not the obligation, to process all
natural gas production from leases dedicated by Shell for the
life of such leases; plus
o 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
o the obligation to re-deliver to Shell the natural gas stream
after the mixed NGL stream is extracted.
Under this contract, we are responsible for reimbursing Shell for the market
value of the energy we extract from their natural gas stream in the course of
performing natural gas processing services for them. Our reimbursement to Shell
(which we record as an operating cost) is generally based upon the energy value
of the fuel we consume and the NGLs we extract from their natural gas stream
(in terms of its Btu content, a measure of heating value). In lieu of
collecting a cash fee for our services under this contract, we take ownership
of the NGLs we extract from their natural gas stream. These volumes (our
"equity NGL production") become part our inventory held for sale. We derive a
profit to the extent that the revenues from the ultimate sale and delivery to
customers of these NGLs exceeds the costs of extraction and any other ancillary
costs such as fractionation fees.
We have completed a number of business acquisitions and asset
purchases involving Shell since 1999. Among these transactions were:
o the acquisition of TNGL's natural gas processing and related
businesses in 1999 for approximately $528.8 million (this
purchase price includes both the $166 million in cash we paid to
Shell and the value of the three issues of Special Units granted
to Shell in connection with this acquisition);
o the purchase of the Lou-Tex Propylene Pipeline System for $100
million in 2000; and,
o the acquisition of Acadian Gas in 2001 for $243.7 million.
Shell is also a partner with us in the Gulf of Mexico natural gas pipelines we
acquired from El Paso in 2001. We also lease from Shell its 45.4% interest in
our Splitter I propylene fractionation facility.
Relationships with Unconsolidated Affiliates
Our investment in unconsolidated affiliates with industry partners is
a vital component of our business strategy. These investments are a means by
which we conduct our operations to align our interests with a supplier of raw
materials or a consumer of finished products. 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. The following summarizes significant related
party transactions we have with our unconsolidated affiliates:
o We sell natural gas to Evangeline, which, in turn, uses the
natural gas to satisfy supply commitments it has with a major
Louisiana utility. We have also furnished $2.2 million in
letters of credit on behalf of Evangeline.
o We pay EPIK for export services to load product cargoes for our
NGL and petrochemical marketing customers.
o We pay Dixie transportation fees for propane movements on their
system initiated by our NGL marketing activities.
o We sell high purity isobutane to BEF as a feedstock and purchase
certain of BEF's by-products. We also receive transportation
fees for MTBE movements on our HSC pipeline and fractionation
revenues for reprocessing mixed feedstock streams generated by
BEF.
o We pay Promix for the transportation, storage and fractionation
of certain of our mixed NGL volumes. In addition, we sell
natural gas to Promix for their fuel requirements.
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The following table summarizes our related party transactions with
unconsolidated affiliates for the years ended December 31, 2002, 2001 and 2000:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
REVENUES
Evangeline $ 131,635 $ 117,283
EPIK 259 297 $ 5,070
BEF 50,494 45,778 56,216
Promix 12,697 8,952 57
Other unconsolidated affiliates 1,182 1,374 645
OPERATING COSTS AND EXPENSES
EPIK 19,788 7,438 17,600
Dixie 12,184 12,695 11,763
BEF 9,794 8,073 10,640
Promix 18,408 12,676 18,200
Other unconsolidated affiliates 482 193
As part of Other Income and Expense as shown in our Statements of
Consolidated Operations and Comprehensive Income, we record dividend income
from our investment in VESCO.
15. UNIT OPTION PLAN ACCOUNTING
During 1998, EPCO adopted its 1998 Long-Term Incentive Plan (the "1998
Plan"). Under the 1998 Plan, non-qualified incentive options to purchase a
fixed number of our Common Units (the "Units") may be granted to EPCO's key
employees who perform management, administrative or operational functions for
us. The exercise price per Unit, vesting and expiration terms, and rights to
receive distributions on Units granted are determined by EPCO for each grant
agreement. EPCO funds the purchase of the Units under the 1998 Plan at fair
value in the open market.
Categories of equity-based awards and our general responsibility under
each
Equity-based awards granted to certain key operations personnel. Under
the EPCO Agreement (see Note 14), we reimburse EPCO for the compensation of all
operations personnel it employs on our behalf. This includes the costs
attributable to equity-based awards granted to these personnel. When these
employees exercise Unit options, we reimburse EPCO for the difference between
the strike price paid by the employee and the actual purchase price for the
Units awarded to the employee. We may reimburse EPCO for these costs by either
furnishing cash, reissuing Treasury Units or by issuing new Common Units. We
record the expense associated with these awards in our operating costs and
expenses as shown on our Statements of Consolidated Operations.
Equity-based awards granted to certain key expansion-related
administrative and management employees. We also reimburse EPCO for the
compensation of administrative and management personnel it hires in response to
our expansion and new business activities. This includes costs attributable to
equity-based awards granted to members of this "expansion" group of EPCO
employees. When these employees exercise Unit options, we reimburse EPCO for
the difference between the strike price paid by the employee and the actual
purchase price for the Units awarded to the employee. We may reimburse EPCO for
these costs by either furnishing cash, reissuing Treasury Units or by issuing
new Common Units. We record the expense associated with these awards in our
selling, general and administrative costs as shown on our Statements of
Consolidated Operations.
Equity-based awards granted to other key administrative and management
employees. In addition, we reimburse EPCO for our share of the costs of certain
of its employees in administrative and management positions that were active at
the time of our initial public offering in July 1998 who manage our business
and affairs. Our reimbursement for the cost of equity-based awards to this
"pre-expansion" group of administrative EPCO employees is covered by the
Administrative Services Fee we pay to EPCO. EPCO is responsible for the actual
costs when the
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Unit options granted to these pre-expansion administrative employees are
exercised. EPCO satisfies its equity-award obligations to these employees by
arranging for Common Units to be purchased in the open market. We record the
Administrative Service Fee paid to EPCO as a selling, general and
administrative expense as shown on our Statements of Consolidated Operations.
Summary of 1998 Plan activity and amounts related to Employees who
perform activities on our behalf
EPCO's 1998 Plan is used to issue Unit option awards to the three
categories of employees discussed above. The information in the following table
shows (i) Unit option activity for all operations and expansion -related
administrative/management personnel and (ii) Unit option activity of the
pre-expansion administrative/management employees allocable to us under the
EPCO Agreement (based on each pre-expansion employee's percentage of time
worked on our behalf).
WEIGHTED-AVERAGE
NUMBER OF UNITS STRIKE PRICE
-----------------------------------
Outstanding at December 31, 1999 178,611 $ 1.95
Granted 664,000 $ 9.26
Exercised (38,180) $ 1.84
Forfeited (20,000) $ 9.00
-----------------------------------
Outstanding at December 31, 2000 784,431 $ 7.96
Granted 680,000 $ 16.67
Exercised (150,585) $ 6.01
Forfeited (20,000) $ 9.00
-----------------------------------
Outstanding at December 31, 2001 1,293,846 $ 12.74
Granted 249,000 $ 23.76
Exercised (102,604) $ 6.16
-----------------------------------
Outstanding at December 31, 2002 1,440,242 $ 15.12
===================================
Options exercisable at:
December 31, 2000 140,431
=================
December 31, 2001 155,846
=================
December 31, 2002 383,742
=================
OPTIONS EXERCISABLE AT
DECEMBER 31, 2002
------------------------------
WEIGHTED
OPTIONS AVERAGE WEIGHTED NUMBER WEIGHTED
RANGE OUTSTANDING AT REMAINING AVERAGE EXERCISABLE AT AVERAGE
OF STRIKE DECEMBER 31, CONTRACTUAL STRIKE DECEMBER 31, STRIKE PRICE
PRICES 2002 LIFE(IN YEARS) PRICE 2002
- -----------------------------------------------------------------------------------------------------
$.69 - $2.23 52,242 2.16 $ 1.58 52,242 $ 1.98
$7.75 -$9.00 331,500 6.75 $ 8.82 331,500 $ 8.82
$11.81 127,500 7.09 $ 11.81 - -
$15.93 - $17.63 615,000 8.10 $ 16.30 - -
$21.22 - $24.73 314,000 9.09 $ 23.61 - -
----------------- ------------------
1,440,242 383,742
================= ==================
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The weighted average fair value of options granted was $3.17, $1.86,
and $2.23 per option for the fiscal years ended December 31, 2002, 2001, and
2000, respectively.
We apply Accounting Principles Board Opinion No. 25, "Accounting for
Stock Issued to Employees", in accounting for employee Unit option awards
whereby no compensation expense is recorded related to the options granted
equal to the market value of the Unit on the date of grant. If compensation
expense had been determined based on the Black-Scholes option pricing model
value at the grant date for Unit option awards consistent with the provisions
of SFAS No. 123, "Accounting for Stock-Based Compensation", our net income and
earnings per unit would have been as follows:
2002 2001 2000
---- ---- ----
Net income:
As reported......................... $95,500 $242,178 $220,506
Pro forma........................... 94,406 241,348 219,844
Basic earnings per unit:
As reported......................... $ .55 $ 1.70 $ 1.62
Pro forma........................... .54 1.69 1.62
Diluted earnings per unit:
As reported......................... $ .48 $ 1.39 $ 1.32
Pro forma........................... .48 1.38 1.32
The effects of applying SFAS No. 123 in the pro forma disclosure above may not
be indicative of future amounts as additional awards in future years are
anticipated.
The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option-pricing model with the following assumptions:
2002 2001 2000
---- ---- ----
Expected life of options................. 7 years 7 years 7 years
Risk-free interest rate.................. 3.10% 3.83% 6.44%
Expected dividend yield.................. 5.65% 5.30% 10.00%
Expected Unit price volatility........... 25% 20% 30%
16. COMMITMENTS AND CONTINGENCIES
Redelivery Commitments
We store and transport NGL, petrochemical and natural gas volumes for
third parties under various processing, storage, transportation and similar
agreements. Under the terms of these agreements, we are generally required to
redeliver volumes to the owner on demand. We are insured for any physical loss
of such volumes due to catastrophic events. At December 31, 2002, NGL and
petrochemical volumes aggregating 4.2 million barrels were due to be
redelivered to their owners along with 664 BBtus 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, 2002 are as
follows:
2003 $ 7,148
2004 5,081
2005 759
2006 676
2007 506
Thereafter 3,623
--------------
Total minimum obligations $ 17,793
==============
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Third-party lease and rental expense included in operating income for
the years ended December 31, 2002, 2001 and 2000 was approximately $16.4
million, $13.0 million and $10.6 million.
The operating lease commitments shown above exclude the non-cash
related party expense associated with various equipment leases contributed to
us by EPCO at our formation for which EPCO has retained the liability (the
"retained leases"). The retained leases are accounted for as operating leases
by EPCO. EPCO's minimum future rental payments under these leases are $12.6
million for 2003, $2.1 million for each of the years 2004 through 2009 and $0.7
million from 2010 through 2016. EPCO has assigned to us the purchase options
associated with the retained leases. Should we decide to exercise our purchase
options under the retained leases (which are at fair market value), up to $26.0
million is expected to be payable in 2004, $3.4 million in 2008 and $3.1 million
in 2016.
Purchase Commitments
Product purchase commitments. We have long-term purchase commitments
for NGLs, petrochemicals and natural gas with several suppliers. The purchase
prices that we are obligated to pay under these contracts approximate market
prices at the time we take delivery of the volumes. The following table shows
our long-term volume commitments under these contracts.
NATURAL
NGLS PETROCHEMICALS GAS
-----------------------------------------------------------
(MBbls) (MBbls) (BBtus)
-----------------------------------------------------------
2003 15,986 25,428 23,053
2004 13,172 22,857 20,439
2005 9,580 19,287 18,645
2006 5,910 13,399 18,645
2007 5,400 1,125 18,250
Thereafter 10,800 91,250
-----------------------------------------------------------
60,848 82,096 190,282
===========================================================
Capital spending commitments. As of December 31, 2002, we had capital
expenditure commitments totaling approximately $7.8 million, of which $6.3
million relates to our share of capital projects of unconsolidated affiliates.
Commitments under equity compensation plans of EPCO
In accordance with our agreements with EPCO, we reimburse EPCO for our
share of its compensation expense associated with certain employees who perform
management, administrative and operating functions for us (see Note 14). This
includes the costs associated with equity-based awards granted to these
employees (see Note 15). At December 31, 2002, there were 1,194,242 options
outstanding to purchase Common Units under the 1998 Plan that had been granted
to operational and expansion-related administrative employees for which we were
responsible for reimbursing EPCO for the costs of such awards. The
weighted-average strike price of the Unit option awards granted to this group
was $15.73 per Common Unit. At December 31, 2002, 275,242 of these Unit options
were exercisable. An additional 100,000, 570,000 and 249,000 of these Unit
options will be exercisable in 2003, 2004 and 2005, respectively.
When these operations and expansion-related administrative employees
exercise a Unit option, we reimburse EPCO for the difference between the strike
price paid by the employee and the actual purchase price paid for the Units
awarded to the employee. We may reimburse EPCO for these costs by either
furnishing cash, reissuing Treasury Units or by issuing new Common Units.
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
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various business risks, to the extent management believes it is prudent, there
is no assurance that the nature and amount of such insurance will be adequate,
in every case, to indemnify us against liabilities arising from future legal
proceedings as a result of ordinary business activity. 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.
17. SUPPLEMENTAL CASH FLOWS DISCLOSURE
The net effect of changes in operating assets and liabilities is as
follows:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
(Increase) decrease in:
Accounts and notes receivable $ (127,365) $ 231,532 $ (93,716)
Inventories (84,254) 11,048 (13,044)
Prepaid and other current assets 15,340 (26,427) 2,352
Intangible assets (5,226)
Other assets (3,322) 162 (1,410)
Increase (decrease) in:
Accounts payable 23,901 (82,075) 18,723
Accrued gas payable 262,527 (178,102) 135,049
Accrued expenses 7,884 (1,576) 4,978
Accrued interest 5,369 14,234 8,743
Other current liabilities (6,921) 3,073 6,540
Other liabilities (504) (9,012) 8,122
---------------------------------------------------
Net effect of changes in operating accounts $ 92,655 $ (37,143) $ 71,111
===================================================
Cash payments for interest, net of $1,083,
$2,946 and $3,277 capitalized in 2002,
2001 and 2000, respectively $ 82,535 $ 37,536 $ 17,774
===================================================
During 2002 and 2001, we completed $1.8 billion in business
acquisitions of which the purchase price allocation of each affected various
balance sheet accounts. See Note 4 for information regarding the purchase price
allocations of these transactions during 2002. During 2001, we acquired Acadian
Gas from Shell. Its $225.7 million purchase price was allocated as follows:
$83.1 million to current assets, $225.2 million to property, plant and
equipment, $2.7 million to investments in unconsolidated affiliates, $83.9
million to current liabilities and $1.4 million to other long-term liabilities.
We record various financial instruments relating to commodity
positions and interest rate hedging activities at their respective fair values
using mark-to-market accounting. During 2002, we recognized a net $10.2 million
in non-cash mark-to-market decreases in the fair value of these instruments,
primarily in our commodity financial instruments portfolio. During 2001, we
recognized a net $5.6 million in non-cash mark-to-market increases in the fair
value of our financial instruments portfolio.
During 2002, we made the first of two cash payments to acquire certain
processing-related contract rights connected to Venice gas processing facility.
Of the initial $4.6 million value of this intangible asset, $2.6 million was
reclassified from construction-in-progress and $2.0 million represented the
actual cash payment made to the third-party. The prior expenditures recorded as
construction-in-progress were reclassified due to the direct linkage between
these expenditures and the successful negotiation of the Venice contracts. The
remaining $2.0 million is scheduled to be paid during the third quarter of
2003.
Cash and cash equivalents (as shown on our Statements of Consolidated
Cash Flows) excludes restricted cash amounts held by a brokerage firm as margin
deposits associated with our financial instruments portfolio and for our
physical purchase transactions made on the NYMEX exchange. The restricted cash
balance at December 31, 2002 and 2001 was $8.8 million and $5.8 million,
respectively.
F-41
We did not have any cash payments for income taxes during 2002, 2001
or 2000. For additional information regarding our partnership and income taxes,
see Note 1 and Note 12.
18. FINANCIAL INSTRUMENTS
We are exposed to financial market risks, including changes in
commodity prices and interest rates. 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 within our Processing segment. In general, the types of
risks we attempt to hedge 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.
The estimated fair values of our financial instruments have been
determined using available market information and appropriate valuation
methodologies. We must use considerable judgment, however, in interpreting
market data and developing these estimates. Accordingly, our fair value
estimates are not necessarily indicative of the amounts that we could realize
upon disposition of these instruments. The use of different market assumptions
and/or estimation techniques could have a material effect on our estimates of
fair value.
Commodity financial instruments
The prices of natural gas, NGLs, petrochemical products 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 our Processing segment activities, we may
enter into various commodity financial instruments. The primary purpose of
these risk management activities is to hedge our exposure to price risks
associated with natural gas, NGL production and inventories, firm commitments
and certain anticipated transactions. The commodity financial instruments we
utilize may be settled in cash or with another financial instrument.
We do not hedge our exposure related to MTBE price risks. In addition,
we generally do not hedge risks associated with the petrochemical marketing
activities that are part of our Fractionation segment. In our Pipelines
segment, we do utilize a limited number of commodity financial instruments to
manage the price Acadian Gas charges certain of its customers for natural gas.
Lastly, due to the nature of the transactions, we do not employ commodity
financial instruments in our fee-based marketing business accounted for in the
Other segment.
We have adopted a policy to govern our use of commodity financial
instruments to manage 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 limits 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 24 months. The
General Partner oversees 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.
Our commodity financial instruments may not qualify for hedge
accounting treatment under the specific guidelines of SFAS No. 133 because of
ineffectiveness. A financial instrument is generally regarded as "effective"
when changes in its fair value almost fully offset changes in the fair value of
the hedged item throughout the term of the instrument. Due to the complex
nature of risks we attempt to hedge, our commodity financial instruments have
generally not qualified as effective hedges under SFAS No. 133. As a result,
changes in the fair value of these positions are recorded on the balance sheet
and in earnings through mark-to-market accounting. Mark-to-market accounting
results in a degree of non-cash earnings volatility that is dependent upon
changes in the commodity prices underlying these financial instruments. Even
though these financial instruments may not qualify for hedge accounting
treatment under SFAS No. 133, we view such contracts as hedges since this was
the intent when we entered into such positions. Upon entering into such
positions, our expectation is that the economic performance of these
instruments will mitigate (or offset) the commodity risk being addressed. The
specific accounting for these contracts, however, is consistent with the
requirements of SFAS No. 133.
F-42
At December 31, 2002, we had open commodity financial instruments that
settle at different dates through December 2003. We routinely review our
outstanding 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 a new
commodity financial instrument to reestablish the hedge to which the closed
instrument relates.
During 2002, we recognized a loss of $51.3 million from our commodity
hedging activities that was recorded as an increase in our operating costs and
expenses in the Statements of Consolidated Operations. Of the loss recognized
in 2002, $5.6 million is related to non-cash mark-to-market income recorded on
open positions at December 31, 2001. During 2001, we posted income of $101.3
million from our commodity hedging activities, which served to reduce operating
costs and expenses.
Beginning in late 2000 and extending through March 2002, a large
number of our commodity hedging transactions were based on the historical
relationship between natural gas prices and NGL prices. This type of hedging
strategy utilized 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 marketing activities and the value of
our equity NGL production. Throughout 2001, this strategy proved very
successful to us (as the price of natural gas declined relative to our fixed
positions) and was responsible for most of the $101.3 million in commodity
hedging income we recorded during 2001.
In late March 2002, the effectiveness of this strategy deteriorated
due to an unexpected rapid increase in natural gas prices whereby the loss in
the value of our fixed-price natural gas financial instruments was not offset
by increased gas processing margins. Due to the inherent uncertainty that was
controlling natural gas prices at the time, we decided that it was prudent to
exit this strategy, and we did so by late April 2002. The failure of this
strategy is the primary reason for the $51.3 million in commodity hedging
losses we recorded during 2002.
We had a limited number of commodity financial instruments open at
December 31, 2002. The fair value of these open positions was a liability of
$26 thousand (based on market prices at that date).
Interest rate hedging financial instruments
Our interest rate exposure results from variable-interest rate
borrowings and fixed-interest rate borrowings (see Note 9). We assess the cash
flow risk related to interest rates by identifying and measuring changes in our
interest rate exposures that may impact future cash flows and evaluating
hedging opportunities to manage these risks. We use analytical techniques to
measure our 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 these financial risks and approves instruments that are
appropriate for our requirements.
Interest rate swaps. We manage a portion of our interest rate risks by
utilizing interest rate swaps. The objective of entering into 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. In general, an interest rate swap requires one party to pay a
fixed-interest rate on a notional amount while the other party pays a
floating-interest rate based on the same notional amount. The notional amount
specified in an interest rate swap agreement does not represent exposure to
credit loss. We monitor our positions and the credit ratings of counterparties.
Management believes the risk of incurring a credit loss on these financial
instruments is remote, and that if incurred, such losses would be immaterial.
We believe that it is prudent to maintain an appropriate balance of
variable-rate and fixed-rate debt.
At December 31, 2002, we had one interest rate swap outstanding having
a notional amount of $54 million that extends through March 2010. Under this
agreement, we exchanged a fixed-interest rate of 8.7% for a variable-interest
rate that ranged from 1.8% to 4.5% during 2002 (the variable-interest rate we
paid under this swap fluctuated over time depending on market conditions).The
counterparty exercised its right to early termination of this swap in March
2003; therefore, only a minimal amount of income will be recognized in 2003
from this financial instrument. We recognized income from our interest rate
swaps of $0.9 million during 2002 compared to $13.2
F-43
million during 2001. This income is recorded as a reduction of interest expense
in our Statements of Consolidated Operations.
Treasury Locks. During the fourth quarter of 2002, we entered into
seven treasury lock transactions. A treasury lock is a specialized agreement
that fixes the price (or yield) on a specific treasury security for an
established period of time. A treasury lock purchaser is protected from a rise
in the yield of the underlying treasury security during the lock period. Our
treasury lock transactions carried an original maturity date of either January
31, 2003 or April 15, 2003. The purpose of these transactions was to hedge the
underlying treasury interest rate associated with our anticipated issuance of
debt in early 2003 to refinance the Mid-America and Seminole acquisitions. The
notional amounts of these transactions totaled $550 million, with a total
treasury lock rate of approximately 4%.
Our treasury lock transactions are accounted for as cash flow hedges
under SFAS No. 133. The fair value of these instruments at December 31, 2002
was a current liability of $3.8 million offset by a current asset of $0.2
million. The net $3.6 million non-cash mark-to-market liability was recorded as
a component of comprehensive income on that date, with no impact to current
earnings.
We elected to settle all of the treasury locks by early February 2003
in connection with our issuance of Senior Notes C and D (see Note 21). The
settlement of these instruments resulted in our receipt of $5.4 million of
cash. This amount will be recorded as a gain in other comprehensive income
during the first quarter of 2003 and represents the effective portion of the
treasury locks.
Of the $5.4 million recorded in other comprehensive income during the
first quarter of 2003, $4.0 million is attributable to our issuance of Senior
Notes C and will be amortized to earnings as a reduction in interest expense
over the 10-year term of this debt. The remaining $1.4 million is attributable
to our issuance of Senior Notes D and will amortized to earnings as a reduction
in interest expense over the 10-year term of the anticipated transaction as
required by SFAS No. 133. The estimated amount to be reclassified from
accumulated other comprehensive income to earnings during 2003 is $0.4 million.
With the settlement of the treasury locks, the $3.6 million non-cash
mark-to-market liability recorded at December 31, 2002 will be reclassified out
of accumulated other comprehensive income in Partners' Equity to offset the
current asset and liabilities we recorded at December 31, 2002 with no impact
to earnings.
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.
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. The estimated fair value of
our fixed-rate debt is estimated based on quoted market prices for such debt or
debt of similar terms and maturities. The carrying amounts of our variable-rate
debt obligations reasonably approximate their fair values due to their variable
interest rates. The fair values associated with our commodity and interest rate
hedging financial instruments were developed using available market information
and appropriate valuation techniques.
F-44
The following table summarizes the estimated fair values of our
various financial instruments at December 31, 2002 and 2001:
AT DECEMBER 31, 2002 AT DECEMBER 31, 2001
---------------------------------------------------------------
CARRYING FAIR CARRYING FAIR
FINANCIAL INSTRUMENTS VALUE VALUE VALUE VALUE
------------------------------------------------------------------------------------------------------------------------
Financial assets:
Cash and cash equivalents $ 22,568 $ 22,568 $ 137,823 $ 137,823
Accounts receivable 399,415 399,415 260,399 260,399
Commodity financial instruments (1) 513 513 9,992 9,992
Interest rate hedging financial instruments (2) 203 203 2,324 2,324
Financial liabilities:
Accounts payable and accrued expenses 663,715 663,715 357,951 357,951
Fixed-rate debt (principal amount) 899,000 1,027,749 854,000 894,005
Variable-rate debt 1,346,000 1,346,000
Commodity financial instruments (1) 539 539 3,206 3,206
Interest rate hedging financial instruments (2) 3,766 3,766
------------------------------------------------------------------------------------------------------------------------
(1) Represent commodity financial instrument transactions that either
have not settled or have settled and not been invoiced . Settled and
invoiced transactions are reflected in either accounts receivable or
accounts payable depending on the outcome of the transaction.
(2) Represent interest rate hedging financial instrument transactions
that have not settled. Settled transactions are reflected in either
accounts receivable or accounts payable depending on the outcome of the
transaction.
19. 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. This concentration could affect our overall exposure to credit risk
since these customers might be affected by similar economic or other
conditions. We generally do not require collateral for our accounts receivable;
however, we do attempt to negotiate offset agreements with customers that are
deemed to be credit risks in order to minimize our potential exposure to any
defaults.
Counterparty risk. From time to time, we have credit risk with our
counterparties in terms of settlement risk associated with its financial
instruments (which includes accounts receivable). 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 $10.7
million reserve for amounts owed to us by Enron and its affiliates. Affiliates
of Enron were our counterparty to various past financial instruments, which
were guaranteed by Enron. The Enron amounts were unsecured and the amount that
we may ultimately recover, if any, is not presently determinable.
Nature of Operations. Our Company is subject to a number of risks
inherent in the industry in which it operates, including fluctuating gas and
product prices. Our financial condition and results of operations depend
significantly on the demand for NGLs and the costs involved in their
production. These NGL, natural gas and other related 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 our processing business in order to
maintain or increase gas plant processing 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.
F-45
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 our
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.
20. SEGMENT INFORMATION
Operating segments are components of a business about which separate
financial information is available. These components 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: Pipelines, Fractionation,
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. Pipelines
consists of NGL, petrochemical and natural gas pipeline systems, storage and
import/export terminal services. Fractionation primarily includes NGL
fractionation, isomerization, and polymer grade propylene fractionation
services. Processing includes the natural gas processing business and its
related NGL marketing 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 various operational support activities.
We evaluate segment performance based on our measurement of segment
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 other income and expense transactions, provision for
income taxes, minority interest and extraordinary charges.
Gross operating margin by segment includes intersegment and
intrasegment revenues (offset by corresponding intersegment and intrasegment
expenses within the segments), which are generally based on transactions made
at market-related rates. Our intersegment and intrasegment activities include,
but are not limited to, the following types of transactions:
o NGL fractionation revenues from separating our NGL raw-make
inventories into distinct NGL products using our fractionation
plants for our NGL marketing activities (an intersegment revenue
of Fractionation offset by an intersegment expense of
Processing);
o liquids pipeline revenues from transporting our NGL volumes from
gas processing plants on our pipelines to our NGL fractionation
facilities (an intersegment revenue of Pipelines offset by an
intersegment expense of Processing); and,
o the transfer sale of our NGL equity production extracted by our
gas processing plants to our NGL marketing activities (an
intrasegment revenue of Processing offset by an intrasegment
expense of Processing).
For additional information regarding our revenue recognition policies, see Note
2.
Our consolidated financial statements include our accounts and those
of our majority-owned subsidiaries, after elimination of all material
intercompany (both intersegment and intrasegment) accounts and transactions. We
include equity earnings from unconsolidated affiliates in our measurement of
segment gross operating margin. 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
F-46
relative to the level of investment and business risk assumed versus what we
could accomplish on a stand alone basis. Many of our equity investees (see Note
7) 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
Processing segment's NGL marketing activities. 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. For additional
information regarding our related party relationships with unconsolidated
affiliates, see Note 14.
Our revenues are derived from a wide customer base. All consolidated
revenues were earned in the United States. Most of our plant-based operations
are located primarily along the western Gulf Coast in Texas, Louisiana and
Mississippi. Our pipelines and related operations are in a number of regions of
the United States including the Gulf of Mexico offshore Louisiana (certain
natural gas pipelines); the south and southeastern United States (primarily in
the Texas, Louisiana and Mississippi regions); and certain regions of the
central and western United States. The Mid-America pipeline system extends from
the Hobbs hub located on the Texas-New Mexico border to Wyoming along one route
and to Minnesota, Wisconsin and Illinois along other routes. Our marketing
activities are headquartered in Houston, Texas at our main office and service
customers in a number of regions in the United States including the Gulf Coast,
West Coast and Mid-Continent areas.
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.
Consolidated intangible assets and goodwill are allocated to the segments based
on the classification of the assets to which they relate.
The following table shows our measurement of total segment gross
operating margin for the periods indicated:
FOR YEAR ENDED DECEMBER 31,
--------------------------------------------------
2002 2001 2000
--------------------------------------------------
Revenues (1) $ 3,584,783 $ 3,154,369 $ 3,049,020
Operating costs and expenses (1) (3,382,561) (2,861,743) (2,801,060)
Equity in income of unconsolidated affiliates (2) 35,253 25,358 24,119
--------------------------------------------------
Subtotal 237,475 317,984 272,079
Add: Depreciation and amortization in
operating costs and expenses (3) 86,029 48,775 35,621
Retained lease expense, net in
operating costs and expenses (4) 9,124 10,414 10,645
(Gain) loss on sale of assets in
operating costs and expenses (3) (1) (390) 2,270
-------------------------------------------------
Total segment gross operating margin $ 332,627 $ 376,783 $ 320,615
=================================================
- -------------------------------------------------------------------------------
(1) Amounts are comprised of both third party and related party totals from the
Statements of Consolidated Operations and Comprehensive Income
(2) Amount taken from Statements of Consolidated Operations and Comprehensive
Income
(3) Amount taken from Statements of Consolidated Cash Flows
(4) Amount represents leases paid by EPCO and the related contribution by the
minority interest as reflected on the Statements of Consolidated Cash Flows
F-47
A reconciliation of our measurement of total segment gross operating
margin to consolidated income before provision for income taxes and minority
interest follows:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
Total segment gross operating margin $ 332,627 $ 376,783 $ 320,615
Depreciation and amortization (86,029) (48,775) (35,621)
Retained lease expense, net (9,124) (10,414) (10,645)
Gain (loss) on sale of assets 1 390 (2,270)
Selling, general and administrative (42,890) (30,296) (28,345)
---------------------------------------------------
Consolidated operating income 194,585 287,688 243,734
Interest expense (101,580) (52,456) (33,329)
Interest income from unconsolidated affiliates 139 31 1,787
Dividend income from unconsolidated affiliates 4,737 3,462 7,091
Interest income - other 2,313 7,029 3,748
Other, net (113) (1,104) (272)
---------------------------------------------------
Consolidated income before provision for income
taxes and minority interest $ 100,081 $ 244,650 $ 222,759
===================================================
F-48
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 third parties:
2002 $ 592,681 $ 458,427 $ 2,049,202 $ 1,756 $ 3,102,066
2001 301,263 239,489 2,100,224 937 2,641,913
2000 361,919 15,648 2,310,706 1,268 2,689,541
Revenues from related parties:
2002 19,121 161,727 301,747 122 482,717
2001 23,013 163,941 324,057 1,445 512,456
2000 35,076 12,524 310,269 1,610 359,479
Intersegment and intrasegment
revenues:
2002 203,750 102,330 604,981 401 $ (911,462) -
2001 158,853 89,907 683,524 389 (932,673) -
2000 177,963 55,690 630,155 375 (864,183) -
Total revenues:
2002 815,552 722,484 2,955,930 2,279 (911,462) 3,584,783
2001 483,129 493,337 3,107,805 2,771 (932,673) 3,154,369
2000 574,958 83,862 3,251,130 3,253 (864,183) 3,049,020
Equity income in unconsolidated affiliates:
2002 7,179 19,505 $ 8,569 35,253
2001 6,945 12,742 5,671 25,358
2000 6,391 7,321 10,407 24,119
Total gross operating margin by segment:
2002 129,000 214,932 (17,633) 8,569 (2,241) 332,627
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
Segment property (see Note 6):
2002 444,016 2,166,524 133,888 16,825 49,586 2,810,839
2001 357,122 717,348 124,555 8,921 98,844 1,306,790
Investments in and advances
to unconsolidated affiliates (see Note 7):
2002 95,467 213,632 33,000 54,894 396,993
2001 93,329 216,029 33,000 55,843 398,201
Intangible Assets (see Note 8):
2002 71,069 7,895 198,697 277,661
2001 7,857 194,369 202,226
Goodwill (see Note 8):
2002 81,547 81,547
F-49
In general, our consolidated results of operations and financial
position have been materially affected by acquisitions since late 1999. Our
more significant acquisitions during this period were:
o William's Mid-America and Seminole pipelines in July 2002 for $1.2
billion;
o Diamond-Koch's propylene fractionation business in February 2002 for
$239 million ;
o Diamond-Koch's NGL and petrochemical storage business in January 2002
for $129.6 million;
o Shell's Acadian Gas pipeline business in April 2001 for $243.7
million;
o El Paso's equity interests in four Gulf of Mexico natural gas
pipelines in January 2001 for $113 million; and
o Shell's TNGL natural gas processing and related businesses in August
1999 for approximately $528.8 million.
See Note 4 for a description of acquisitions we completed during 2002.
21. SUBSEQUENT EVENTS
January 2003 Common Unit Offering. In January 2003, we completed a
public offering of 14,662,500 Common Units (including 1,912,500 Common Units
sold pursuant to the underwriters' over-allotment option) from which we
received net proceeds before offering expenses of approximately $258.9 million,
including our General Partner's $5.3 million in capital contributions. We used
$252.8 million of the proceeds from this offering to repay a portion of the
indebtedness outstanding under the 364-Day Term Loan. The remaining balance of
proceeds was used for working capital purposes and offering expenses.
January 2003 Senior Notes Offering. In January 2003, our Operating
Partnership issued $350 million in principal amount of 6.375% Senior Notes due
2013 ("Senior Notes C"), from which we received net proceeds before offering
expenses of approximately $347.7 million. We used $347.0 million of the
proceeds from this offering to repay a portion of the indebtedness outstanding
under the 364-Day Term Loan. The remaining balance of proceeds was used for
offering expenses.
February 2003 Senior Notes Offering. In February 2003, our Operating
Partnership issued $500 million in principal amount of 6.875% Senior Notes due
2033 ("Senior Notes D"), from which we received net proceeds before offering
expenses of approximately $489.8 million. We used $421.4 million of the
proceeds from this offering to repay the remaining principal balance
outstanding under the 364-Day Term Loan. An additional $60.0 million in
proceeds was used to reduce the amount outstanding under the 364-Day Revolving
Credit facility. The remaining balance of proceeds was used for working capital
purposes and offering expenses.
Purchase of remaining 50% interest in EPIK. In March 2003, we
purchased the remaining ownership interests in EPIK from Idemitsu LPG USA
Corporation for $19.0 million. The purchase price is subject to certain
post-closing adjustments that we expect to finalize during the second quarter
of 2003.
F-50
22. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table contains selected quarterly financial data for 2002 and
2001.
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
---------------------------------------------------------------
FOR THE YEAR ENDED DECEMBER 31, 2001:
Revenues $ 836,315 $ 959,397 $ 723,329 $ 635,328
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 $ 0.38 $ 0.68 $ 0.52 $ 0.14
Net income per Unit, diluted $ 0.30 $ 0.54 $ 0.43 $ 0.12
FOR THE YEAR ENDED DECEMBER 31, 2002:
Revenues $ 662,054 $ 786,257 $ 943,313 $ 1,193,159
Operating income (1,104) 39,964 68,356 87,369
Income before minority interest (17,376) 22,523 36,146 57,154
Minority interest 173 (203) (1,296) (1,621)
Net income (loss) (17,203) 22,320 34,850 55,533
Net income (loss) per Unit, basic $ (0.13) $ 0.14 $ 0.20 $ 0.30
Net income (loss) per Unit, diluted $ (0.13) $ 0.11 $ 0.18 $ 0.28
We recorded a net loss during the first quarter of 2002 due to
commodity hedging losses resulting from an unexpected increase in natural gas
prices. Overall, we recorded $51.3 million of commodity hedging losses during
2002 compared to $101.3 million of income from such activities during 2001 (see
Note 18). Net income for the second half of 2002 improved relative to the first
half of 2002 primarily due to the acquisition of Mid-America and Seminole in
July 2002 (see Note 4).
F-51
SCHEDULE II
ENTERPRISE PRODUCTS PARTNERS L.P.
VALUATION AND QUALIFYING ACCOUNTS
ADDITIONS
---------------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER BALANCE AT
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS END OF PERIOD
- ---------------------------------- -------------- -------------- -------------- -------------- --------------
ACCOUNTS RECEIVABLE - TRADE:
Allowance for doubtful
accounts
2002 $ 20,642 $ 5,367 (b) $ (4,813) (d) $ 21,196
2001 10,916 $ 6,200 (a) 6,522 (c) (2,996) (d) 20,642
2000 15,871 (4,955) (d) 10,916
OTHER CURRENT ASSETS:
Additional credit reserve
for Enron
2002 $ 4,305 $ (4,305) (b)
2001 4,305 (a) 4,305
OTHER CURRENT LIABILITIES:
Reserve for environmental
liabilities
2002 102 (e) (93) (e) 9
Reserve for inventory
gains and losses (f)
2002 2,029 500 (g) (1,258) (h) 1,271
2001 5,690 500 (g) (4,161) (h) 2,029
2000 2,894 500 (g) 2,296 (h) 5,690
OTHER LONG-TERM LIABILITIES:
Reserve for environmental
liabilities
2002 45 (e) 90 (e) 135
- -------------------------------------------------------------------------------
The following explanations describe significant transactions affecting the
amounts shown in the table above:
(a) In December 2001, Enron North America 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 established at December 31, 2001, $6.3 million offsets
billed amounts due from Enron recorded in Accounts Receivable-Trade. The
remaining $4.3 million in reserve offsets various unbilled commodity financial
instrument positions, which were reclassified to "Additional credit reserve from
Enron".
(b) The $4.3 million in unbilled positions was invoiced in early 2002 as the
financial instruments settled (see Note 19). These amounts were reclassified
from the "Additional credit reserve for Enron" account to "Allowance for
doubtful accounts" accordingly.
(c) The allowance account was increased in April 2001 as a result of accounts
acquired from Acadian Gas.
(d) In the normal course of business, we charged the allowance account for
customer amounts that have been deemed uncollectible.
(e) In July 2002, we acquired the Mid-America pipeline from Williams. This
operation had existing minor environmental liabilities that were of a current
and long-term nature that we recorded using purchase accounting. Since the
acquisition, various vendor invoices have been charged against the current
portion of the reserve. In addition, the long-term portion of the reserve has
been increased due to revisions in management estimates of the future liability
to remediate the sites involved.
(f) In general, the inventory gain/loss reserve was established to cover
anticipated net losses attributable to the storage of NGL and petrochemical
products in underground storage caverns.
(g) The reserve is increased based on management's estimate of annual net
product storage losses.
(h) Product losses are charged against and reduce the reserve balance.
Conversely, product gains increase the reserve. Management regularly reviews
the status of the reserve and determines the appropriate level based on
historical and anticipated storage well activity. A review of the reserve
balance was performed in late 2001 and based upon its findings and estimated
future losses, the reserve was adjusted by $2.4 million.
F-52
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of Enterprise Products GP, LLC (the General Partner of
Enterprise Products Operating L.P.):
We have audited the accompanying consolidated balance sheets of
Enterprise Products Operating L.P. and subsidiaries (the "Company") as of
December 31, 2002 and 2001, and the related statements of consolidated
operations and other comprehensive income, consolidated cash flows and
consolidated partners' equity for each of the three years in the period ended
December 31, 2002. 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, 2002 and 2001, and the results of its consolidated operations and
its consolidated cash flows for each of the three years in the period ended
December 31, 2002 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.
The Company changed its method of accounting for goodwill in 2002 and
for derivative financial instruments in 2001. These changes are discussed in
Notes 8 and 1, respectively, to the consolidated financial statements.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 7, 2003
F-53
ENTERPRISE PRODUCTS OPERATING L.P.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
DECEMBER 31,
---------------------------------------
2002 2001
---------------------------------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents (includes restricted cash of $8,751 at
December 31, 2002 and $5,752 at December 31, 2001) $ 20,795 $ 137,823
Accounts and notes receivable - trade, net of allowance for doubtful accounts
of $21,196 at December 31, 2002 and $20,642 at December 31, 2001 399,187 256,024
Accounts receivable - affiliates 3,369 4,405
Inventories 167,369 62,942
Prepaid and other current assets 48,137 51,110
---------------------------------------
Total current assets 638,857 512,304
PROPERTY, PLANT AND EQUIPMENT, NET 2,810,839 1,306,790
INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES 396,993 398,201
INTANGIBLE ASSETS, NET OF ACCUMULATED AMORTIZATION OF $25,546 AT
DECEMBER 31, 2002 AND $13,084 AT DECEMBER 31, 2001 277,661 202,226
GOODWILL 81,547
DEFERRED TAX ASSET 15,846
OTHER ASSETS 9,818 5,201
---------------------------------------
TOTAL $ 4,231,561 $ 2,424,722
=======================================
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt $ 15,000
Accounts payable - trade 67,283 $ 54,269
Accounts payable - affiliates 40,773 33,691
Accrued gas payables 489,562 227,035
Accrued expenses 35,760 22,233
Accrued interest 30,338 24,302
Other current liabilities 42,644 44,767
---------------------------------------
Total current liabilities 721,360 406,297
LONG-TERM DEBT 2,231,463 855,278
OTHER LONG-TERM LIABILITIES 7,666 8,061
MINORITY INTEREST 59,336 1,468
COMMITMENTS AND CONTINGENCIES
PARTNERS' EQUITY
Limited Partner 1,211,593 1,148,124
General Partner 12,363 11,716
Parent's Units acquired by Trust (8,660) (6,222)
Accumulated Other Comprehensive Loss (3,560)
---------------------------------------
Total Partners' Equity 1,211,736 1,153,618
---------------------------------------
TOTAL $ 4,231,561 $ 2,424,722
=======================================
See Notes to Consolidated Financial Statements
F-54
ENTERPRISE PRODUCTS OPERATING L.P.
STATEMENTS OF CONSOLIDATED OPERATIONS AND COMPREHENSIVE INCOME
(DOLLARS IN THOUSANDS)
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
REVENUES
Revenues from consolidated operations
Third parties $ 3,102,066 $ 2,641,913 $ 2,689,541
Related parties 482,717 512,456 359,479
---------------------------------------------------
Total revenues 3,584,783 3,154,369 3,049,020
---------------------------------------------------
COST AND EXPENSES
Operating costs and expenses
Third parties 2,686,982 2,052,321 1,953,341
Related parties 695,579 809,422 847,719
Selling, general and administrative
Third parties 18,460 10,863 12,665
Related parties 24,204 19,949 15,680
---------------------------------------------------
Total costs and expenses 3,425,225 2,892,555 2,829,405
---------------------------------------------------
EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES 35,253 25,358 24,119
---------------------------------------------------
OPERATING INCOME 194,811 287,172 243,734
---------------------------------------------------
OTHER INCOME (EXPENSE)
Interest expense (101,580) (52,456) (33,329)
Interest income from related parties 139 15 1,662
Dividend income from unconsolidated affiliates 4,737 3,462 7,091
Interest income - other 2,846 7,773 4,295
Other, net (230) (1,104) (272)
---------------------------------------------------
Other income (expense) (94,088) (42,310) (20,553)
---------------------------------------------------
INCOME BEFORE PROVISION FOR
INCOME TAXES AND MINORITY INTEREST 100,723 244,862 223,181
PROVISION FOR INCOME TAXES (1,634)
---------------------------------------------------
INCOME BEFORE MINORITY INTEREST 99,089 244,862 223,181
MINORITY INTEREST (2,137) (144) (113)
---------------------------------------------------
NET INCOME 96,952 244,718 223,068
Cumulative transition adjustment related to financial instruments
recorded upon adoption of SFAS No. 133 (see Note 16) (42,190)
Reclassification of cumulative transition adjustment to earnings 42,190
Change in fair value of financial instruments
recorded as cash flow hedges (3,560)
---------------------------------------------------
COMPREHENSIVE INCOME $ 93,392 $ 244,718 $ 223,068
===================================================
See Notes to Consolidated Financial Statements
F-55
ENTERPRISE PRODUCTS OPERATING L.P.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(DOLLARS IN THOUSANDS)
FOR YEAR ENDED DECEMBER 31,
-------------------------------------------
2002 2001 2000
-------------------------------------------
OPERATING ACTIVITIES
Net income $ 96,952 $ 244,718 $ 223,068
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities:
Depreciation and amortization in operating costs and expenses 86,029 48,775 35,621
Depreciation in selling, general and administrative costs 77 2,341 1,689
Amortization in interest expense 8,819 787 3,735
Equity in income of unconsolidated affiliates (35,253) (25,358) (24,119)
Distributions received from unconsolidated affiliates 57,662 45,054 37,267
Leases paid by EPCO 9,125 10,414 10,644
Minority interest 2,137 144 113
Loss (gain) on sale of assets (1) (390) 2,270
Deferred income tax expense 2,080
Changes in fair market value of financial
instruments (see Note 16) 10,213 (5,697)
Net effect of changes in operating accounts 86,045 (34,663) 68,635
-------------------------------------------
Operating activities cash flows 323,885 286,125 358,923
-------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (72,135) (149,896) (243,913)
Proceeds from sale of assets 165 568 92
Business acquisitions, net of cash acquired (1,620,727) (225,665)
Acquisition of intangible asset (2,000)
Collection of note receivable from unconsolidated affiliate 6,519
Investments in and advances to unconsolidated affiliates (13,651) (116,220) (31,496)
-------------------------------------------
Investing activities cash flows (1,708,348) (491,213) (268,798)
-------------------------------------------
FINANCING ACTIVITIES
Borrowings under debt agreements 1,968,000 449,717 598,818
Repayments of debt (637,000) (490,000)
Debt issuance costs (19,329) (3,125) (4,043)
Cash distributions to partners (224,470) (167,044) (141,472)
Cash distributions to minority interest (1,191) (59) (146)
Cash contributions from partners 182,509
Cash contributions from minority interest 1,354 379 5
Parent's Units acquired by consolidated Trust (2,438) (18,003)
Parent's Units reissued by consolidated Trust 22,600
Increase in restricted cash (2,999) (5,752)
-------------------------------------------
Financing activities cash flows 1,264,436 278,713 (36,838)
-------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (120,027) 73,625 53,287
CASH AND CASH EQUIVALENTS, JANUARY 1 132,071 58,446 5,159
-------------------------------------------
CASH AND CASH EQUIVALENTS, DECEMBER 31 $ 12,044 $ 132,071 $ 58,446
===========================================
See Notes to Consolidated Financial Statements
F-56
ENTERPRISE PRODUCTS OPERATING L.P.
STATEMENTS OF CONSOLIDATED PARTNERS' EQUITY
(DOLLARS IN THOUSANDS)
LIMITED GENERAL PARENT'S ACCUM.
PARTNER PARTNER UNITS OCI TOTAL
-----------------------------------------------------------------------
Balances, December 31, 1999 $ 791,279 $ 8,074 $ (4,727) $ 794,626
Net income 220,815 2,253 223,068
Leases paid by EPCO 10,537 107 10,644
Asset contributions by partners related to
business acquisitions 55,241 564 55,805
Cash distributions to partners (140,043) (1,429) (141,472)
-----------------------------------------------------------------------
Balances, December 31, 2000 937,829 9,569 (4,727) 942,671
Net income 242,246 2,472 244,718
Leases paid by EPCO 10,309 105 10,414
Asset contributions by partners related to
business acquisitions 117,067 1,195 118,262
Cash distributions to partners (165,357) (1,687) (167,044)
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 6,030 62 6,092
Cumulative transition adjustment
recorded per SFAS No. 133 $ 42,190 42,190
Reclassification of cumulative
transition adjustment to earnings (42,190) (42,190)
-----------------------------------------------------------------------
Balances, December 31, 2001 1,148,124 11,716 (6,222) - 1,153,618
Net income 95,973 979 96,952
Leases paid by EPCO 9,033 92 9,125
Contributions from partners 180,665 1,844 182,509
Cash distributions to partners (222,202) (2,268) (224,470)
Treasury Units acquired by consolidated
Trust (2,438) (2,438)
Change in fair value of financial
instruments recorded as cash flow hedges
(see Note 16) (3,560) (3,560)
-----------------------------------------------------------------------
Balances, December 31, 2002 $ 1,211,593 $ 12,363 $ (8,660) $ (3,560) $ 1,211,736
=======================================================================
See Notes to Consolidated Financial Statements
F-57
ENTERPRISE PRODUCTS OPERATING L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ENTERPRISE PRODUCTS OPERATING L.P. (a Delaware limited partnership)
was formed in April 1998 to acquire, own and operate all of the NGL processing
and distribution assets of Enterprise Products Company ("EPCO"). We conduct
substantially all of the business of our Limited Partner and parent, Enterprise
Products Partners L.P. ("EPPLP"), which owns 98.9899% of our equity interests.
Enterprise Products GP, LLC (the "General Partner") owns the remaining 1.0101%
of our equity interests. Both the Limited Partner and General Partner are
affiliates of EPCO. Our principal executive offices are located at 2727 North
Loop West, Houston, Texas 77008-1038 and our telephone number is 713-880-6500.
Unless the context requires otherwise, references to "we","us","our" or the
"Company" are intended to mean Enterprise Products Operating L.P. and
subsidiaries.
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.
On May 8, 1998, EPCO contributed all of its NGL assets to us (through
our Limited and General Partners) and we assumed certain of EPCO's debt. As a
result, we became the successor to the NGL operations of EPCO.
Effective July 27, 1998, our Limited Partner filed a registration
statement pursuant to an initial public offering ("IPO") of 24,000,000 Common
Units. The Common Units sold for $11 per unit. As a result, our Limited Partner
contributed the proceeds of its IPO of approximately $243.3 million net of
underwriting commissions and offering costs to the Company.
The consolidated financial statements include our accounts and those of
our majority-owned subsidiaries in which we have a controlling interest, after
elimination of all material intercompany accounts and transactions. The
majority-owned subsidiaries are identified based upon the determination that the
Company possesses a controlling financial interest through direct or indirect
ownership of a majority voting interest in the subsidiary. 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.
Equity method investments are evaluated for impairment whenever events
or changes in circumstances indicate that there is a loss in value of the
investment which is other than a temporary decline. The Company considers events
affecting its equity method investments such as if they had continuing operating
losses or significant and long-term changes in their industry conditions as
examples of indicators of potential impairment. In the event that we determine
that the loss in value of an investment is other than a temporary decline, we
would record a charge to earnings to adjust the carrying value to fair value. We
had no such impairment charges for 2002, 2001 and 2000.
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.
DOLLAR AMOUNTS presented in the tabulations within the notes to our
financial statements are stated in thousands of dollars, unless otherwise
indicated.
F-58
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, 2002 were not significant to the
consolidated financial statements. Costs of environmental compliance and
monitoring aggregated $1.7 million, $1.3 million and $1.3 million for the years
ended December 31, 2002, 2001 and 2000, 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 Promix, Dixie, Neptune, La Porte and Nemo. The excess cost of
these investments is reflected in our investments in and advances to
unconsolidated affiliates for these entities. See Note 7 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 accounts
receivable, and volumes loaned to us under such agreements are accrued as a
liability in accrued gas payables.
FINANCIAL INSTRUMENTS such as swaps, forward and other contracts to
manage the price risks associated with inventories, firm commitments, interest
rates and certain anticipated transactions are used by the Company. We
recognize our transactions on the balance sheet as assets and liabilities based
on the instrument's fair value. 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. Changes in fair
value of financial instrument contracts are recognized currently in earnings
unless specific hedge accounting criteria are met. If the financial instruments
meet those criteria, the instrument's gains and losses offset related results
of the hedge item in the income statement for a fair value hedge and are
deferred in other comprehensive income for a cash flow hedge. Gains and losses
on a cash flow hedge are reclassified into earnings when the forecasted
transaction occurs. A contract designated as a hedge of an anticipated
transaction that is no longer likely to occur is immediately recognized in
earnings.
To qualify as a hedge, the item to be hedged must expose us to
commodity or interest rate risk and the hedging instrument must reduce the
exposure and meet the hedging requirements of SFAS No. 133. We must formally
designate the financial instrument as a hedge and document and assess the
effectiveness of the hedge at inception and on a quarterly basis. Any
ineffectiveness is recorded into earnings immediately.
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.
GOODWILL consists of the excess of amounts we paid for businesses and
assets over the respective fair value of the underlying net assets purchased
(see Note 8). Since adopting SFAS No. 142, "Goodwill and Other Intangible
Assets", on January 1, 2002, our goodwill amounts are no longer amortized but
will be assessed annually for recoverability. In addition, we will periodically
review the reporting units to which the goodwill amounts relate if impairment
indicators are evident. If such indicators are present (i.e., loss of a
significant customer, economic obsolescence of plant assets, etc.), the fair
value of the reporting unit, including its related goodwill, will be calculated
and compared to its combined book value. If the fair value of the reporting
unit exceeds its book value, goodwill is not considered impaired and no
adjustment to earnings would be required. Should the fair value of the
reporting unit (including its goodwill) be less than its book value, a charge
to earnings would be recorded to adjust goodwill to its implied fair value. We
have not recognized any impairment losses related to our goodwill for any of
the periods presented.
F-59
INVENTORIES primarily consist of NGL, petrochemical and natural gas
volumes and are valued at the lower of average cost or market (see Note 5).
Shipping and handling charges directly related to volumes we purchase or to
which we take ownership are capitalized as costs of inventory. As these
inventories are sold and delivered out of inventory, the average cost of these
products (which includes freight-in charges which have been capitalized) are
charged to current period operating costs and expenses. Shipping and handling
charges for products we sell and deliver to customers are charged to operating
costs and expenses as incurred.
INTANGIBLE ASSETS consist primarily of the estimated value of contract
rights we own arising from agreements with customers (see Note 8). A
contract-based intangible asset with a finite useful life is amortized over its
estimated useful life, which is the period over which the asset is expected to
contribute directly or indirectly to the future cash flows of the entity. It is
based on an analysis of all pertinent factors including (a) the expected use of
the asset by the entity, (b) the expected useful life of related assets (i.e.,
fractionation facility, storage well, etc.), (c) any legal, regulatory or
contractual provisions, including renewal or extension periods that would not
cause substantial costs or modifications to existing agreements, (d) the
effects of obsolescence, demand, competition, and other economic factors and
(e) the level of maintenance required to obtain the expected future cash flows.
LONG-LIVED ASSETS (including intangible assets with finite useful
lives and property, plant and equipment) 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.
Long-lived assets with recorded values that are not expected to be
recovered through future cash flows are written-down to estimated fair value in
accordance with SFAS No. 144 "Accounting for the Impairment or Disposal of
Long-Lived Assets." Under SFAS 144, an asset shall be tested for impairment
when events or circumstances indicate that its carrying value may not be
recoverable. The carrying value of a long-lived asset is not recoverable if it
exceeds the sum of the undiscounted cash flows expected to result from the use
and eventual disposition of the asset. If the carrying value exceeds the sum of
the undiscounted cash flows, an impairment loss equal to the amount the
carrying value exceeds the fair value of the asset is recognized. Fair value is
generally determined from estimated discounted future net cash flows. We
adopted SFAS 144 on January 1, 2002, and there have been no events or
circumstances indicating that the carrying value of any of our assets may not
be recoverable.
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. 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) as
expansion capital expenditures.
PROVISION FOR INCOME TAXES is only applicable to the tax obligation of
our Seminole pipeline business, which is a corporation and the only entity
subject to income taxes in the consolidated group. The income tax provision
relates solely to Seminole's earnings before income taxes for the five month
period ended December 31, 2002. Deferred income tax assets and liabilities for
Seminole are recognized for temporary differences between the assets and
liabilities for financial reporting and tax purposes (see Note 11).
In and of itself, our partnership structure is not subject to federal
income taxes. Accordingly, our owners are individually responsible for the
taxes on their allocable share of our consolidated taxable income.
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, 2002 and
2001, cash and cash equivalents includes $8.8 million and $5.8 million of
restricted cash related to these requirements, respectively.
F-60
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. For additional information regarding our revenue recognition process,
please see Note 2.
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. Our allowance amount is generally determined as a
percentage of revenues for the last twelve months. Our procedure for recording
an allowance for doubtful accounts is based on historical experience, financial
stability of our customers and levels of credit granted to customers. In
addition, we may also increase the allowance account in response to specific
identification of customers involved in bankruptcy proceedings and those
experiencing financial uncertainties. We routinely review our estimates in this
area to ascertain that we have recorded sufficient reserves to cover forecasted
losses. Our allowance for doubtful accounts was $21.2 million and $20.6 million
at December 31, 2002 and 2001, respectively.
UNIT OPTION PLAN ACCOUNTING for reimbursement to EPCO under its 1998
Plan is accounted for by applying APB Opinion No. 25, "Accounting for Stock
Issued to Employees," in accounting for equity-based awards granted to EPCO's
employees whereby no compensation expense is recorded related to the options
granted when the exercise price equals the market price of the underlying
equity issue on the date of grant. See Note 13 for the pro forma effect on our
net income, as if compensation expense had been determined based on the
Black-Scholes option pricing model value at the grant date for equity-based
awards consistent with the provisions of SFAS No. 123, "Accounting for
Stock-Based Compensation." No compensation expense was recorded during the
years ended December 31, 2002, 2001 and 2000, since the equity-based awards
were granted at exercise prices equal to the market prices at the date of
grant.
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. REVENUE RECOGNITION
The following summarizes our revenue recognition process by business segment:
Pipelines segment revenues. In our Pipelines segment, we enter into
pipeline, storage and product handling contracts. Under our NGL, petrochemical
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 various governmental agencies,
including the Federal Energy Regulatory Commission ("FERC"). Additionally, we
have product sales contracts associated with our natural gas pipeline business
whereby revenue is recognized when we sell and deliver a volume of natural gas
to a customer. These natural gas sales contracts are based upon market-related
prices as determined by the individual agreements.
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 product handling contracts (applicable to our
import and export operations) are recorded once the services have been
performed with the applicable fees stated in the individual contracts.
Fractionation segment revenues. In our Fractionation segment, we enter
into NGL fractionation, isomerization and propylene fractionation tolling
arrangements, NGL fractionation in-kind contracts and propylene fractionation
sales contracts. Under our tolling arrangements, we recognize revenue upon
completion of all contract services and obligations. These tolling arrangements
typically include a base processing fee per gallon (or other unit of
measurement) subject to adjustment for changes in natural gas, electricity and
labor costs, which are the
F-61
principal variable costs of fractionation and isomerization operations. At
certain of our NGL fractionation facilities, an in-kind tolling arrangement is
utilized. An in-kind processing contract allows us to retain a
contractually-determined percentage of NGL products fractionated for our
customer in lieu of collecting a cash tolling fee per gallon. Fractionation
revenue is recognized and recorded on a monthly basis for transfers of
"in-kind" retained NGL products to the NGL working inventory maintained within
our Processing segment where it is then held for sale. Transfer pricing for
these retained NGLs is based upon monthly market posted prices for such
products. This intersegment revenue and offsetting cost to the Processing
segment is eliminated in our reporting of consolidated revenues and expenses.
In our propylene fractionation product sales contracts, we recognize revenue
once the products have been delivered to the customer. Pricing for sales
contracts is based upon market-related prices as determined by the individual
agreements.
Processing segment revenues. As part of our Processing business, we
have entered into a significant 20-year natural gas processing agreement with
Shell (the "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 natural gas processing 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 natural gas processing contract stipulates that we retain a
percentage of the extracted NGLs as payment for our services, revenue is
recognized and recorded when the extracted NGLs are delivered out of our
inventory and sold to customers on sales contracts. Our NGL marketing
activities within this segment also use product sales contracts to sell and
deliver out of inventory the NGLs transferred to it as a result of the
Fractionation segment's in-kind arrangements and those it purchases for cash in
the open market. These NGL sales contracts may include forward product sales
contracts from time-to-time. Revenues from NGL sales contracts are recognized
and recorded upon the delivery of the NGL products specified in each individual
contract. Pricing terms in these sales contracts are based upon market-related
prices for such products and can include pricing differentials due to factors
such differing delivery locations.
Octane Enhancement segment revenues. 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. Gross operating margin for this
segment consists of our equity earnings from BEF, which in turn is dependent
upon is BEF's general revenue recognition policy. 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. BEF recognizes its revenue once the product has
been delivered to Sun.
Other segment revenues. Revenues shown for our Other segment are
primarily derived from 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 in our revenue recognition process. 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 routine nature of these
estimates.
3. RECENTLY ISSUED ACCOUNTING STANDARDS
We adopted SFAS No. 142, "Goodwill and Other Intangible Assets", on
January 1, 2002. This standard establishes accounting standards for all
goodwill and other intangible assets recognized in our consolidated balance
sheet. In addition, we adopted SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets"
F-62
on January 1, 2002. This statement addresses financial accounting and reporting
for the impairment and/or disposal of long-lived assets. For information
regarding our goodwill and intangible assets see Note 8. For information
regarding our accounting policy for long-lived assets, please see Note 1.
We adopted SFAS No. 143, "Accounting for Asset Retirement
Obligations," on January 1, 2003. This statement establishes accounting
standards for the recognition and measurement of a liability for an asset
retirement obligation ("ARO") and the associated asset retirement cost. An ARO
exists when a company determines that it has a clearly defined legal obligation
upon retirement of a long-lived asset or any component part thereof and that
the legal obligation will lead to the future payment of funds to a third party
upon retirement of the asset. In general, legal obligations underlying AROs
result from enacted laws and regulations or from contractual provisions related
to long-lived assets. AROs can also arise through the normal course of
operating a long-lived fixed asset.
An ARO liability will be recorded on the balance sheet if a reasonable
estimate of fair value of the obligation can be made. Our estimate of fair
value for each ARO is primarily dependent upon a clearly defined plan of
retirement (dates, methods, etc.) and costs associated with the retirement
activity. If a reasonable estimate cannot be made (i.e., no current or required
plans for retirement of the asset, etc.), footnote disclosure is required but
the ARO is not recorded until a reasonable estimate can be made. Any earnings
impact resulting from the recognition of an ARO upon adoption of SFAS No. 143
should be reflected as the cumulative effect of a change in accounting
principle.
Upon adoption of SFAS No. 143, we reviewed our long-lived assets for
ARO's by segment. We identified, but have not recognized, ARO liabilities in
several operational areas. These include ARO liabilities related to easements
over property not currently owned by us. Our rights to the easements are
renewable and only require retirement action upon nonrenewal of the easement
agreements. We currently plan to renew all such easement agreements and use
these properties indefinitely. Therefore, the ARO liability is not estimable
for such easements. If we decide not to renew these agreements, an ARO
liability would be recorded at that time.
ARO liabilities related to statutory regulatory requirements for
abandonment or retirement of certain currently operated facilities were also
identified. We currently have no intention or legal obligation to abandon or
retire such facilities. An ARO liability would be recorded if future
abandonment or retirement occurred.
Certain Gulf of Mexico natural gas pipelines, in which we have an
equity interest, have identified ARO's relating to regulatory requirements.
There is no current intention to abandon or retire these pipelines. If these
pipelines were abandoned or retired, an ARO liability would then be disclosed.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." This standard requires companies
to recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to exit or disposal plan.
Examples of costs covered by the standard include lease termination costs and
certain employee severance costs that are associated with a restructuring,
discontinued operations, plant closing, or other exit or disposal activity.
Previous accounting guidance was provided by EITF Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit
an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No.
146 replaces Issue 94-3. SFAS No. 146 is to be applied prospectively to exit or
disposal activities initiated after December 31, 2002. We adopted this
statement on January 1, 2003 and determined that it had no material impact on
our financial statements.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements from Guarantees, Including Indirect
Guarantees of Indebtedness of Others". This interpretation of SFAS No. 5, 57
and 107, and rescission of FASB Interpretation No. 34 elaborates on the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued.
It also clarifies that a guarantor is required to recognize, at the inception
of a guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. The initial recognition and initial measurement
provisions of this interpretation are applicable on a prospective basis to
guarantees issued or modified after December 31, 2002. The disclosure
requirements in this interpretation are applicable for financial statements of
interim or annual periods after December 15, 2002. See Note 9 for the
disclosure of Parent-Subsidiary guarantor relationships.
F-63
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation-Transition and Disclosure," which provides alternative
methods of transition from a voluntary change to the fair value based method of
accounting for stock-based employee compensation. In addition, SFAS No. 148
amends the disclosure requirements of SFAS No. 123 in both annual and interim
financial statements. SFAS No. 148 is effective for financial statements for
fiscal years ending after December 15, 2002, and financial reports containing
condensed financial statements for interim periods beginning after December 15,
2002. EPCO has stock-based employee compensation plans for which we have a
funding commitment for certain employees, see Note 13. We do not believe that
the adoption of this statement will have a material effect on our financial
statements.
4. BUSINESS ACQUISITIONS
ACQUISITION OF MID-AMERICA AND SEMINOLE IN JULY 2002
On July 31, 2002, we acquired equity interests in affiliates of
Williams, which in turn, own controlling interests in Mid-America Pipeline
Company, LLC ("Mid-America," formerly Mid-America Pipeline Company) and
Seminole Pipeline Company ("Seminole"). The purchase price of the acquisitions
was approximately $1.2 billion. The acquisition of Mid-America and Seminole
significantly enhances our existing asset base by:
o accessing NGL-rich natural gas production in major North American
natural gas producing regions;
o expanding our integrated natural gas and NGL network;
o providing access to new end markets for NGL products; and
o increasing our gross margins from fee-based businesses.
In addition to our current strategic position in the Gulf of Mexico,
we now have access to major supply basins throughout North America, including
the Rocky Mountain Overthrust, the San Juan and Permian basins, the
Mid-Continent region and, through third-party pipeline connections, north into
Canada's Western Sedimentary basin. The combination of these assets with our
existing assets also creates a significant link between Mont Belvieu, Texas and
Conway, Kansas, the two largest NGL hubs in the United States. They also
provide additional access to new end markets for NGL products.
The acquisitions include a 98% ownership interest in Mapletree, LLC,
which is the sole owner of Mid-America and certain propane terminals and
storage facilities. Mid-America owns a regulated 7,226-mile major NGL pipeline
system (the "Mid-America Pipeline System") consisting of three NGL pipelines:
the 2,548-mile Rocky Mountain pipeline, the 2,740-mile Conway North pipeline,
and the 1,938-mile Conway South pipeline. The Rocky Mountain system transports
mixed NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to the
Hobbs hub located on the Texas-New Mexico border. The Conway North segment
links the large NGL hub at Conway, Kansas to refineries and propane markets in
the upper Midwest. In addition, the Conway North segment has access to, through
third-party pipeline connections, NGL supplies from Canada's Western
Sedimentary basin. The Conway South system connects the Conway hub with Kansas
refineries and transports mixed NGLs from Conway, Kansas to the Hobbs hub (with
interconnections to the Seminole Pipeline System at the Hobbs hub).
We also acquired a 98% ownership interest in E-Oaktree, LLC, owner of
an 80% equity interest in Seminole. Seminole owns a regulated 1,281-mile
pipeline (the "Seminole Pipeline System") that transports mixed NGLs and NGL
products from the Hobbs hub on the Texas-New Mexico border and the Permian
Basin area to Mont Belvieu, Texas. The primary source of throughput for the
Seminole system are those volumes originating from the Mid-America system.
The initial funding for these acquisitions was accomplished by
entering into a $1.2 billion 364-day credit facility (the "364-Day Term Loan";
see Note 9 for a description of this debt). This temporary credit facility was
extinguished in February 2003 when we completed our plans for the permanent
financing of these acquisitions (see our discussion of subsequent events in
Note 19). These acquisitions did not require any material governmental
approvals.
F-64
ACQUISITION OF DIAMOND-KOCH PROPYLENE FRACTIONATION BUSINESS IN FEBRUARY 2002
In February 2002, we purchased various propylene fractionation assets
and certain inventories of refinery grade propylene, propane, and polymer grade
propylene from Diamond-Koch. These include a 66.7% interest in a polymer grade
propylene fractionation facility located in Mont Belvieu, Texas (the "Splitter
III" facility), a 50% 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. Splitter III has the capacity to produce approximately 41
MBPD of polymer grade propylene. These assets are part of our Mont Belvieu
propylene fractionation operations, which is part of the Fractionation segment.
The purchase price of $239.0 million was funded by a drawdown on our Multi-Year
and 364-Day Revolving Credit facilities.
ACQUISITION OF DIAMOND-KOCH STORAGE BUSINESS IN JANUARY 2002
In January 2002, we purchased various hydrocarbon storage assets from
Diamond-Koch. The storage facility consists of 25 operational salt dome storage
caverns with a useable capacity of 64 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
and serve the largest petrochemical and refinery complex in the United States.
These assets are part of our Mont Belvieu storage operations, which is part of
the Pipelines segment. The purchase price of $129.6 million was funded by
utilizing cash on hand.
OTHER MINOR ACQUISITIONS COMPLETED DURING 2002
We completed the purchase of an additional interest in our Mont
Belvieu NGL fractionator from ChevronTexaco, the acquisition of a gas
processing plant and NGL fractionator in Louisiana from Western Resources and
certain NGL terminal assets from CornerStone during 2002. Due to the immaterial
nature of each of these acquisitions, our discussion of each is limited to the
following:
Acquisition of ChevronTexaco's interest in our Mont Belvieu NGL
fractionator. Effective June 2002, we finalized the acquisition of a 12.5%
undivided ownership interest in our Mont Belvieu, Texas NGL fractionator from
an affiliate of ChevronTexaco. The purchase price of approximately $8.1 million
was paid in May 2002. As a result of this transaction, our ownership interest
in the Mont Belvieu NGL fractionator increased to 75.0% from 62.5%.
Acquisition of gas processing and NGL fractionator assets from Western
Gas Resources, Inc. Effective June 2002, we acquired a 160 MMcf/d natural gas
processing plant, a 14.2 MBPD NGL fractionator and supporting assets (including
contracts) from Western Gas Resources, Inc. for approximately $32.6 million.
The "Toca-Western" facilities are located in St. Bernard Parish, Louisiana near
our existing Toca natural gas processing plant.
Acquisition of NGL terminals from CornerStone. In November 2002, we
purchased four NGL terminals and existing propane inventories from an affiliate
of CornerStone for approximately $11.5 million. The terminals are located in
Bakersfield and Rocklin, California; Reno, Nevada and Albertville, Alabama. In
addition, we acquired storage facilities related to these terminals with a
capacity of 0.1 million barrels. These terminals will support our NGL marketing
activities and fee-based marketing services.
ACADIAN GAS POST-CLOSING ADJUSTMENTS COMPLETED IN APRIL 2002
In April 2002, we finalized the post-closing purchase price adjustment
associated with our April 2001 acquisition of Acadian Gas. Acadian Gas was
acquired from an affiliate of Shell and is involved in the purchase, sale,
transportation and storage of natural gas in Louisiana. As a result, we paid
Shell $18.0 million for various working capital items, the majority of which
were related to natural gas inventories.
F-65
ALLOCATION OF AMOUNTS PAID DURING 2002
The acquisitions and post-closing adjustments described previously
were accounted for under the purchase method of accounting and, accordingly,
the cost of each has been allocated to the assets acquired and liabilities
assumed based on their estimated fair values as follows:
D-K
D-K PROPYLENE MID-AMERICA
STORAGE FRACTIONATION AND SEMINOLE OTHER TOTAL
----------------------------------------------------------------------
Accounts and notes receivable $ 11,777 $ (120) $ 11,657
Accounts receivable - affiliates 7,799 7,799
Inventories $ 4,994 10,776 4,403 20,173
Prepaids and other current assets $ 890 3,148 9,204 416 13,658
Property, plant and equipment 120,571 96,772 1,265,264 24,636 1,507,243
Investments in unconsolidated affiliates 7,550 7,550
Intangible assets 8,127 53,000 31,229 92,356
Goodwill 73,691 73,691
Deferred tax asset 17,307 17,307
Other assets 2,699 2,699
Accounts payable - affiliates (7,799) (7,799)
Accrued expenses (5,529) (5,529)
Accrued interest (667) (667)
Other current liabilities (107) (12,226) 8,581 (3,752)
Long-term debt (60,000) (60,000)
Other long-term liabilities (90) (90)
Minority interest (55,569) (55,569)
------------------------------------------------------------------------
Total purchase price $ 129,588 $ 239,048 $1,182,946 $ 69,145 $1,620,727
========================================================================
The fair value estimates for both Diamond-Koch transactions;
Mid-America and Seminole; the Toca-Western and CornerStone acquisitions were
developed by independent appraisers using recognized business valuation
techniques. The Mid-America, Seminole and CornerStone allocations are
preliminary pending completion of a final review of these businesses which is
expected to be completed during the first quarter of 2003. The purchase price
allocations related to the Acadian Gas post-closing adjustment and the
acquisition of ChevronTexaco's interest in our Mont Belvieu NGL fractionator
are based on previously issued fair value reports.
The purchase price paid for the propylene fractionation business
resulted in goodwill of $73.7 million. The goodwill primarily represents the
value management has attached to future earnings improvements and to the
strategic location of the assets. Earnings from the propylene business are
expected to improve substantially from the last few years with the years 2005
and 2006 projected to be peak years in the petrochemical business cycle based
on industry forecasts. The propylene fractionation assets are located in Mont
Belvieu, Texas on the Gulf Coast, the largest natural gas liquids and
petrochemical marketplace in the U.S. The assets have access to substantial
supply from major Gulf Coast and central U.S. producers of refinery grade
propylene. The polymer grade products produced at the facility have competitive
advantages because of distribution direct to customers via affiliated pipelines
and through an affiliated export facility. For additional information regarding
our goodwill, see Note 8.
COMBINED PRO FORMA EFFECT OF MID-AMERICA, SEMINOLE, DIAMOND-KOCH AND
ACADIAN GAS BUSINESS ACQUISITIONS
The following table presents unaudited pro forma financial information
incorporating the historical (pre-acquisition) financial results of the
following acquired businesses:
o D-K storage (acquired January 1, 2002) and propylene fractionation
(acquired February 1, 2002);
o Mid-America and Seminole (both acquired July 31, 2002); and
o Acadian Gas (acquired April 1, 2001).
F-66
Our historical Statements of Consolidated Operations and Comprehensive
Income reflect the operations of each acquired business since their respective
acquisition dates.
The following pro forma information has been prepared as if the
acquisitions had been completed on January 1 of the respective periods
presented as opposed to the actual dates that these acquisitions occurred. The
pro forma information is based upon data currently available to and certain
estimates and assumptions made by management. As a result, this information is
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,
---------------------------------------
2002 2001
---------------------------------------
PRO FORMA EARNINGS DATA
Revenues $ 3,784,286 $ 3,952,896
Operating income $ 275,498 $ 383,865
Net income $ 132,334 $ 254,968
PRO FORMA EARNINGS ALLOCATION
To Limited Partner $ 130,997 $ 252,393
To General Partner $ 1,337 $ 2,575
Pro forma net income for each year includes (among other pro forma
adjustments) the impact of interest expense associated with the 364-Day Term
Loan we used to fund the Mid-America and Seminole acquisitions. The pro forma
results for 2001 assume that the initial $1.2 billion borrowed under this
facility was outstanding during the entire year. The pro forma results for 2002
reflect our actual repayment of a portion of this debt using contributions
related to our Limited Partner's October 2002 equity offering and our General
Partner's related contribution. The pro forma earnings data do not reflect
contributions from our Limited Partner's January 2003 equity offering nor our
January 2003 issuance of Senior Notes C or February 2003 issuance of Senior
Notes D. The proceeds from these equity and debt offerings were used to fully
repay the 364-Day Term Loan by the end of February 2003. For additional
information regarding these subsequent events, see Note 19.
5. INVENTORIES
Our inventories were as follows at the dates indicated:
DECEMBER 31,
-------------------------------------
2002 2001
-------------------------------------
Working inventory $ 131,769 $ 29,393
Forward-sales inventory 35,600 33,549
-------------------------------------
Inventory $ 167,369 $ 62,942
=====================================
A description of each inventory is as follows:
o Our regular trade (or "working") inventory is comprised of
inventories of natural gas, NGLs and petrochemical products that are
available for sale. This inventory is valued at the lower of average
cost or market, with "market" being determined by industry-related
posted prices such as those published by OPIS and CMAI.
o The forward-sales inventory is comprised of segregated NGL volumes
dedicated to the fulfillment of forward sales contracts and is valued
at the lower of average cost or market, with "market" being defined
as the weighted-average sales price for NGL volumes to be delivered
in future months on the forward sales contracts.
In general, our inventory values reflect amounts we have paid for
product purchases, freight charges associated with such purchase volumes,
terminal and storage fees, vessel inspection and demurrage charges and other
handling and processing costs. In those instances where we take ownership of
inventory volumes through
F-67
in-kind and similar arrangements (as opposed to actually purchasing volumes for
cash from third parties, see Note 2), these volumes are valued at market-related
prices during the month in which they are acquired. Like the third-party
purchases described above, we inventory the various ancillary costs such as
freight-in and other handling and processing amounts associated with owned
volumes obtained through our in-kind and similar contracts.
Due to fluctuating market conditions in the NGL, natural gas and
petrochemical industry, we occasionally recognize lower of average cost or
market ("LCM") adjustments when the cost of our inventories exceed their net
realizable value. These non-cash adjustments are charged to operating costs and
expenses in the period they are recognized and generally affect our segment
operating results in the following manner:
o NGL inventory write-downs are recorded as a cost of the Processing
segment's NGL marketing activities;
o Natural gas inventory write downs are recorded as a cost of the
Pipeline segment's Acadian Gas operations; and
o Petrochemical inventory write downs are recorded as a cost of the
Fractionation segment's propylene fractionation business.
For the years ended December 31, 2002, 2001 and 2000, we recognized
LCM adjustments of approximately $6.3 million, $40.7 million and $6.9 million,
respectively. The majority of these write-downs were taken against NGL
inventories. To the extent our commodity hedging strategies address
inventory-related risks and are successful, these inventory valuation
adjustments are mitigated (or in some cases, offset). See Note 16 for a
description of our commodity hedging activities.
6. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment and accumulated depreciation were as
follows at the dates indicated:
ESTIMATED DECEMBER 31,
USEFUL LIFE -------------------------------------
IN YEARS 2002 2001
---------------------------------------------------
Plants and pipelines 5-35 $ 2,860,180 $ 1,398,843
Underground and other storage facilities 5-35 283,114 127,900
Transportation equipment 3-35 5,118 3,736
Land 23,817 15,517
Construction in progress 49,586 98,844
-------------------------------------
Total 3,221,815 1,644,840
Less accumulated depreciation 410,976 338,050
-------------------------------------
Property, plant and equipment, net $ 2,810,839 $ 1,306,790
=====================================
Depreciation expense for the years ended December 31, 2002, 2001 and
2000 was $72.5 million, $43.4 million and $33.3 million, respectively.
7. 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 business segments, see Note
18. The following table shows our investments in and advances to unconsolidated
affiliates at:
F-68
DECEMBER 31,
OWNERSHIP ----------------------------------------
PERCENTAGE 2002 2001
----------------------------------------------------------
Accounted for on equity basis:
Fractionation:
BRF 32.25% $ 28,293 $ 29,417
BRPC 30.00% 17,616 18,841
Promix 33.33% 41,643 45,071
La Porte 50.00% 5,737
OTC 50.00% 2,178
Pipeline:
EPIK 50.00% 11,114 14,280
Wilprise 37.35% 8,566 8,834
Tri-States 33.33% 25,552 26,734
Belle Rose 41.67% 11,057 11,624
Dixie 19.88% 36,660 37,558
Starfish 50.00% 28,512 25,352
Neptune 25.67% 77,365 76,880
Nemo 33.92% 12,423 12,189
Evangeline 49.50% 2,383 2,578
Octane Enhancement:
BEF 33.33% 54,894 55,843
Accounted for on cost basis:
Processing:
VESCO 13.10% 33,000 33,000
----------------------------------------
Total $ 396,993 $ 398,201
========================================
The following table shows our equity in income (loss) of
unconsolidated affiliates for the periods indicated:
FOR YEAR ENDED DECEMBER 31,
OWNERSHIP ---------------------------------------------------
PERCENTAGE 2002 2001 2000
--------------------------------------------------------------------
Fractionation:
BRF 32.25% $ 2,427 $ 1,583 $ 1,369
BRPC 30.00% 997 1,161 (284)
Promix 33.33% 3,936 4,201 5,306
La Porte 50.00% (559)
OTC 50.00% 378
Pipelines:
EPIK 50.00% 4,688 345 3,273
Wilprise 37.35% 948 472 497
Tri-States 33.33% 1,959 1,565 2,499
Belle Rose 41.67% 203 103 301
Dixie 19.88% 1,231 2,092 751
Starfish 50.00% 7,346 4,122
Ocean Breeze 25.67% - 32
Neptune 25.67% 2,111 4,081
Nemo 33.92% 1,077 75
Evangeline 49.50% (58) (145)
Octane Enhancement:
BEF 33.33% 8,569 5,671 10,407
---------------------------------------------------
Total $ 35,253 $ 25,358 $ 24,119
===================================================
F-69
At December 31, 2002, our share of accumulated earnings of equity
method unconsolidated affiliates that had not been remitted to us was
approximately $15.4 million. In addition, our initial investment in Promix, La
Porte, Dixie, Neptune and Nemo exceeded our share of the historical cost of the
underlying net assets of such entities ("excess cost"). The excess cost of
these investments is reflected in our investments in and advances to
unconsolidated affiliates for these entities. The excess cost amounts related
to Promix, La Porte and Nemo are attributable to the tangible plant and
pipeline assets of each entity, and are amortized against equity earnings from
these entities in a manner similar to depreciation. The excess cost of Dixie
includes amounts attributable to both goodwill and tangible pipeline assets,
with the portion assigned to the pipeline assets being amortized in a manner
similar to depreciation. The goodwill inherent in Dixie's excess cost is
subject to periodic impairment testing; therefore, it is not amortized. The
following table summarizes our excess cost information:
AMORTIZATION
UNAMORTIZED BALANCE AT CHARGED AGAINST
INITIAL --------------------------------------- EQUITY
EXCESS DECEMBER 31, DECEMBER 31, EARNINGS AMORTIZATION
COST 2002 2001 DURING 2002 PERIOD
--------------------------------------------------------------------------------------------
Fractionation segment:
Promix $ 7,955 $ 6,596 $ 7,083 $ 398 20 years
La Porte 873 833 n/a 40 35 years
Pipelines segment:
Dixie
Attributable to pipeline assets 28,448 26,074 26,887 813 35 years
Goodwill 9,246 8,827 8,827 n/a n/a
Neptune 12,768 12,039 12,404 365 35 years
Nemo 727 697 718 21 35 years
As used in the following condensed financial data tables, gross
operating margin represents operating income before applicable depreciation and
amortization expense and selling, general and administrative costs. Gross
operating margin is an important measure of the profitability of assets owned
by our unconsolidated affiliates. We regularly evaluate our consolidated
operations on the same basis. Operating income represents earnings before
non-operating income and expense items such interest expense and interest
income. The equity earnings we record from these investments represent our
share of the net income or loss of each.
FRACTIONATION SEGMENT:
At December 31, 2002, the Fractionation segment included the following
unconsolidated affiliates accounted for using the equity method:
o Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25%
interest in an NGL fractionator located in southeastern Louisiana.
o Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% interest
in a propylene fractionator located in southeastern Louisiana.
o K/D/S Promix LLC ("Promix") - a 33.33% interest in an NGL
fractionator and related storage and pipeline assets located in south
Louisiana.
o La Porte Pipeline Company, L.P. and La Porte Pipeline GP, LLC
(collectively "La Porte") - an aggregate 50% interest in a private
polymer grade propylene pipeline extending from Mont Belvieu, Texas
to La Porte, Texas. We do not exercise management control over La
Porte and are precluded from consolidating its financial statements
with our financial statements.
o Olefins Terminal Corporation ("OTC") - a 50% interest in a polymer
grade propylene export facility located in Seabrook, Texas. As with
La Porte, we do not exercise management control over OTC and are
precluded from consolidating its financial statements with our
financial statements.
F-70
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 OF OR FOR THE
YEAR ENDED DECEMBER 31,
-----------------------------------------------
2002 2001 2000
-----------------------------------------------
BALANCE SHEET DATA:
Current assets $ 23,496 $ 27,424
Property, plant and equipment, net 250,096 251,519
--------------------------------
Total assets $ 273,592 $ 278,943
================================
Current liabilities $ 11,229 $ 9,950
Other liabilities 6,800
Combined equity 255,563 268,993
--------------------------------
Total liabilities and combined equity $ 273,592 $ 278,943
================================
INCOME STATEMENT DATA:
Revenues $ 78,350 $ 76,480 $ 71,287
Gross operating margin 40,215 36,321 33,240
Operating income 23,464 22,396 19,997
Net income 23,399 22,738 20,661
PIPELINES SEGMENT:
At December 31, 2002, our Pipelines operating segment included the
following unconsolidated affiliates accounted for using the equity method:
o EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively,
"EPIK") - a 50% aggregate interest in an NGL export terminal located
in southeast Texas. In March 2003, we purchased the remaining
ownership interests in EPIK for $19 million plus certain post-closing
purchase price adjustments, at which time EPIK became a consolidated
subsidiary of ours (see Note 19). Prior to our purchase of the
remaining interests, we did not exercise management control over EPIK
and were precluded from consolidating its financial statements with
our financial statements.
o Wilprise Pipeline Company, LLC ("Wilprise") - a 37.35% interest in an
NGL pipeline system located in southeastern Louisiana.
o Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33%
interest in an NGL pipeline system located in Louisiana, Mississippi
and Alabama.
o Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.67% interest in an
NGL pipeline system located in south Louisiana.
o 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.
o 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. We do not exercise management control over Starfish and
are precluded from consolidating its financial statements with our
financial statements.
o 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.
o 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.
o 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.
F-71
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,
-----------------------------------------------
2002 2001 2000
-----------------------------------------------
BALANCE SHEET DATA:
Current assets $ 76,930 $ 68,325
Property, plant and equipment, net 510,483 515,327
Other assets 47,501 50,265
--------------------------------
Total assets $ 634,914 $ 633,917
================================
Current liabilities $ 60,484 $ 62,347
Other liabilities 56,230 57,965
Combined equity 518,200 513,605
--------------------------------
Total liabilities and combined equity $ 634,914 $ 633,917
================================
INCOME STATEMENT DATA:
Revenues $ 303,567 $ 305,404 $ 96,270
Gross operating margin 112,455 98,682 51,414
Operating income 65,855 54,459 41,757
Net income 56,736 41,015 31,241
OCTANE ENHANCEMENT SEGMENT:
At December 31, 2002, 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 will reduce
the demand for MTBE and could have an adverse effect on our results of
operations.
In recent years, MTBE has been detected in municipal and private water
supplies resulting in various legal actions. BEF has not been named in any MTBE
legal action to date. In light of these legal and regulatory developments, we
and the other two partners of BEF are actively compiling a contingency plan for
the BEF facility should MTBE be banned. We are currently evaluating a possible
conversion of the facility from MTBE production to alkylate production. In
addition to MTBE's value in reducing air pollution, it is a significant source
of octane in the U.S. motor gasoline pool. Octane is a critical component of
motor gasoline. Therefore, 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 gasoline and that alkylate would be an
economic and effective substitute. We are currently conducting a detailed
engineering study that is expected to be completed by the end of 2003, at which
time we expect a more definitive conversion cost estimate will be available.
The cost to convert the facility will depend on the type of alkylate process
chosen and level of alkylate production desired by the partnership.
F-72
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,
-----------------------------------------------
2002 2001 2000
-----------------------------------------------
BALANCE SHEET DATA:
Current assets $ 37,237 $ 29,301
Property, plant and equipment, net 129,019 140,009
Other assets 9,050 10,067
--------------------------------
Total assets $ 175,306 $ 179,377
================================
Current liabilities $ 16,787 $ 13,352
Other liabilities 4,017 3,438
Partners' equity 154,502 162,587
--------------------------------
Total liabilities and partners' equity $ 175,306 $ 179,377
================================
INCOME STATEMENT DATA:
Revenues $ 229,358 $ 213,734 $ 258,180
Gross operating margin 71,537 28,701 43,328
Operating income 25,461 15,984 30,529
Net income 25,707 17,014 31,220
PROCESSING SEGMENT:
At December 31, 2002, 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 natural gas processing plant, fractionation facilities, storage, and
gas gathering pipelines in the Gulf of Mexico. We account for this investment
using the cost method. As part of Other Income and Expense as shown in our
Statements of Consolidated Operations and Comprehensive Income, we record
dividend income from our investment in VESCO.
8. INTANGIBLE ASSETS AND GOODWILL
INTANGIBLE ASSETS
The following table summarizes our intangible assets at December 31,
2002 and 2001:
AT DECEMBER 31, 2002 AT DECEMBER 31, 2001
-------------------------- --------------------------
GROSS ACCUM. CARRYING ACCUM. CARRYING
VALUE AMORT. VALUE AMORT. VALUE
------------- -------------------------- --------------------------
Shell natural gas processing agreement $ 206,331 $ (23,015) $ 183,201 $ (11,962) $ 194,369
Mont Belvieu Storage II contracts 8,127 (232) 7,895
Mont Belvieu Splitter III contracts 53,000 (1,388) 51,612
Toca-Western natural gas processing contracts 11,096 (326) 10,861
Toca-Western NGL fractionation contracts 20,041 (585) 19,457
Venice contracts (a) 4,639 4,635
MBA acquisition goodwill (b) 8,979 (1,122) 7,857
------------- -------------------------- --------------------------
Total $ 312,213 $ (25,546) $ 277,661 $ (13,084) $ 202,226
============= ========================== ==========================
- -------------------------------------------------------------------------------
(a) Amortization will commence when contracted-volumes begin to be processed
in 2003.
(b) Amount reclassified to Goodwill on January 1, 2002 per transition
provisions of SFAS 142.
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At December 31, 2002, our intangible assets consisted of:
o the Shell natural gas processing agreement that we acquired as part
of the TNGL acquisition in August 1999;
o certain storage and propylene fractionation contracts we acquired in
connection with the Diamond-Koch acquisitions in January and February
2002;
o certain natural gas processing and NGL fractionation contracts we
acquired in connection with the Toca-Western acquisition in June
2002; and
o certain NGL-related contracts (the "Venice contracts") we acquired
during the third quarter of 2002.
The following table shows amortization expense associated with our
intangible assets for the years ended December 31, 2002, 2001 and 2000:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------
2002 2001 2000
---------------------------------------
Shell natural gas processing agreement $ 11,054 $ 7,260 $ 3,576
Mont Belvieu Storage II contracts 232
Mont Belvieu Splitter III contracts 1,388
Toca-Western natural gas processing contracts 326
Toca-Western NGL fractionation contracts 585
MBA acquisition goodwill (a) 449 453
---------------------------------------
Total $ 13,585 $ 7,709 $ 4,029
=======================================
- -------------------------------------------------------------------------------
(a) Our MBA acquisition goodwill is no longer subject to amortization under
SFAS 142 guidelines.
The value of the Shell natural gas processing agreement is being
amortized on a straight-line basis over the remainder of its initial 20-year
contract term (currently $11.1 million annually from 2002 through 2019). The
values of the propylene fractionation and storage contracts acquired from
Diamond-Koch are being amortized on a straight-line basis over the economic
life of the assets to which they relate, which is currently estimated at 35
years. The Toca-Western natural gas processing contracts are being amortized
over the expected 20-year remaining life of the natural gas supplies supporting
these contracts. The value of the Toca-Western NGL fractionation contracts is
being amortized over the expected 20-year remaining life of the assets to which
they relate. The value of the Venice contracts will be amortized over 14 years
beginning in the third quarter of 2003.
For 2003, amortization expense attributable to these intangible assets
is currently estimated at $14.5 million. Based on information currently
available, we expect that amortization expense relating to existing intangibles
will increase to $14.7 million during each of the years 2004 through 2007.
GOODWILL
At December 31, 2002, the value of goodwill was $81.5 million. Our
goodwill is attributable to the excess of the purchase price over the fair
value of assets acquired and is comprised of the following (values as of
December 31, 2002):
o $73.6 million associated with the purchase of propylene fractionation
assets from Diamond-Koch in February 2002; and,
o $7.9 million related to the July 1999 purchase of an additional
ownership interest in MBA, which in turn owned an interest in our
Mont Belvieu NGL fractionation facility.
Our goodwill amounts are classified as part of the Fractionation
segment since they are related to assets recorded in this operating segment. At
December 31, 2001, the goodwill associated with the MBA acquisition was
recorded as part of our intangible assets.
Since our adoption of SFAS No. 142 on January 1, 2002, our goodwill
amounts are no longer amortized but are assessed annually for recoverability.
Prior to adoption of SFAS No. 142, the only goodwill amortization we recorded
was that associated with the MBA acquisition from July 1999. Due to the
immaterial nature of such
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amortization expense (approximately $0.4 million per year), the pro forma
effect of not amortizing this goodwill in 2001 or 2000 would have had a
negligible effect on our net income.
9. DEBT OBLIGATIONS
Our debt consisted of the following at:
DECEMBER 31,
----------------------------------
2002 2001
----------------------------------
Borrowings under:
364-Day Term Loan, variable rate, due July 2003 $ 1,022,000
364-Day Revolving Credit facility, variable rate,
due November 2004 99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005 225,000
Senior Notes A, 8.25% fixed rate, due March 2005 350,000 $ 350,000
Senior Notes B, 7.50% fixed rate, due February 2011 450,000 450,000
MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
Seminole Notes, 6.67% fixed rate, $15 million due
each December, 2002 through 2005 45,000
----------------------------------
Total principal amount 2,245,000 854,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 1,774 1,653
Less unamortized discount on:
Senior Notes A (81) (117)
Senior Notes B (230) (258)
Less current maturities of debt (15,000) -
----------------------------------
Long-term debt $ 2,231,463 $ 855,278
==================================
The table above does not reflect the issuance of our $350 million
principal amount Senior Notes C in January 2003 and $500 million principal
amount Senior Notes D in February 2003 nor does it reflect the repayment of
debt using contributions from our Limited Partner related to its January 2003
equity offering. We used a combination of proceeds from the issuance of our
Senior Notes C and D and the Limited Partner's contribution related to its
January 2003 equity offering to completely repay the 364-Day Term Loan by the
end of February 2003 (see the section titled "General description of
debt--364-Day Term Loan" within this note for additional information regarding
the use of proceeds to extinguish this debt). For additional information
regarding subsequent events affecting our debt balances, see Note 19.
As to the assets of our subsidiary, Seminole Pipeline Company, our
$2.2 billion in senior indebtedness at December 31, 2002 is structurally
subordinated and ranks junior in right of payment to the $45 million of
indebtedness of Seminole Pipeline Company. In accordance with SFAS No. 6,
"Classification of Short-Term Obligations Expected to Be Refinanced", long-term
and current maturities of debt at December 31, 2002 reflect the classification
of such debt obligations at March 7, 2003.
LETTERS OF CREDIT
At December 31, 2002, we had a total of $75 million of standby letters
of credit capacity under our Multi-Year Revolving Credit facility, of which
$2.4 million was outstanding.
PARENT-SUBSIDIARY GUARANTOR RELATIONSHIPS
Enterprise Products Partners L.P. (the "MLP", on a stand-alone basis)
acts as guarantor of certain of our debt obligations. These parent-subsidiary
guaranty provisions exist under all of our debt obligations with the
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exception of the Seminole Notes. The Seminole Notes are unsecured obligations
solely of Seminole Pipeline Company. If we were to default on any guaranteed
debt obligation, the MLP would be responsible for full payment of that
obligation.
GENERAL DESCRIPTION OF DEBT
The following is a summary of the significant aspects of our debt
obligations at December 31, 2002.
364-Day Term Loan. We entered into a $1.2 billion senior unsecured
364-day term loan to fund the Mid-America and Seminole acquisitions in July
2002. We applied $178.8 million in cash contributions received from our Limited
Partner related to its October 2002 equity offering to partially repay this
loan. In addition, we used $252.8 million of the $258.9 million in cash
contributions received from Limited Partner related to its January 2003 equity
offering, $347.0 million of the $347.7 million in proceeds from our issuance of
Senior Notes C and $421.4 million in proceeds from our issuance of Senior Notes
D to completely repay the 364-Day Term Loan by the end of February 2003 (see
Note 19). Base variable interest rates under this facility generally bore
interest at either (1) the greater of (a) the Prime Rate or (b) the Federal
Funds Effective Rate plus one-half percent or (2) a Eurodollar rate. Whichever
base interest rate we selected, the rate was increased by an appropriate
applicable margin (as defined within the loan agreement). During 2002, the
weighted-average interest rate charged was 3.10%, with the range of rates being
between 4.88% and 2.88%. This facility contained various covenants similar to
those of our revolving credit facilities. We were in compliance with these
covenants at December 31, 2002.
364-Day Revolving Credit facility. In November 2000, we entered in a
364-Day revolving credit agreement. Currently, the stand-alone borrowing
capacity under this credit facility is $230 million with the maturity date for
any amount outstanding being November 2003. We have the option to convert any
revolving credit balance outstanding at maturity to a one-year term loan (due
November 2004) in accordance with the terms of the credit agreement. This
credit facility is guaranteed by the MLP through an unsecured guarantee. In
addition, our borrowings under this bank credit facility are unsecured general
obligations and are non-recourse to the General Partner. We applied $60.0
million in proceeds from our February 2003 issuance of Senior Notes D to reduce
the balance outstanding under this facility during 2003 (see Note 19).
As defined by the credit agreement, variable interest rates charged
under this facility generally bear interest at either (1) the greater of (a)
the Prime Rate or (b) the Federal Funds Effective Rate plus one-half percent or
(2) a Eurodollar rate plus an applicable margin or (3) a Competitive Bid Rate.
We elect the basis of the interest rate at the time of each borrowing. During
2002, the weighted-average interest rate charged for borrowings under this
facility was 2.51%, with the range of rates being between 4.75% and 2.37%.
The 364-Day Revolving Credit facility agreement contains various
covenants related to our ability to incur certain indebtedness; grant certain
liens; enter into certain merger or consolidation transactions; and make
certain investments. The loan agreement also requires us to satisfy certain
financial covenants at the end of each quarter. As defined within the
agreement, we must maintain a specified level of consolidated net worth and
certain financial ratios. We were in compliance with these covenants at
December 31, 2002. The MLP has entered into an unsecured and unsubordinated
guarantee of this debt. This debt is non-recourse to the General Partner.
Multi-Year Revolving Credit facility. In conjunction with the 364-Day
Revolving Credit facility, we entered into a five-year revolving credit
facility that includes a sublimit capacity of $75 million for standby letters
of credit. Currently, the stand-alone borrowing capacity under this credit
facility is $270 million. This credit facility is guaranteed by the MLP through
an unsecured guarantee. In addition, our borrowings under this bank credit
facility are unsecured general obligations and are non-recourse to the General
Partner. The interest rates charged under this facility are determined in the
same manner as that described under our 364-Day Revolving Credit facility.
During 2002, the weighted-average interest rate charged for borrowings under
this facility was 2.37%, with the range of rates being between 4.75% and 2.00%.
This facility contains various covenants similar to those of our
364-Day Revolving Credit facility. (please refer to our discussion regarding
restrictive covenants of the "364-Day Revolving Credit facility" within this
"General description of debt" section). We were in compliance with these
covenants at December 31, 2002.
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Senior Notes A and B. These fixed-rate notes are an unsecured
obligation of ours and rank equally with its existing and future unsecured and
unsubordinated indebtedness. They are senior to any future subordinated
indebtedness. Both notes are guaranteed by the MLP through an unsecured and
unsubordinated guarantee and are non-recourse to the General Partner. These
notes were issued under an indenture containing certain covenants and are
subject to a make-whole redemption right. 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 covenants at December
31, 2002.
MBFC Loan. In connection with the construction of our Pascagoula,
Mississippi natural gas processing plant, we entered into a ten-year fixed-rate
loan with the Mississippi Business Finance Corporation ("MBFC"). This loan is
subject to a make-whole redemption right and is guaranteed by MLP through an
unsecured and unsubordinated guarantee. The indenture agreement for this loan
contains an acceleration clause whereby the outstanding principal and interest
on the loan may become due and payable within 120 days 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 within the loan agreement) may, and if requested to do so by
holders of at least 25% of the principal amount of the underlying bonds,
accelerate the maturity of the MBFC Loan. Should this acceleration occur, the
entire principal balance of the MBFC Loan and all related accrued and unpaid
interest would become immediately due and payable. If such an event occurred,
we would have the option of (1) to redeem the MBFC Loan or (2) to provide an
alternate credit agreement to support our obligation under the MBFC Loan. We
would have 120 days to exercise these options upon receiving notice of the
decline in our credit ratings.
The MBFC Loan agreement contains certain covenants including the
maintenance of appropriate levels of insurance on the Pascagoula facility and
restrictions regarding mergers. We were in compliance with these covenants at
December 31, 2002.
Seminole Notes. As a result of our acquisition of 78.4% of Seminole in
July 2002, we are required to consolidate its debt with our other debt
obligations. At December 31, 2002, Seminole had $45 million in fixed-rate
senior unsecured notes, of which $15 million is due annually each December
through December 2005. The Seminole Notes contain various covenants, such as
minimum net worth requirements and those restricting Seminole's ability to
borrow additional funds. Seminole was in compliance with these covenants at
December 31, 2002.
10. CAPITAL STRUCTURE
We are owned 98.9899% by our Limited Partner and 1.0101% by our
General Partner. For purposes of maintaining partner capital accounts, our
partnership agreement generally specifies that items of income or loss shall be
allocated among the partners in accordance with their respective ownership
percentages. Net losses are first allocated to the partners in accordance with
their respective percentages to the extent that the allocations do not cause
the Limited Partner to have a deficit balance in its capital account. Any net
loss not allocated to the Limited Partner is allocated to the General Partner.
Normal allocations of net income to percentage interests are done only,
however, after giving effect to any priority income allocations to the General
Partner in an amount equal to any aggregate net losses incurred by the General
Partner for all previous years. For the years ended December 31, 2002, 2001 and
2000, the allocation of earnings has been based solely on the respective
ownership interests of the partners with no priority income allocations being
necessary.
Our partnership agreement requires that we distribute 100% of the
"Available Cash" (as defined within the agreement) to the partners within 45
days following the end of each calendar quarter in accordance with their
respective ownership interests. Our distributions to partners during the three
years ended December 31, 2002, 2001 and 2000 were $224.5 million, $167.0
million and $141.5 million.
In connection with the TNGL acquisition completed during 1999, Shell
received 6.0 million non-distribution bearing, convertible special partnership
interests in our Limited Partner during each of 2001 and 2000. The value of the
special partnership interests issued during 2001 was $117.1 million while the
value of those issued during 2000 was $55.2 million. Both values were
determined using present value techniques. The value of these special
partnership interests increased the overall purchase price of the TNGL
acquisition and was allocated to the
F-77
Shell natural gas processing agreement. The value of the Limited Partner's
special partnership interests granted to Shell was accounted for as a non-cash
contribution to us by our Limited Partner.
In October 2002, our Limited Partner completed an equity offering from
which we received a cash contribution of $180.7 million. In connection with the
Limited Partner's contribution, we also received $1.8 million from our General
Partner to maintain its 1.0101% partnership interest in us. We applied these
cash contributions to the partial repayment of our 364-Day Term Loan and for
working capital and other expenses. See Note 9 for a description of our 364-Day
Term Loan. In January 2003, our Limited Partner completed another equity
offering from which we received a total cash contribution of $258.9 million,
which includes our General Partner's related contribution of $2.6 million.
Again, we applied these cash contributions to the partial repayment of the
364-Day Term Loan and for working capital and other expenses.
Parent's Units acquired and reissued by a consolidated trust. During
the first quarter of 1999, we established a revocable grantor trust, the EPOLP
1999 Grantor Trust or the "1999 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 1999 Trust purchased $2.4 million and $18.0 million of
our Limited Partner's Common Units during 2002 and 2001, respectively. In
November 2001, the 1999 Trust sold 1,000,000 Common Units costing $16.5 million
to EPCO for $22.6 million. The $6.1 million profit on the sale of these Common
Units has been credited to each partner in accordance with their respective
ownership interest.
Buy-Back Program. The 1999 Trust participates in a Buy-Back Program
with our parent entity, Enterprise Products Partners L.P. , under which an
aggregate 2,000,000 Common Units of our Limited Partner can be repurchased. The
source of funds used by Enterprise Products Partners L.P. to repurchase its
Common Units are special cash distributions from us. All of the Common Units
purchased by the 1999 Trust during 2002 and 2001 were under this program. At
December 31, 2002, 618,400 Common Units could potentially be repurchased under
the Buy-Back Program, either by the 1999 Trust or by Enterprise Products
Partners L.P.
11. PROVISION FOR INCOME TAXES
Provision for income taxes is only applicable to the tax obligation of
our Seminole pipeline business, which is a corporation and the only entity
subject to income taxes in the consolidated group. The following is a summary
of the provision for income taxes for Seminole for the period August 1, 2002
through December 31, 2002:
Current:
Federal tax benefit ($391)
State tax benefit (55)
--------------
(446)
--------------
Deferred:
Federal 1,812
State 268
--------------
2,080
--------------
Provision for Income Taxes $1,634
==============
The following is a reconciliation of the provision for income taxes at
the federal statutory rate to the provision for income taxes:
Taxes computed by applying the federal statutory rate $1,488
State income taxes (net of federal benefit) 138
Other 8
------------
Provision for income taxes $1,634
============
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Significant components of deferred income tax assets and liabilities
at December 31, 2002 are as follows:
Deferred tax assets:
Property, plant and equipment $15,846
Deferred tax liabilities:
Other (619)
-------------
Net deferred tax assets $15,227
=============
Based upon the periods in which taxable temporary differences are
anticipated to reverse, we believe it is more likely than not that the Company
will realize the benefits of these deductible differences. Accordingly, we
believe that no valuation allowance is required for the deferred tax assets.
However, the amount of the deferred tax asset considered realizable could be
adjusted in the future if estimates of reversing taxable temporary differences
are revised.
12. RELATED PARTY 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 D. Williams and Richard
H. Bachmann) and the remaining executive and other officers 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 Ms. 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 us.
In addition, trust affiliates of EPCO (the 1998 Trust and 2000 Trust)
owned 2,478,236 Common Units at December 31, 2002. Collectively, EPCO, Dan L.
Duncan, the 1998 Trust and the 2000 Trust owned 61.4% of our limited
partnership interests at December 31, 2002. We neither direct the actions of
either 1998 Trust or the 2000 Trust nor exercise any measure of control over
their actions. Accordingly, these two trusts are not consolidated with our
businesses.
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.
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. Under the terms of the EPCO Agreement,
EPCO agrees to:
o employ the personnel necessary to manage our business and affairs
(through the General Partner);
o employ the operating personnel involved in our business for which we
reimburse EPCO (based upon EPCO's actual salary and related fringe
benefits cost);
o 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;
o grant us an irrevocable, non-exclusive worldwide license to all of
the EPCO trademarks and trade names used in our business;
o indemnify us against any losses resulting from certain lawsuits; and
o 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
F-79
one dollar per year and to assign to us its purchase option under such
leases to us (the "retained leases"). EPCO remains liable for the
lease payments associated with these assets.
Operating costs and expenses (as shown in the Statements of
Consolidated Operations) treat the lease payments being made by EPCO as a
non-cash related party operating expense, with the offset to Partners' Equity
on the Consolidated Balance Sheets recorded as a general contribution to the
partnership. In addition, operating costs and expenses include compensation
charges for EPCO's employees who operate our facilities.
Pursuant to the EPCO Agreement, we reimburse EPCO for our share of the
costs of certain of its employees in administrative positions that were active
at the time of our initial public offering in July 1998 who manage our business
and affairs. Our reimbursement of EPCO's administrative personnel expense is
capped (currently at $17.6 million annually). The General Partner, with the
approval and consent of the Audit and Conflicts Committee, may agree to
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 of administrative personnel (including costs associated with equity-based
awards granted to certain individuals within this group) and the fee we pay
will be born solely by EPCO. The actual amounts incurred by EPCO did not
materially exceed the capped amounts for any periods. We also reimburse EPCO
for the compensation of administrative personnel it hires in response to our
expansion and new business activities. This includes costs attributable to
equity-based awards granted to members of this group.
Other related party transactions with EPCO. The following is a summary
of other significant related party transactions between EPCO and us, including
those between EPCO and our unconsolidated affiliates.
o EPCO is the operator of the facilities owned by BEF, of which we own
33.33%. In lieu of charging BEF for the actual cost of providing
management services, EPCO charges BEF a management fee. EPCO charged
BEF $0.6 million for such services during each of 2002, 2001 and
2000.
o EPCO is also operator of the facilities owned by EPIK, of which we
now wholly own. Prior to February 2003, we owned only 50% of EPIK. In
lieu of charging EPIK for the actual cost of management services,
EPCO charges EPIK a management fee. During 2002, 2001 and 2000, EPCO
charged EPIK $0.3 million, $0.2 million and $0.3 million,
respectively, for such services.
o We have entered into an agreement with EPCO to provide trucking
services to us for the loading and transportation of products.
o In the normal course of business, we also buy from and sell NGL
products to EPCO's Canadian affiliate.
The following table summarizes our various related party transactions
with EPCO for the years ended December 31, 2002, 2001 and 2000:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
REVENUES FROM CONSOLIDATED OPERATIONS
EPCO $ 3,630 $ 5,439 $ 4,750
OPERATING COSTS AND EXPENSES
EPCO 103,210 62,919 52,861
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES
Base fees payable under EPCO Agreement 16,638 15,125 13,750
Other EPCO compensation reimbursement 7,566 4,824 1,930
Relationship with Shell
We have an extensive and ongoing commercial relationship with Shell as
a partner, customer and vendor. Shell, through its subsidiary Shell US Gas &
Power LLC, currently owns approximately 20.5% of our limited partnership
interests and 30.0% of the General Partner. Currently, three members of the
Board of Directors of the General Partner (J. A. Berget, J.R. Eagan, and A.Y.
Noojin, III) are employees of Shell.
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Shell is our single largest customer. During 2002, it accounted for
7.8% of our consolidated revenues. Our revenues from Shell reflect the sale of
NGL and petrochemical products to them and the fees we charge them for pipeline
transportation and NGL fractionation services. Our operating costs and expenses
with Shell primarily reflect the payment of energy related-expenses related to
the Shell natural gas processing agreement (see below) and the purchase of NGL
products from them. The following table shows our revenues and operating costs
and expenses with Shell for the years ended December 31, 2002, 2001 and 2000:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
REVENUES FROM CONSOLIDATED OPERATIONS
Shell $ 282,820 $ 333,333 $ 292,741
OPERATING COSTS AND EXPENSES
Shell 531,712 705,440 736,655
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 state and federal waters
of the Gulf of Mexico on a keepwhole basis. This is a life of lease dedication,
which may extend the agreement well beyond 20 years. Generally, this contract
has the following rights and obligations:
o the exclusive right, but not the obligation, to process substantially
all of Shell's Gulf of Mexico natural gas production; plus
o the exclusive right, but not the obligation, to process all natural
gas production from leases dedicated by Shell for the life of such
leases; plus
o 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
o the obligation to re-deliver to Shell the natural gas stream after
the mixed NGL stream is extracted.
Under this contract, we are responsible for reimbursing Shell for the market
value of the energy we extract from their natural gas stream in the course of
performing natural gas processing services for them. Our reimbursement to Shell
(which we record as an operating cost) is generally based upon the energy value
of the fuel we consume and the NGLs we extract from their natural gas stream
(in terms of its Btu content, a measure of heating value). In lieu of
collecting a cash fee for our services under this contract, we take ownership
of the NGLs we extract from their natural gas stream. These volumes (our
"equity NGL production") become part our inventory held for sale. We derive a
profit to the extent that the revenues from the ultimate sale and delivery to
customers of these NGLs exceeds the costs of extraction and any other inventory
costs such as fractionation fees.
We have completed a number of business acquisitions and asset
purchases involving Shell since 1999. Among these transactions were:
o the acquisition of TNGL's natural gas processing and related
businesses in 1999 for approximately $528.8 million (this purchase
price includes both the $166 million in cash we paid to Shell and the
value of the three issues of Special Units granted to Shell in
connection with this acquisition);
o the purchase of the Lou-Tex Propylene Pipeline System for $100
million in 2000; and,
o the acquisition of Acadian Gas in 2001 for $243.7 million.
Shell is also a partner with us in the Gulf of Mexico natural gas pipelines we
acquired from El Paso in 2001. We also lease from Shell its 45.4% interest in
our Splitter I propylene fractionation facility.
Relationships with Unconsolidated Affiliates
Our investment in unconsolidated affiliates with industry partners is
a vital component of our business strategy. These investments are a means by
which we conduct our operations to align our interests with a supplier of raw
materials or a consumer of finished products. 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
F-81
operations. The following summarizes significant related party transactions we
have with our unconsolidated affiliates:
o We sell natural gas to Evangeline, which, in turn, uses the natural
gas to satisfy supply commitments it has with a major Louisiana
utility. We have also furnished $2.2 million in letters of credit on
behalf of Evangeline.
o We pay EPIK for export services to load product cargoes for our NGL
and petrochemical marketing customers.
o We pay Dixie transportation fees for propane movements on their
system initiated by our NGL marketing activities.
o We sell high purity isobutane to BEF as a feedstock and purchase
certain of BEF's by-products. We also receive transportation fees for
MTBE movements on our HSC pipeline and fractionation revenues for
reprocessing mixed feedstock streams generated by BEF.
o We pay Promix for the transportation, storage and fractionation of
certain of our mixed NGL volumes. In addition, we sell natural gas to
Promix for their fuel requirements.
The following table summarizes our related party transactions with
unconsolidated affiliates for the years ended December 31, 2002, 2001 and 2000:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
REVENUES
Evangeline $ 131,635 $ 117,283
EPIK 259 297 $ 5,070
BEF 50,494 45,778 56,216
Promix 12,697 8,952 57
Other unconsolidated affiliates 1,182 1,374 645
OPERATING COSTS AND EXPENSES
EPIK 19,788 7,438 17,600
Dixie 12,184 12,695 11,763
BEF 9,794 8,073 10,640
Promix 18,408 12,676 18,200
Other unconsolidated affiliates 482 193
As part of Other Income and Expense as shown in our Statements of
Consolidated Operations and Comprehensive Income, we record dividend income
from our investment in VESCO.
13. UNIT OPTION PLAN ACCOUNTING
During 1998, EPCO adopted its 1998 Long-Term Incentive Plan (the "1998
Plan"). Under the 1998 Plan, non-qualified incentive options to purchase a
fixed number of our Common Units (the "Units") of our Limited Partner may be
granted to EPCO's key employees who perform management, administrative or
operational functions for us. The exercise price per Unit, vesting and
expiration terms, and rights to receive distributions on Units granted are
determined by EPCO for each grant agreement. EPCO funds the purchase of the
Units under the 1998 Plan at fair value in the open market.
Categories of equity-based awards and our general responsibility
under each
Equity-based awards granted to certain key operations personnel. Under
the EPCO Agreement (see Note 12), we reimburse EPCO for the compensation of all
operations personnel it employs on our behalf. This includes the costs
attributable to equity-based awards granted to these personnel. When these
employees exercise Unit options, we reimburse EPCO for the difference between
the strike price paid by the employee and the actual purchase price for the
Units awarded to the employee. We may reimburse EPCO for these costs in a
number of ways including furnishing cash or having our Limited Partner issue
new Common Units. We record the expense
F-82
associated with these awards in our operating costs and expenses as shown on
our Statements of Consolidated Operations.
Equity-based awards granted to certain key expansion-related
administrative and management employees. We also reimburse EPCO for the
compensation of administrative and management personnel it hires in response to
our expansion and new business activities. This includes costs attributable to
equity-based awards granted to members of this "expansion" group of EPCO
employees. When these employees exercise Unit options, we reimburse EPCO for
the difference between the strike price paid by the employee and the actual
purchase price for the Units awarded to the employee. We may reimburse EPCO for
these costs in a number of ways including furnishing cash or having our Limited
Partner issue new Common Units. We record the expense associated with these
awards in our selling, general and administrative costs as shown on our
Statements of Consolidated Operations.
Equity-based awards granted to other key administrative and management
employees. In addition, we reimburse EPCO for our share of the costs of certain
of its employees in administrative positions that were active at the time of
our initial public offering in July 1998 who manage our business and affairs.
Our reimbursement for the cost of equity-based awards to this "pre-expansion"
group of administrative EPCO employees is covered by the Administrative
Services Fee we pay to EPCO. EPCO is responsible for the actual costs when the
Unit options granted to these pre-expansion administrative employees are
exercised. EPCO satisfies its equity-award obligations to these employees by
arranging for Common Units of our Limited Partner to be purchased in the open
market. We record the Administrative Service Fee paid to EPCO as a selling,
general and administrative expense as shown on our Statements of Consolidated
Operations.
Summary of 1998 Plan activity and amounts related to Employees who
perform activities on our behalf
EPCO's 1998 Plan is used to issue Unit option awards to the three
categories of employees discussed above. The information in the following table
shows (i) Unit option activity for all operations and expansion-related
administrative/management personnel and (ii) Unit option activity of the
pre-expansion administrative/management employees allocable to us under the
EPCO Agreement (based on each pre-expansion employee's percentage of time
worked on our behalf).
WEIGHTED-AVERAGE
NUMBER OF UNITS STRIKE PRICE
-----------------------------------
Outstanding at December 31, 1999 178,611 $ 1.95
Granted 664,000 $ 9.26
Exercised (38,180) $ 1.84
Forfeited (20,000) $ 9.00
-----------------------------------
Outstanding at December 31, 2000 784,431 $ 7.96
Granted 680,000 $ 16.67
Exercised (150,585) $ 6.01
Forfeited (20,000) $ 9.00
-----------------------------------
Outstanding at December 31, 2001 1,293,846 $ 12.74
Granted 249,000 $ 23.76
Exercised (102,604) $ 6.16
-----------------------------------
Outstanding at December 31, 2002 1,440,242 $ 15.12
===================================
Options exercisable at:
December 31, 2000 140,431
=================
December 31, 2001 155,846
=================
December 31, 2002 383,742
=================
F-83
OPTIONS EXERCISABLE AT
DECEMBER 31, 2002
WEIGHTED --------------------------------
OPTIONS AVERAGE WEIGHTED NUMBER WEIGHTED
RANGE OUTSTANDING AT REMAINING AVERAGE EXERCISABLE AT AVERAGE
OF STRIKE DECEMBER 31, CONTRACTUAL STRIKE DECEMBER 31, STRIKE PRICE
PRICES 2002 LIFE (IN YEARS) PRICE 2002
- -----------------------------------------------------------------------------------------------------
$.69 - $2.23 52,242 2.16 $ 1.58 52,242 $ 1.98
$7.75 -$9.00 331,500 6.75 $ 8.82 331,500 $ 8.82
$11.81 127,500 7.09 $ 11.81 - -
$15.93 - $17.63 615,000 8.10 $ 16.30 - -
$21.22 - $24.73 314,000 9.09 $ 23.61 - -
----------------- ------------------
1,440,242 383,742
================= ==================
The weighted average fair value of options granted was $3.17, $1.86,
and $2.23 per option for the fiscal years ended December 31, 2002, 2001, and
2000, respectively.
We apply Accounting Principles Board Opinion No. 25, "Accounting for
Stock Issued to Employees", in accounting for employee Unit option awards
whereby no compensation expense is recorded related to the options granted
equal to the market value of the Unit on the date of grant. If compensation
expense had been determined based on the Black-Scholes option pricing model
value at the grant date for Unit option awards consistent with the provisions
of SFAS No. 123, "Accounting for Stock-Based Compensation", our net income
would have been as follows:
2002 2001 2000
---- ---- ----
Net income:
As reported.................... $96,952 $244,718 $223,068
Pro forma...................... 95,858 243,888 222,406
The effects of applying SFAS No. 123 in the pro forma disclosure above may not
be indicative of future amounts as additional awards in future years are
anticipated.
The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option-pricing model with the following assumptions:
2002 2001 2000
---- ---- ----
Expected life of options............ 7 years 7 years 7 years
Risk-free interest rate............. 3.10% 3.83% 6.44%
Expected dividend yield............. 5.65% 5.30% 10.00%
Expected Unit price volatility...... 25% 20% 30%
14. COMMITMENTS AND CONTINGENCIES
Redelivery Commitments
We store and transport NGL, petrochemical and natural gas volumes for
third parties under various processing, storage, transportation and similar
agreements. Under the terms of these agreements, we are generally required to
redeliver volumes to the owner on demand. We are insured for any physical loss
of such volumes due to catastrophic events. At December 31, 2002, NGL and
petrochemical volumes aggregating 4.2 million barrels were due to be
redelivered to their owners along with 664 BBtus 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, 2002 are as
follows:
F-84
2003 $ 7,148
2004 5,081
2005 759
2006 676
2007 506
Thereafter 3,623
--------------
Total minimum obligations $ 17,793
==============
Third-party lease and rental expense included in operating income for
the years ended December 31, 2002, 2001 and 2000 was approximately $16.4
million, $13.0 million and $10.6 million.
The operating lease commitments shown above exclude the non-cash
related party expense associated with various equipment leases contributed to us
by EPCO at our formation for which EPCO has retained the liability (the
"retained leases"). The retained leases are accounted for as operating leases by
EPCO. EPCO's minimum future rental payments under these leases are $12.6 million
for 2003, $2.1 million for each of the years 2004 through 2009 and $0.7 million
from 2010 through 2016. EPCO has assigned to us the purchase options associated
with the retained leases. Should we decide to exercise our purchase options
under the retained leases (which are at fair market value), up to $26.0 million
is expected to be payable in 2004, $3.4 million in 2008 and $3.1 million in
2016.
Purchase Commitments
Product purchase commitments. We have long-term purchase commitments
for NGLs, petrochemicals and natural gas with several suppliers. The purchase
prices that we are obligated to pay under these contracts approximate market
prices at the time we take delivery of the volumes. The following table shows
our long-term volume commitments under these contracts.
NATURAL
NGLS PETROCHEMICALS GAS
----------------------------------------------------------
(MBbls) (MBbls) (BBtus)
----------------------------------------------------------
2003 15,986 25,428 23,053
2004 13,172 22,857 20,439
2005 9,580 19,287 18,645
2006 5,910 13,399 18,645
2007 5,400 1,125 18,250
Thereafter 10,800 91,250
----------------------------------------------------------
60,848 82,096 190,282
==========================================================
Capital spending commitments. As of December 31, 2002, we had capital
expenditure commitments totaling approximately $7.8 million, of which $6.3
million relates to our share of capital projects of unconsolidated affiliates.
Commitments under equity compensation plans of EPCO
In accordance with our agreements with EPCO, we reimburse EPCO for our
share of its compensation expense associated with certain employees who perform
management, administrative and operating functions for us (see Note 12). This
includes the costs associated with equity-based awards granted to these
employees (see Note 13). At December 31, 2002, there were 1,194,242 options to
purchase Common Units of our Limited Partner outstanding under the 1998 Plan
that had been granted to operational and expansion-related administrative
employees for which we were responsible for reimbursing EPCO for the costs of
such awards. The weighted-average strike price of the Unit option awards
granted to this group was $15.73 per Common Unit. At December 31, 2002, 275,242
of these Unit options were exercisable. An additional 100,000, 570,000 and
249,000 of these Unit options will be exercisable in 2003, 2004 and 2005,
respectively.
F-85
When these operations and expansion-related administrative employees
exercise a Unit option, we reimburse EPCO for the difference between the strike
price paid by the employee and the actual purchase price paid for the Units
awarded to the employee. We may reimburse EPCO for these costs in a number of
ways including furnishing cash and transferring Common Units acquired by our
1999 Trust.
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
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. 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.
15. SUPPLEMENTAL CASH FLOWS DISCLOSURE
The net effect of changes in operating assets and liabilities is as
follows:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
(Increase) decrease in:
Accounts and notes receivable $ (130,476) $ 229,525 $ (95,647)
Inventories (84,254) 11,048 (13,044)
Prepaid and other current assets 15,419 (26,427) 2,351
Intangible assets (5,228)
Other assets (3,322) 163 (1,410)
Increase (decrease) in:
Accounts payable 20,096 (78,270) 18,725
Accrued gas payable 262,527 (178,102) 135,048
Accrued expenses 8,111 (894) 4,430
Accrued interest 5,369 14,234 8,743
Other current liabilities (6,921) 3,072 6,544
Other liabilities (504) (9,012) 8,123
---------------------------------------------------
Net effect of changes in operating accounts $ 86,045 $ (34,663) $ 68,635
===================================================
Cash payments for interest, net of $1,083,
$2,946 and $3,277 capitalized in 2002,
2001 and 2000, respectively $ 82,535 $ 37,536 $ 17,774
===================================================
During 2002 and 2001, we completed $1.8 billion in business
acquisitions of which the purchase price allocation of each affected various
balance sheet accounts. See Note 4 for information regarding the purchase price
allocations of these transactions during 2002. During 2001, we acquired Acadian
Gas from Shell. Its $225.7 million purchase price was allocated as follows:
$83.1 million to current assets, $225.2 million to property, plant and
equipment, $2.7 million to investments in unconsolidated affiliates, $83.9
million to current liabilities and $1.4 million to other long-term liabilities.
We record various financial instruments relating to commodity
positions and interest rate hedging activities at their respective fair values
using mark-to-market accounting. During 2002, we recognized a net $10.2 million
in non-cash mark-to-market decreases in the fair value of these instruments,
primarily in our commodity financial instruments portfolio. During 2001, we
recognized a net $5.6 million in non-cash mark-to-market increases in the fair
value of our financial instruments portfolio.
F-86
During 2002, we made the first of two cash payments to acquire certain
processing-related contract rights connected to Venice gas processing facility.
Of the initial $4.6 million value of this intangible asset, $2.6 million was
reclassified from construction-in-progress and $2.0 million represented the
actual cash payment made to the third-party. The prior expenditures recorded as
construction-in-progress were reclassified due to the direct linkage between
these expenditures and the successful negotiation of the Venice contracts. The
remaining $2.0 million is scheduled to be paid during the third quarter of
2003.
Cash and cash equivalents (as shown on our Statements of Consolidated
Cash Flows) excludes restricted cash amounts held by a brokerage firm as margin
deposits associated with our financial instruments portfolio and for our
physical purchase transactions made on the NYMEX exchange. The restricted cash
balance at December 31, 2002 and 2001 was $8.8 million and $5.8 million,
respectively.
We did not have any cash payments for income taxes during 2002, 2001
or 2000. For additional information regarding our partnership and income taxes,
see Note 1 and Note 11.
16. FINANCIAL INSTRUMENTS
We are exposed to financial market risks, including changes in
commodity prices and interest rates. 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 within our Processing segment. In general, the types of
risks we attempt to hedge 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.
The estimated fair values of our financial instruments have been
determined using available market information and appropriate valuation
methodologies. We must use considerable judgment, however, in interpreting
market data and developing these estimates. Accordingly, our fair value
estimates are not necessarily indicative of the amounts that we could realize
upon disposition of these instruments. The use of different market assumptions
and/or estimation techniques could have a material effect on our estimates of
fair value.
Commodity financial instruments
The prices of natural gas, NGLs, petrochemical products 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 our Processing segment activities, we may
enter into various commodity financial instruments. The primary purpose of
these risk management activities is to hedge our exposure to price risks
associated with natural gas, NGL production and inventories, firm commitments
and certain anticipated transactions. The commodity financial instruments we
utilize may be settled in cash or with another financial instrument.
We do not hedge our exposure related to MTBE price risks. In addition,
we generally do not hedge risks associated with our petrochemical marketing
activities that are part of our Fractionation segment. In our Pipelines
segment, we do utilize a limited number of commodity financial instruments to
manage the price Acadian Gas charges certain of its customers for natural gas.
Lastly, due to the nature of the transactions, we do not employ commodity
financial instruments in our fee-based marketing business accounted for in the
Other segment.
We have adopted a policy to govern our use of commodity financial
instruments to manage 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 limits 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 24 months. The
General Partner oversees 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.
F-87
Our commodity financial instruments may not qualify for hedge
accounting treatment under the specific guidelines of SFAS No. 133 because of
ineffectiveness. A financial instrument is generally regarded as "effective"
when changes in its fair value almost fully offset changes in the fair value of
the hedged item throughout the term of the instrument. Due to the complex nature
of risks we attempt to hedge, our commodity financial instruments have generally
not qualified as effective hedges under SFAS No. 133. As a result, changes in
the fair value of these positions are recorded on the balance sheet and in
earnings through mark-to-market accounting. Mark-to-market accounting results in
a degree of non-cash earnings volatility that is dependent upon changes in the
commodity prices underlying these financial instruments. Even though these
financial instruments may not qualify for hedge accounting treatment under SFAS
No. 133, we view such contracts as hedges since this was the intent when we
entered into such positions. Upon entering into such positions, our expectation
is that the economic performance of these instruments will mitigate (or offset)
the commodity risk being addressed. The specific accounting for these contracts,
however, is consistent with the requirements of SFAS No. 133.
At December 31, 2002, we had open commodity financial instruments that
settle at different dates through December 2003. We routinely review our
outstanding 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 a new
commodity financial instrument to reestablish the hedge to which the closed
instrument relates.
During 2002, we recognized a loss of $51.3 million from our commodity
hedging activities that was recorded as an increase in our operating costs and
expenses in the Statements of Consolidated Operations. Of the loss recognized
in 2002, $5.6 million is related to non-cash mark-to-market income recorded on
open positions at December 31, 2001. During 2001, we posted income of $101.3
million from our commodity hedging activities, which served to reduce operating
costs and expenses.
Beginning in late 2000 and extending through March 2002, a large
number of our commodity hedging transactions were based on the historical
relationship between natural gas prices and NGL prices. This type of hedging
strategy utilized 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 our NGL marketing activities and the
value of our equity NGL production. Throughout 2001, this strategy proved very
successful to us (as the price of natural gas declined relative to our fixed
positions) and was responsible for most of the $101.3 million in commodity
hedging income we recorded during 2001.
In late March 2002, the effectiveness of this strategy deteriorated
due to an unexpected rapid increase in natural gas prices whereby the loss in
the value of our fixed-price natural gas financial instruments was not offset
by increased gas processing margins. Due to the inherent uncertainty that was
controlling natural gas prices at the time, we decided that it was prudent to
exit this strategy, and we did so by late April 2002. The failure of this
strategy is the primary reason for the $51.3 million in commodity hedging
losses we recorded during 2002.
We had a limited number of commodity financial instruments open at
December 31, 2002. The fair value of these open positions was a liability of
$26 thousand (based on market prices at that date).
Interest rate hedging financial instruments
Our interest rate exposure results from variable-interest rate
borrowings and fixed-interest rate borrowings (see Note 9). We assess the cash
flow risk related to interest rates by identifying and measuring changes in our
interest rate exposures that may impact future cash flows and evaluating
hedging opportunities to manage these risks. We use analytical techniques to
measure our 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 these financial risks and approves instruments that are
appropriate for our requirements.
Interest rate swaps. We manage a portion of our interest rate risks by
utilizing interest rate swaps. The objective of entering into 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. In general, an interest rate swap requires one party to pay a
fixed-interest rate on a notional amount while the other party pays a
floating-interest rate based on the same notional amount. The notional amount
specified in an interest rate swap agreement does not represent exposure to
credit loss. We monitor our positions and the credit ratings of counterparties.
Management
F-88
believes the risk of incurring a credit loss on these financial instruments is
remote, and that if incurred, such losses would be immaterial. We believe that
it is prudent to maintain an appropriate balance of variable-rate and
fixed-rate debt.
At December 31, 2002, we had one interest rate swap outstanding having
a notional amount of $54 million that extends through March 2010. Under this
agreement, we exchanged a fixed-interest rate of 8.7% for a variable-interest
rate that ranged from 1.8% to 4.5% during 2002 (the variable-interest rate we
paid under this swap fluctuated over time depending on market conditions). The
counterparty exercised its right to early termination of this swap in March
2003; therefore, only a minimal amount of income will be recognized in 2003
from this financial instrument. We recognized income from our interest rate
swaps of $0.9 million during 2002 compared to $13.2 million during 2001. This
income is recorded as a reduction of interest expense in our Statements of
Consolidated Operations.
Treasury Locks. During the fourth quarter of 2002, we entered into
seven treasury lock transactions. A treasury lock is a specialized agreement
that fixes the price (or yield) on a specific treasury security for an
established period of time. A treasury lock purchaser is protected from a rise
in the yield of the underlying treasury security during the lock period. Our
treasury lock transactions carried an original maturity date of either January
31, 2003 or April 15, 2003. The purpose of these transactions was to hedge the
underlying treasury interest rate associated with our anticipated issuance of
debt in early 2003 to refinance the Mid-America and Seminole acquisitions. The
notional amounts of these transactions totaled $550 million, with a total
treasury lock rate of approximately 4%.
Our treasury lock transactions are accounted for as cash flow hedges
under SFAS No. 133. The fair value of these instruments at December 31, 2002
was a current liability of $3.8 million offset by a current asset of $0.2
million. The net $3.6 million non-cash mark-to-market liability was recorded as
a component of comprehensive income on that date, with no impact to current
earnings.
We elected to settle all of the treasury locks by early February 2003
in connection with our issuance of Senior Notes C and D (see Note 19). The
settlement of these instruments resulted in our receipt of $5.4 million of
cash. This amount will be recorded as a gain in other comprehensive income
during the first quarter of 2003 and represents the effective portion of the
treasury locks.
Of the $5.4 million recorded in other comprehensive income during the
first quarter of 2003, $4.0 million is attributable to our issuance of Senior
Notes C and will be amortized to earnings as a reduction in interest expense
over the 10-year term of this debt. The remaining $1.4 million is attributable
to our issuance of Senior Notes D and will amortized to earnings as a reduction
in interest expense over the 10-year term of the anticipated transaction as
required by SFAS No. 133. The estimated amount to be reclassified from
accumulated other comprehensive income to earnings during 2003 is $0.4 million.
With the settlement of the treasury locks, the $3.6 million non-cash
mark-to-market liability recorded at December 31, 2002 will be reclassified out
of accumulated other comprehensive income in Partners' Equity to offset the
current asset and liabilities we recorded at December 31, 2002 with no impact
to earnings.
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.
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. The estimated fair value of
our fixed-rate debt is estimated based on quoted market prices for such debt or
debt of similar terms and maturities. The carrying amounts of our variable-rate
debt obligations reasonably approximate their fair values due
F-89
to their variable interest rates. The fair values associated with our commodity
and interest rate hedging financial instruments were developed using available
market information and appropriate valuation techniques.
The following table summarizes the estimated fair values of our
various financial instruments at December 31, 2002 and 2001:
AT DECEMBER 31, 2002 AT DECEMBER 31, 2001
---------------------------------------------------------------
CARRYING FAIR CARRYING FAIR
FINANCIAL INSTRUMENTS VALUE VALUE VALUE VALUE
- ------------------------------------------------------------------------------------------------------------------------
Financial assets:
Cash and cash equivalents $ 20,795 $ 20,795 $ 137,823 $ 137,823
Accounts receivable 402,556 402,556 260,429 260,429
Commodity financial instruments (1) 513 513 9,992 9,992
Interest rate hedging financial instruments (2) 203 203 2,324 2,324
Financial liabilities:
Accounts payable and accrued expenses 663,716 663,716 361,530 361,530
Fixed-rate debt (principal amount) 899,000 1,027,749 854,000 894,005
Variable-rate debt 1,346,000 1,346,000
Commodity financial instruments (1) 539 539 3,206 3,206
Interest rate hedging financial instruments (2) 3,766 3,766
- -------------------------------------------------------------------------------
(1) Represent commodity financial instrument transactions that either
have not settled or have settled and not been invoiced. Settled and
invoiced transactions are reflected in either accounts receivable or
accounts payable depending on the outcome of the transaction.
(2) Represent interest rate hedging financial instrument transactions
that have not settled. Settled transactions are reflected in either
accounts receivable or accounts payable depending on the outcome of the
transaction.
17. 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. This concentration could affect our overall exposure to credit risk
since these customers might be affected by similar economic or other
conditions. We generally do not require collateral for our accounts receivable;
however, we do attempt to negotiate offset agreements with customers that are
deemed to be credit risks in order to minimize our potential exposure to any
defaults.
Counterparty risk. From time to time, we have credit risk with our
counterparties in terms of settlement risk associated with its financial
instruments (which includes accounts receivable). 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 $10.7
million reserve for amounts owed to us by Enron and its affiliates. Affiliates
of Enron were our counterparty to various past financial instruments, which
were guaranteed by Enron. The Enron amounts were unsecured and the amount that
we may ultimately recover, if any, is not presently determinable.
Nature of Operations. Our Company is subject to a number of risks
inherent in the industry in which it operates, including fluctuating gas and
product prices. Our financial condition and results of operations depend
significantly on the demand for NGLs and the costs involved in their
production. These NGL, natural gas and other related 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.
F-90
In addition, we must obtain access to new natural gas volumes along the
Gulf Coast of the United States for our processing business in order to maintain
or increase gas plant processing 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 our
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.
18. SEGMENT INFORMATION
Operating segments are components of a business about which separate
financial information is available. These components 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: Pipelines, Fractionation,
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. Pipelines
consists of NGL, petrochemical and natural gas pipeline systems, storage and
import/export terminal services. Fractionation primarily includes NGL
fractionation, isomerization, and polymer grade propylene fractionation
services. Processing includes the natural gas processing business and its
related NGL marketing 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 various operational support activities.
We evaluate segment performance based on our measurement of segment
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 other income and expense transactions, provision for
income taxes, minority interest and extraordinary charges.
Gross operating margin by segment includes intersegment and
intrasegment revenues (offset by corresponding intersegment and intrasegment
expenses within the segments), which are generally based on transactions made
at market-related rates. Our intersegment and intrasegment activities include,
but are not limited to, the following types of transactions:
o NGL fractionation revenues from separating our NGL raw-make
inventories into distinct NGL products using our fractionation plants
for our NGL marketing activities (an intersegment revenue of
Fractionation offset by an intersegment expense of Processing);
o liquids pipeline revenues from transporting our NGL volumes from gas
processing plants on our pipelines to our NGL fractionation
facilities (an intersegment revenue of Pipelines offset by an
intersegment expense of Processing); and,
o the transfer sale of our NGL equity production extracted by our gas
processing plants to our NGL marketing activities (an intrasegment
revenue of Processing offset by an intrasegment expense of
Processing).
For additional information regarding our revenue recognition policies, see Note
2.
F-91
Our consolidated financial statements include our accounts and those of
our majority-owned subsidiaries, after elimination of all material intercompany
(both intersegment and intrasegment) accounts and transactions. We include
equity earnings from unconsolidated affiliates in our measurement of segment
gross operating margin. 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 our equity investees (see Note 7) 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 Processing segment's NGL marketing
activities. 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. For additional information regarding our related party
relationships with unconsolidated affiliates, see Note 12.
Our revenues are derived from a wide customer base. All consolidated
revenues were earned in the United States. Most of our plant-based operations
are located primarily along the western Gulf Coast in Texas, Louisiana and
Mississippi. Our pipelines and related operations are in a number of regions of
the United States including the Gulf of Mexico offshore Louisiana (certain
natural gas pipelines); the south and southeastern United States (primarily in
the Texas, Louisiana and Mississippi regions); and certain regions of the
central and western United States. The Mid-America pipeline system extends from
the Hobbs hub located on the Texas-New Mexico border to Wyoming along one route
and to Minnesota, Wisconsin and Illinois along other routes. Our marketing
activities are headquartered in Houston, Texas at our main office and service
customers in a number of regions in the United States including the Gulf Coast,
West Coast and Mid-Continent areas.
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.
Consolidated intangible assets and goodwill are allocated to the segments based
on the classification of the assets to which they relate.
F-92
The following table shows our measurement of total segment gross
operating margin for the periods indicated:
FOR YEAR ENDED DECEMBER 31,
---------------------------------------------------
2002 2001 2000
---------------------------------------------------
Revenues (1) $ 3,584,783 $ 3,154,369 $ 3,049,020
Operating costs and expenses (1) (3,382,561) (2,861,743) (2,801,060)
Equity in income of unconsolidated affiliates (2) 35,253 25,358 24,119
---------------------------------------------------
Subtotal 237,475 317,984 272,079
Add: Depreciation and amortization in
operating costs and expenses (3) 86,029 48,775 35,621
Retained lease expense, net in
operating costs and expenses (4) 9,124 10,414 10,645
(Gain) loss on sale of assets in
operating costs and expenses (3) (1) (390) 2,270
---------------------------------------------------
Total segment gross operating margin $ 332,627 $ 376,783 $ 320,615
===================================================
- -------------------------------------------------------------------------------
(1) Amounts are comprised of both third party and related party totals from the
Statements of Consolidated Operations and Comprehensive Income
(2) Amount taken from Statements of Consolidated Operations and Comprehensive
Income
(3) Amount taken from Statements of Consolidated Cash Flows
(4) Amount represents leases paid by EPCO as reflected on the Statements of
Consolidated Cash Flows
A reconciliation of our measurement of total segment gross operating
margin to consolidated income before provision for income taxes and minority
interest follows:
FOR YEAR ENDED DECEMBER 31,
----------------------------------------------------
2002 2001 2000
----------------------------------------------------
Total segment gross operating margin $ 332,627 $ 376,783 $ 320,615
Depreciation and amortization (86,029) (48,775) (35,621)
Retained lease expense, net (9,124) (10,414) (10,645)
Gain (loss) on sale of assets 1 390 (2,270)
Selling, general and administrative (42,664) (30,812) (28,345)
----------------------------------------------------
Consolidated operating income 194,811 287,172 243,734
Interest expense (101,580) (52,456) (33,329)
Interest income from unconsolidated affiliates 139 15 1,662
Dividend income from unconsolidated affiliates 4,737 3,462 7,091
Interest income - other 2,846 7,773 4,295
Other, net (230) (1,104) (272)
----------------------------------------------------
Consolidated income before provision for income
taxes and minority interest $ 100,723 $ 244,862 $ 223,181
====================================================
F-93
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 third parties:
2002 $ 592,681 $ 458,427 $2,049,202 $ 1,756 $ 3,102,066
2001 301,263 239,489 2,100,224 937 2,641,913
2000 361,919 15,648 2,310,706 1,268 2,689,541
Revenues from related parties:
2002 19,121 161,727 301,747 122 482,717
2001 23,013 163,941 324,057 1,445 512,456
2000 35,076 12,524 310,269 1,610 359,479
Intersegment and intrasegment
revenues:
2002 203,750 102,330 604,981 401 $ (911,462) -
2001 158,853 89,907 683,524 389 (932,673) -
2000 177,963 55,690 630,155 375 (864,183) -
Total revenues:
2002 815,552 722,484 2,955,930 2,279 (911,462) 3,584,783
2001 483,129 493,337 3,107,805 2,771 (932,673) 3,154,369
2000 574,958 83,862 3,251,130 3,253 (864,183) 3,049,020
Equity income in unconsolidated affiliates:
2002 7,179 19,505 $ 8,569 35,253
2001 6,945 12,742 5,671 25,358
2000 6,391 7,321 10,407 24,119
Total gross operating margin by segment:
2002 129,000 214,932 (17,633) 8,569 (2,241) 332,627
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
Segment property (see Note 6):
2002 444,016 2,166,524 133,888 16,825 49,586 2,810,839
2001 357,122 717,348 124,555 8,921 98,844 1,306,790
Investments in and advances to
unconsolidated affiliates (see Note 7):
2002 95,467 213,632 33,000 54,894 396,993
2001 93,329 216,029 33,000 55,843 398,201
Intangible Assets (see Note 8):
2002 71,069 7,895 198,697 277,661
2001 7,857 194,369 202,226
Goodwill (see Note 8):
2002 81,547 81,547
F-94
In general, our consolidated results of operations and financial
position have been materially affected by acquisitions since late 1999. Our
more significant acquisitions during this period were:
o William's Mid-America and Seminole pipelines in July 2002 for $1.2
billion;
o Diamond-Koch's propylene fractionation business in February 2002 for
$239 million ;
o Diamond-Koch's NGL and petrochemical storage business in January 2002
for $129.6 million;
o Shell's Acadian Gas pipeline business in April 2001 for $243.7
million;
o El Paso's equity interests in four Gulf of Mexico natural gas
pipelines in January 2001 for $113 million; and
o Shell's TNGL natural gas processing and related businesses in August
1999 for approximately $528.8 million.
See Note 4 for a description of acquisitions we completed during 2002.
19. SUBSEQUENT EVENTS
January 2003 contribution from Limited Partner. In January 2003, our
Limited Partner completed a public offering of 14,662,500 Common Units from
which we received a cash contribution of approximately $258.9 million,
including our General Partner's $2.6 million capital contribution. We used
$252.8 million of the proceeds to repay a portion of the indebtedness
outstanding under the 364-Day Term Loan. The remaining balance was used for
working capital purposes and other expenses.
January 2003 Senior Notes Offering. In January 2003, we issued $350
million in principal amount of 6.375% Senior Notes due 2013 ("Senior Notes C"),
from which we received net proceeds before offering expenses of approximately
$347.7 million. We used $347.0 million of the proceeds from this offering to
repay a portion of the indebtedness outstanding under the 364-Day Term Loan.
The remaining balance of proceeds was used for offering expenses.
February 2003 Senior Notes Offering. In February 2003, we issued $500
million in principal amount of 6.875% Senior Notes due 2033 ("Senior Notes D"),
from which we received net proceeds before offering expenses of approximately
$489.8 million. We used $421.4 million of the proceeds from this offering to
repay the remaining principal balance outstanding under the 364-Day Term Loan.
An additional $60.0 million in proceeds was used to reduce the amount
outstanding under the 364-Day Revolving Credit facility. The remaining balance
of proceeds was used for working capital purposes and offering expenses.
Purchase of remaining 50% interest in EPIK. In March 2003, we
purchased the remaining ownership interests in EPIK from Idemitsu LPG USA
Corporation for $19.0 million. The purchase price is subject to certain
post-closing adjustments that we expect to finalize during the second quarter
of 2003.
F-95
20. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table contains selected quarterly financial data for
2002 and 2001.
First Second Third Fourth
Quarter Quarter Quarter Quarter
--------------------------------------------------------------------
FOR THE YEAR ENDED DECEMBER 31, 2001:
Revenues $ 836,315 $ 959,397 $ 723,329 $ 635,328
Operating income 54,417 108,390 87,478 36,887
Income before minority interest 52,939 93,437 76,003 22,483
Minority interest (23) (44) (46) (31)
Net income 52,916 93,393 75,957 22,452
FOR THE YEAR ENDED DECEMBER 31, 2002:
Revenues $ 662,054 $ 786,257 $ 943,313 $1,193,159
Operating income (928) 39,889 68,374 87,476
Income before minority interest (17,098) 22,480 36,307 57,400
Minority interest (53) (33) (988) (1,063)
Net income (loss) (17,151) 22,447 35,319 56,337
We recorded a net loss during the first quarter of 2002 due to
commodity hedging losses resulting from an unexpected increase in natural gas
prices. Overall, we recorded $51.3 million of commodity hedging losses during
2002 compared to $101.3 million of income from such activities during 2001 (see
Note 16). Net income for the second half of 2002 improved relative to the first
half of 2002 primarily due to the acquisition of Mid-America and Seminole in
July 2002 (see Note 4).
F-96
SCHEDULE II
ENTERPRISE PRODUCTS OPERATING L.P.
VALUATION AND QUALIFYING ACCOUNTS
ADDITIONS
---------------------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER BALANCE AT
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS END OF PERIOD
- ---------------------------------- -------------- -------------- -------------- -------------- --------------
ACCOUNTS RECEIVABLE - TRADE:
Allowance for doubtful
accounts
2002 $ 20,642 $ 5,367 (b) $ (4,813) (d) $ 21,196
2001 10,916 $ 6,200 (a) 6,522 (c) (2,996) (d) 20,642
2000 15,871 (4,955) (d) 10,916
OTHER CURRENT ASSETS:
Additional credit reserve
for Enron
2002 $ 4,305 $ (4,305) (b)
2001 4,305 (a) 4,305
OTHER CURRENT LIABILITIES:
Reserve for environmental
liabilities
2002 102 (e) (93) (e) 9
Reserve for inventory
gains and losses (f)
2002 2,029 500 (g) (1,258) (h) 1,271
2001 5,690 500 (g) (4,161) (h) 2,029
2000 2,894 500 (g) 2,296 (h) 5,690
OTHER LONG-TERM LIABILITIES:
Reserve for environmental
liabilities
2002 45 (e) 90 (e) 135
- -------------------------------------------------------------------------------
The following explanations describe significant transactions affecting the
amounts shown in the table above:
(a) In December 2001, Enron North America 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 established at December 31, 2001,
$6.3 million offsets billed amounts due from Enron recorded in Accounts
Receivable-Trade. The remaining $4.3 million in reserve offsets various
unbilled commodity financial instrument positions, which were reclassified to
"Additional credit reserve from Enron".
(b) The $4.3 million in unbilled positions was invoiced in early 2002 as the
financial instruments settled (see Note 17). These amounts were reclassified
from the "Additional credit reserve for Enron" account to "Allowance for
doubtful accounts" accordingly.
(c) The allowance account was increased in April 2001 as a result of accounts
acquired from Acadian Gas.
(d) In the normal course of business, we charged the allowance account for
customer amounts that have been deemed uncollectible.
(e) In July 2002, we acquired the Mid-America pipeline from Williams. This
operation had existing minor environmental liabilities that were of a current
and long-term nature that we recorded using purchase accounting. Since the
acquisition, various vendor invoices have been charged against the current
portion of the reserve. In addition, the long-term portion of the reserve has
been increased due to revisions in management estimates of the future liability
to remediate the sites involved.
(f) In general, the inventory gain/loss reserve was established to cover
anticipated net losses attributable to the storage of NGL and petrochemical
products in underground storage caverns.
(g) The reserve is increased based on management's estimate of annual net
product storage losses.
(h) Product losses are charged against and reduce the reserve balance.
Conversely, product gains increase the reserve. Management regularly reviews
the status of the reserve and determines the appropriate level based on
historical and anticipated storage well activity. A review of the reserve
balance was performed in late 2001 and based upon its findings and estimated
future losses, the reserve was adjusted by $2.4 million.
F-97
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrants have duly caused this report to be signed
on their behalf by the undersigned thereunto duly authorized, in the City of
Houston, State of Texas on March 31, 2003.
ENTERPRISE PRODUCTS PARTNERS L.P. (A Delaware Limited Partnership)
ENTERPRISE PRODUCTS OPERATING L.P. (A Delaware Limited Partnership)
By: ENTERPRISE PRODUCTS GP, LLC, as General Partner for both registrants
By: /s/ Michael J. Knesek
----------------------------
Name: Michael J. Knesek
Title: Vice President, Controller and Principal Accounting Officer
of the General Partner
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
registrants and in the capacities indicated below on March 31, 2003.
SIGNATURE TITLE
--------- (OF ENTERPRISE PRODUCTS GP, LLC)
--------------------------------
/s/ Dan L. Duncan
- ----------------------------------------------------------- Chairman of the Board and Director
Dan L. Duncan
/s/ O.S. Andras President, Chief Executive Officer and Director
- ----------------------------------------------------------- (Principal Executive Officer)
O. S. Andras
/s/ Richard H. Bachmann Executive Vice President, Chief Legal Officer,
- ----------------------------------------------------------- Secretary and Director
Richard H. Bachmann
/s/ Michael A. Creel Executive Vice President and Chief Financial Officer
- ----------------------------------------------------------- (Principal Financial Officer)
Michael A. Creel
/s/ Michael J. Knesek Vice President, Controller and Principal Accounting
- ----------------------------------------------------------- Officer
Michael J. Knesek
/s/ Randa D. Williams Director
- -----------------------------------------------------------
Randa D. Williams
/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/ A.Y. Noojin, III Director
- -----------------------------------------------------------
A. Y. Noojin, III
/s/ Richard S. Snell Director
- -----------------------------------------------------------
Richard S. Snell
/s/ Lee W. Marshall, Sr. Director
- -----------------------------------------------------------
Lee W. Marshall, Sr.
S-1
SARBANES-OXLEY SECTION 302 CERTIFICATIONS
CERTIFICATION OF O.S. ANDRAS, PRINCIPAL EXECUTIVE OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS PARTNERS L.P.
I, O.S. Andras, the Principal Executive Officer of Enterprise Products GP,
LLC, the General Partner of Enterprise Products Partners L.P., certify that:
1. I have reviewed this annual report on Form 10-K of Enterprise Products
Partners L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 31, 2003
/s/ O.S. Andras
----------------------------------------------
Name: O.S. Andras
Title: Principal Executive Officer of our General
Partner, Enterprise Products GP, LLC
C-1
CERTIFICATION OF MICHAEL A. CREEL, PRINCIPAL FINANCIAL OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS PARTNERS L.P.
I, Michael A. Creel, the Principal Financial Officer of Enterprise
Products GP, LLC, the General Partner of Enterprise Products Partners L.P.,
certify that:
1. I have reviewed this annual report on Form 10-K of Enterprise Products
Partners L.P.;
2 Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 31, 2003
/s/ Michael A. Creel
---------------------------------------------------
Name: Michael A. Creel
Title: Principal Financial Officer of our General
Partner, Enterprise Products GP, LLC
C-2
CERTIFICATION OF O.S. ANDRAS, PRINCIPAL EXECUTIVE OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS OPERATING L.P.
I, O.S. Andras, the Principal Executive Officer of Enterprise Products GP,
LLC, the General Partner of Enterprise Products Operating L.P., certify that:
1. I have reviewed this annual report on Form 10-K of Enterprise Products
Operating L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 31, 2003
/s/ O.S. Andras
---------------------------------------------------
Name: O.S. Andras
Title: Principal Executive Officer of our General
Partner, Enterprise Products GP, LLC
C-3
CERTIFICATION OF MICHAEL A. CREEL, PRINCIPAL FINANCIAL OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS OPERATING L.P.
I, Michael A. Creel, the Principal Financial Officer of Enterprise
Products GP, LLC, the General Partner of Enterprise Products Operating L.P.,
certify that:
1. I have reviewed this annual report on Form 10-K of Enterprise Products
Operating L.P.;
2 Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 31, 2003
/s/ Michael A. Creel
---------------------------------------------------
Name: Michael A. Creel
Title: Principal Financial Officer of our General
Partner, Enterprise Products GP, LLC
C-4
INDEX TO EXHIBIT
EXHIBIT NO. EXHIBIT*
- ----------- --------------------------------------------------------------------------------------------------
2.1 -- Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P.
dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Form 8-K filed September
26, 2000).
2.2 -- Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and
Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to
Exhibit 10.1 to Form 8-K filed February 8, 2002.)
2.3 -- Purchase and Sale Agreement dated 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 (incorporated by reference to Exhibit 10.2 to Form 8-K filed February 8, 2002).
2.4 -- Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated
July 31, 2002 (incorporated by reference to Exhibit 2.2 to Form 8-K filed August 12, 2002).
2.5 -- Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002
(incorporated by reference to Exhibit 2.1 to Form 8-K filed August 12, 2002).
3.1 -- First Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC
dated as of September 17, 1999 (incorporated by reference to Exhibit 99.8 to the Form 8-K/A-l
filed October 27, 1999).
3.2** -- Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of the
General Partner dated as of September 19, 2002.
3.3 -- Third Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P.
dated May 15, 2002 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 13, 2002).
3.4 -- Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Enterprise
Products Partners L.P. dated August 7, 2002 (incorporated by reference to Exhibit 3.3 to Form
10-Q filed August 13, 2002).
3.5 -- Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Enterprise
Products Partners L.P. dated December 17, 2002 (incorporated by reference to Exhibit 3.5 to Form
8-K filed December 17, 2002).
3.6 -- Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated
as of July 31, 1998 (incorporated by reference to Exhibit 3.2 to Registration Statement on Form
S-1/A filed July 21, 1998).
4.1 -- 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
(incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
4.2 -- First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating
L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National
Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on
Form S-4 filed January 28, 2003).
4.3** -- Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating
L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National
Association, as Trustee.
4.4 -- Global Note representing $350 million principal amount of 6.375% Series A Senior Notes due 2013
with attached Guarantee (incorporated by reference to Exhibit 4.3 to Registration Statement on
Form S-4 filed January 28, 2003).
4.5** -- Rule 144 A Global Note representing $499.2 million principal amount of 6.875% Series A Senior
Notes due 2033 with attached Guarantee.
4.6** -- Regulation S Global Note representing $800,000 principal amount of 6.875% Series A Senior Notes
due 2033 with attached Guarantee.
4.7 -- Form of Global Note representing $350 million principal amount of 6.375% Series B Senior Notes
due 2013 with attached Guarantee (included in Exhibit 4.2).
4.8** -- Form of Global Note representing $500 million principal amount of 6.875% Series B Senior Notes
due 2033 with attached Guarantee (included in Exhibit 4.3).
4.9 -- Registration Rights Agreement dated as of January 22, 2003, among Enterprise Products Operating
L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein (incorporated by
reference to Exhibit 4.5 to Registration Statement on Form S-4 filed January 28, 2003).
4.10** -- Registration Rights Agreement dated as of February 14, 2003, among Enterprise Products Operating
L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein.
4.11 -- Global Note representing $350 million principal amount of 8.25% Senior Notes due 2005
(incorporated by reference to Exhibit 4.2 to Form 8-K filed March 10, 2000).
4.12 -- Global Note representing $450 million principal amount of 7.50% Senior Notes due 2011
(incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001).
4.13 -- Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to Registration
Statement on Form S-1/A; File No. 333-52537, filed July 21, 1998).
4.14 -- $250 Million Multi-Year Revolving Credit Facility dated as of November 17, 2000, among Enterprise
Products Operating L.P., First Union National Bank, as Administrative Agent, Bank One, NA, as
Documentation Agent, the Chase Manhattan Bank, as Syndication Agent, and the several banks from
time to time parties thereto, with First Union Securities, Inc. and Chase Securities Inc. as
Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 4.2 to Form
8-K filed January 24, 2001).
4.15 -- $150 Million 364-Day Revolving Credit Facility November 17, 2000, among Enterprise Products
Operating L.P., First Union National Bank, as Administrative Agent, Bank One, NA, as
Documentation Agent, the Chase Manhattan Bank, as Syndication Agent, and the several banks from
time to time parties thereto, with First Union Securities, Inc. and Chase Securities Inc. as
Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 4.3 to Form
8-K filed January 24, 2001).
4.16 -- Guaranty Agreement dated as of November 17, 2000, by Enterprise Products Partners L.P. in favor
of First Union National Bank, as Administrative Agent, with respect to the $250 Million
Multi-Year Revolving Credit Facility included as Exhibit 4.4 above (incorporated by reference to
Exhibit 4.4 to Form 8-K filed January 24, 2001).
4.17 -- Guaranty Agreement dated as of November 17, 2000, by Enterprise Products Partners L.P. in favor
of First Union National Bank, as Administrative Agent, with respect to the $150 Million 364-Day
Revolving Credit Facility (incorporated by reference to Exhibit 4.5 to Form 8-K filed January 24,
2001).
4.18 -- First Amendment to Multi-Year Credit Facility dated April 19, 2001 (incorporated by reference to
Exhibit 4.12 to Form 10-Q filed May 14, 2001).
4.19 -- Second Amendment to Multi-Year Revolving Credit Facility dated April 14, 2002 (incorporated by
reference to Exhibit 4.14 to Form 10-Q filed May 14, 2002).
4.20 -- Third Amendment to Multi-Year Revolving Credit Facility dated July 31, 2002 (incorporated by
reference to Exhibit 4.1 to Form 10-Q filed August 12, 2002).
4.21 -- Fourth Amendment to Multi-Year Revolving Credit Facility dated effective as of November 15, 2002
(incorporated by reference to Exhibit 4.21 to Form 10-Q filed November 13, 2002).
4.22 -- First Amendment to 364-Day Credit Facility dated November 6, 2001, effective as of November 16,
2001 (incorporated by reference to Exhibit 4.13 to Form 10-Q filed August 13, 2002).
4.23 -- Second Amendment to 364-Day Revolving Credit Facility dated April 24, 2002 (incorporated by
reference to Exhibit 4.15 to Form 10-Q filed May 14, 2002).
4.24 -- Third Amendment to 364-Day Revolving Credit Facility dated July 31, 2002 (incorporated by
reference to Exhibit 4.2 to Form 8-K filed August 12, 2002).
4.25 -- Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit "B" to
Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.26 -- Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit "E"
to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.27 -- Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit "C" to
Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
10.1 -- $1.2 Billion 364-Day Term Credit Facility dated as of July 31, 2002, among Enterprise Products
Operating Partnership L.P., Wachovia Bank, National Association, as Administrative Agent, Lehman
Commercial Paper Inc., as Co-Syndication Agent, Royal Bank of Canada, as Co- Syndication Agent
and Arranger, with Wachovia Securities, Inc. and Lehman Brothers Inc., as Lead Arrangers and
Joint Bookrunners and RBC Capital Markets, as Arranger (incorporated by reference to Exhibit 4.3
to Form 8-K filed August 12, 2002).
10.2 -- Guaranty Agreement dated as of July 31, 2002 by Enterprise Products Partners L.P. in favor of
Wachovia Bank, National Association, as Administrative Agent, with respect to the $1.2 Billion
364-Day Term Credit Facility (incorporated by reference to Exhibit 4.4 to Form 8-K filed August
12, 2002).
10.3 -- EPCO Agreement among Enterprise Products Partners L.P., Enterprise Products Operating L.P.,
Enterprise Products GP, LLC and Enterprise Products Company dated July 31, 1998 (incorporated by
reference to Exhibit 10.3 to Registration Statement on Form S-4 filed January 28, 2003).
10.4 -- Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation
Company dated June 1, 1998 (incorporated by reference to Exhibit 10.3 to Registration Statement
Form S-1/A filed July 8,1998).
10.5 -- Partnership Agreement among Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise
Products Company dated May 1, 1992 (incorporated by reference to Exhibit 10.5 to Registration
Statement on Form S-1 filed May 13, 1998).
10.6 -- Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules
Incorporated dated December 13, 1978 (incorporated by reference to Exhibit 10.9 to Registration
Statement on Form S-l filed May 13, 1998).
10.7 -- 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 (incorporated by reference to Exhibit 10.10 to
Registration Statement on Form S-l/A filed July 8,1998).
10.8 -- 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 (incorporated by
reference to Exhibit 10.12 to Registration Statement on Form S-l/A filed July 8, 1998).
10.9 -- 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 (incorporated by
reference to Exhibit 10.13 to Registration Statement on Form S-l/A filed July 8, 1998).
10.10 -- 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 (incorporated by reference to Exhibit 10.14 to Form 10-Q filed November 15, 1999).
10.11 -- 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. (incorporated by reference to Exhibit 10.13 to Form 10-Q filed August 13, 2001).
10.12*** -- Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to
Post-Effective Amendment No. 1 to Registration Statement on Form S-8 filed March 13, 2003).
10.13*** -- Form of Option Grant Award under the 1998 Long-Term Incentive Plan (incorporated by reference
to Exhibit 4.2 to Post-Effective Amendment No. 1 to Registration Statement on Form S-8 filed
March 13, 2003).
12.1** -- Computation of ratio of earnings to fixed charges for each of the five years ended
December 31, 2002, 2001, 2000, 1999 and 1998 for Enterprise Products Partners L.P.
12.2** -- Computation of ratio of earnings to fixed charges for each of the five years ended
December 31, 2002, 2001, 2000, 1999 and 1998 for Enterprise Products Operating L.P.
21.1** -- List of Subsidiaries of the Registrants.
23.1** -- Consent of Deloitte & Touche LLP.
99.1** -- Audited Balance Sheet of Enterprise Products GP, LLC, as of December 31, 2002.
99.2** -- Section 1350 Certifications
* With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for
Enterprise Products Partners L.P. is 1-14323 and the Commission file number for Enterprise Products Operating L.P. is
333-93239-01.
** Filed with this report.
*** Identifies management contract and compensatory plan arrangements