<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON SEPTEMBER 27, 2000
REGISTRATION NO. 333-44840
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
AMENDMENT NO. 1
TO
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
EOTT ENERGY PARTNERS, L.P.
(Exact Name of Registrant as specified in charter)
<TABLE>
<S> <C> <C>
DELAWARE 5171 76-0424520
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification Number)
</TABLE>
<TABLE>
<S> <C>
REX R. ROGERS
1330 POST OAK BOULEVARD 1400 SMITH STREET
HOUSTON, TEXAS 77056 HOUSTON, TEXAS 77002
(713) 993-5200 (713) 853-6161
(Address, including Zip Code, and (Name and Address, Including Zip Code, and
Telephone Number, Including Area Code, of Telephone Number, Including Area Code,
Registrant's Principal Executive Offices) of Agent for Service)
</TABLE>
Please send copies of communications to:
ROBERT S. BAIRD
VINSON & ELKINS L.L.P.
2700 ONE AMERICAN CENTER, 600 CONGRESS
AUSTIN, TEXAS 78701
(512) 495-8451
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: From time
to time after the effective date of this registration statement.
If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box. [X]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
CALCULATION OF REGISTRATION FEE
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PROPOSED PROPOSED
MAXIMUM MAXIMUM
TITLE OF EACH CLASS OF AMOUNT TO BE OFFERING PRICE AGGREGATE AMOUNT OF
SECURITIES TO BE REGISTERED REGISTERED PER UNIT(1) OFFERING PRICE(1) REGISTRATION FEE
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<S> <C> <C> <C> <C>
Common Units...................... 1,700,000 $15.2188 $25,871,875 $6,831.00(2)
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</TABLE>
(1) Estimated solely for the purpose of calculating the registration fee (based
on the average of the high and low prices of the common units as reported in
the New York Stock Exchange composite transaction reporting system on August
29, 2000).
(2) Previously paid.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a),
MAY DETERMINE.
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<PAGE> 2
THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE
MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH
THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT
AN OFFER TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN OFFER TO BUY
THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED.
SUBJECT TO COMPLETION, DATED SEPTEMBER 27, 2000
PROSPECTUS
1,700,000
COMMON UNITS
EOTT ENERGY PARTNERS, L.P.
We are EOTT Energy Partners, L.P., a publicly traded limited partnership
engaged in the purchasing, gathering, transporting, storage and resale of crude
oil, refined petroleum products and natural gas liquids and in related
activities.
We currently have 18,476,011 common units outstanding. Our common units are
traded on the New York Stock Exchange under the symbol "EOT."
The address of our principal executive offices is 1330 Post Oak Boulevard,
Houston, Texas 77056, and the telephone number is (713) 993-5200.
A selling shareholder is offering and selling common units pursuant to this
prospectus. We will not receive any of the proceeds of sales by this selling
shareholder. On September 26, 2000, the last reported sales price of the common
units on the New York Stock Exchange was $15.9375 per unit. The selling
shareholder may sell its units from time to time through or to underwriters or
brokers or dealers, or directly to investors, at a fixed price or prices, which
may be changed from time to time, at market prices prevailing at the time of
such sale, at prices related to such market prices, or at negotiated prices. In
connection with any sales, distributors' or sellers' commissions may be paid or
allowed. We have agreed to pay all registration expenses related to the sale of
shares by the selling shareholder, except for underwriting discounts and
commissions, which will be paid by the selling shareholder. We have agreed to
indemnify the selling shareholder against certain liabilities relating to the
resale of the shares under the Securities Act of 1933. If the selling
shareholder offers shares through underwriters, the underwriters will be named
in the prospectus supplement relating to such sale.
WE WILL PROVIDE SPECIFIC TERMS OF OFFERINGS OF OUR SECURITIES IN PROSPECTUS
SUPPLEMENTS. YOU SHOULD READ THIS PROSPECTUS AND ANY SUPPLEMENT TO THIS
PROSPECTUS CAREFULLY BEFORE YOU INVEST. YOU SHOULD ALSO READ THE DOCUMENTS WE
HAVE REFERRED YOU TO IN THE "WHERE YOU CAN FIND MORE INFORMATION" SECTION OF
THIS PROSPECTUS FOR INFORMATION ON US. TOGETHER THESE DOCUMENTS WILL PROVIDE YOU
WITH THE SPECIFIC TERMS OF THE OFFERINGS. THIS PROSPECTUS MAY NOT BE USED TO
SELL OUR SECURITIES THROUGH UNDERWRITERS UNLESS IT IS ACCOMPANIED BY A
PROSPECTUS SUPPLEMENT.
LIMITED PARTNER INTERESTS ARE INHERENTLY DIFFERENT FROM CAPITAL STOCK OF A
CORPORATION. PURCHASERS OF OUR SECURITIES SHOULD CONSIDER EACH OF THE FACTORS
DESCRIBED UNDER "RISK FACTORS" ON PAGES 2 TO 6 BEFORE INVESTING IN OUR COMMON
UNITS.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
The date of this prospectus is , 2000
<PAGE> 3
TABLE OF CONTENTS
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PAGE
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<S> <C>
About This Prospectus....................................... ii
Where You Can Find More Information......................... ii
Forward-Looking Statements.................................. ii
Who We Are.................................................. 1
Risk Factors................................................ 2
Use of Proceeds............................................. 7
Capitalization.............................................. 7
Price Range of Common Units and Distributions............... 8
Selected Historical Financial Data.......................... 9
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 11
Business.................................................... 23
Management.................................................. 35
Certain Transactions........................................ 43
Principal Shareholders...................................... 45
Selling Shareholder......................................... 46
Description of our Common Units............................. 47
Cash Distribution Policy.................................... 48
Description of our Partnership Agreement.................... 50
Tax Considerations.......................................... 53
Plan of Distribution........................................ 67
Legal Matters............................................... 68
Experts..................................................... 68
Index to Financial Statements............................... F-1
Form of Transfer Application........................ Appendix I
</TABLE>
You should rely only on the information contained in this prospectus or any
prospectus supplement. We have not authorized anyone else to provide you with
any information. We are not making an offer of these securities in any
jurisdiction where the offer or sale is not permitted. You should not assume
that the information in this prospectus or any prospectus supplement is accurate
as of any date other than the date on the front of each document.
i
<PAGE> 4
ABOUT THIS PROSPECTUS
This prospectus is part of a registration statement that we filed with the
SEC using a "shelf" registration process. Under this shelf process, the selling
shareholder may offer from time to time up to 1,700,000 of our common units.
Each time the selling shareholder offers our securities through underwriters and
in some other instances, we will provide you with a prospectus supplement that
will describe, among other things, the specific amounts and prices of the
securities being offered and the terms of the offering. The prospectus
supplement may also add, update or change information contained in this
prospectus. Therefore, before you invest in our securities, you should read this
prospectus, any prospectus supplements and all additional information referenced
in the next section.
WHERE YOU CAN FIND MORE INFORMATION
We file annual, quarterly and current reports and other information with
the SEC. You may read and copy any document we file at the SEC's public
reference room at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W.,
Washington, D.C. 20549 and at the SEC's public reference rooms in New York, New
York and Chicago, Illinois. Please call the SEC at 1-800-SEC-0330 for further
information on the public reference rooms. In addition, the SEC maintains a web
site that contains reports, information statements and other information
regarding issuers that file electronically. Our SEC filings are also available
on this web site at http://www.sec.gov. You can also obtain information about us
at the offices of the New York Stock Exchange, 20 Broad Street, New York, New
York, 10005.
You may request a copy of these filings at no cost by making written or
telephone requests for copies to:
EOTT Energy Corp.
1400 Smith Street
Houston, Texas 77002
Attention: Shareholder Relations
Telephone: (713) 853-6161
FORWARD-LOOKING STATEMENTS
This prospectus contains statements that constitute "forward looking
statements" within the meaning of Section 27A of the Securities Act and Section
21E of the Securities Exchange Act of 1934. In general, any statement other than
a statement of historical fact is a forward looking statement. We caution that
our actual results may differ materially from those anticipated or projected
forward looking statements. Any differences could result from a variety of
factors, including the following:
- our ability to maintain existing volumes of crude oil purchased at the
lease and to obtain additional volumes of crude oil;
- our success in hedging our positions;
- industry conditions;
- prices and demand for crude oil;
- economic, political and administrative developments that impact federal,
state and local departments and agencies that regulate the oil industry;
- the effect of competition;
- conditions of the capital markets; and
- our ability to successfully acquire and efficiently integrate new assets.
The information we set forth under the heading "Risk Factors" details these
and other facts that could affect our operating results. You should carefully
consider all this information before you invest.
ii
<PAGE> 5
WHO WE ARE
We are EOTT Energy Partners, L.P., and we purchase, gather, transport,
store and resell crude oil, refined petroleum products and natural gas liquids.
As an intermediary, we seek to earn profits primarily by buying crude oil at
competitive prices, efficiently transporting and handling the purchased crude
oil and marketing the crude oil to refinery customers or other trade partners
who can most benefit from the particular crude oil type. Through our crude oil
gathering and marketing operations, we purchase crude oil produced from
approximately 40,000 leases owned by many of the largest integrated and
independent crude oil producers in the United States and Canada. We purchase
approximately 87% of our lease crude oil from independent oil producers and
approximately 13% from major integrated oil companies. We market the crude oil
to major oil companies and independent refiners throughout the United States and
Canada. In addition to our gathering and marketing operations, we have pipeline
operations in which we transport crude oil on our intrastate and interstate
pipelines based on regulated published tariffs.
On December 1, 1998, we purchased crude oil gathering and transportation
assets in key oil producing regions in a transaction that almost tripled our
pipeline mileage and almost doubled our crude oil lease barrels under contract.
The acquisition included approximately 3,900 miles of crude oil pipelines, crude
oil transport trucks, meter stations, vehicles, storage tanks and contracts for
approximately 180,000 lease barrels of crude oil per day from production in 11
central and western states including Texas, Oklahoma, Kansas and California. On
May 1, 1999, we purchased crude oil transportation and storage assets that
included approximately 1,800 miles of common carrier crude oil pipelines in
Southeast New Mexico and West Texas, bringing our crude oil pipeline mileage to
a total of approximately 8,300 miles.
We are a Delaware limited partnership. EOTT Energy Corp., a Delaware
corporation and an indirect wholly-owned subsidiary of Enron Corp., serves as
our sole general partner. Our operations are conducted through, and the
operating assets are owned by, EOTT Energy Operating Limited Partnership, EOTT
Energy Canada Limited Partnership and EOTT Energy Pipeline Limited Partnership,
each of which is a Delaware limited partnership. Our general partner is also the
general partner of our operating partnerships.
1
<PAGE> 6
RISK FACTORS
In addition to the other information in this prospectus and any
accompanying prospectus supplement, you should carefully consider and evaluate
all of the information relating to the risk factors set forth below.
RISKS RELATED TO OUR BUSINESS
Economic and industry factors beyond our control, including production levels
of crude oil, can adversely affect our gross margin.
Our ability to pay cash distributions and service our debt obligations
depends primarily on our gross margin, which is the difference between the sales
price of crude oil and the cost of crude oil purchased, including costs paid to
third parties for transportation and handling charges. Historically, our
business has been very competitive with thin and volatile profit margins. Our
gross margin is affected by many factors beyond our control, including:
- the performance of the U.S. and world economies;
- volumes of crude oil produced in the areas we serve;
- demand for oil by refineries and other customers;
- prices for crude oil at various lease locations;
- prices for crude oil futures contracts on the New York Mercantile
Exchange;
- the competitive position of alternative energy sources; and
- the availability of pipeline and other transportation facilities that may
make crude oil production from other producing areas competitive with
crude oil production that we purchase at the lease.
The absolute price levels for crude oil do not necessarily bear a direct
relationship to our gross margins per barrel, and our gross margins per barrel
cannot be projected with any level of certainty. Due to the volatility of crude
oil prices and the decline in crude oil production, crude oil gathering margins
have suffered industry wide over the last few years. Although there has been
general improvement in crude oil margins since 1997, margins have not returned
to historical levels.
If we cannot maintain our volumes of crude oil purchased at the lease, our
ability to pay cash distributions and service our debt obligations will be
adversely affected.
Our profitability depends in part on our ability to offset volumes lost
because of natural declines in crude oil production from depleting wells or
volumes lost to competitors. This is particularly difficult in the current
environment of reduced drilling activity and discontinued production operations.
The amount of drilling and production will depend in large part on crude oil
prices. To the extent that low crude oil prices result in lower volumes of lease
crude oil available for purchase, we may experience lower per barrel margins, as
competition for available lease crude oil on the basis of price intensifies. It
is possible that domestic crude oil producers may further reduce or discontinue
drilling and production operations. In addition, a sustained depression in crude
oil prices could result in the bankruptcy of some producers.
Because producers experience inconveniences in switching lease crude oil
purchasers, producers typically do not change purchasers on the basis of minor
variations in price. Thus, we may experience difficulty acquiring lease crude
oil in areas where there are existing relationships between producers and other
gatherers and purchasers of crude oil. Furthermore, we cannot assure you that we
will be successful in obtaining production made available by major oil companies
or that we will be successful in acquiring other gatherers or marketers.
2
<PAGE> 7
Our performance depends on our ability to minimize bad debts and legal
liability when extending credit to operators and customers.
When we purchase crude oil at the lease, we often make payment to an
operator who is responsible for the correct payment and distribution of the
proceeds to other parties. If the operator does not have sufficient resources to
indemnify and defend us in case of a protest, action or complaint by those other
parties, our costs could rise. In addition, because we may extend credit to some
customers in large amounts, it is important that our credit review, evaluation
and control mechanisms work properly. Even if our mechanisms work properly, we
cannot assure you that our customers will not experience losses in dealings with
other parties, in which case we could be adversely affected.
A reduction in our credit standing or ability to access capital would
adversely affect our basic purchasing and marketing activities.
Our financial resources are a major consideration for parties that enter
into transactions with us, and because of the large dollar volume of the
marketing transactions in which we engage, we have a significant need for
working capital. While we believe that our revolving credit facility will be
sufficient to support our working capital needs, any significant decrease in our
financial strength, regardless of the reason for the decrease, may:
- increase the number of transactions requiring letters of credit or other
financial support;
- make it more difficult for us to obtain letters of credit upon expiration
of our revolving credit facility;
- make it more difficult to renew our revolving credit facility upon its
expiration; or
- increase the cost of obtaining letters of credit.
If we do experience a decrease in financial strength, or if our general partner
is unsuccessful in managing our working capital position, we may be unable to
maintain or increase the level of our purchasing and marketing activities. We
cannot assure you that our revolving credit facility will be adequate or that we
will not be required to reduce our market activities because of limitations on
our ability to obtain financing for our working capital needs.
Our ability to maintain or increase our gross margins is dependent on the
success of our price risk management strategies.
Sophisticated price risk management strategies, including those involving
price hedges using New York Mercantile Exchange futures contracts, are very
important in maintaining or increasing our gross margins. Hedging techniques
require significant resources dedicated to the management of futures positions
and physical inventories. We cannot assure you that our price risk management
strategies will be successful in protecting us from risks or in maintaining our
gross margins at desirable levels. Furthermore, we have certain basis risks (the
risk that price relationships between delivery points, grades of crude oil or
delivery periods will change) that cannot be completely hedged, and from time to
time we enter into transactions providing for purchases and sales in future
periods in which the volumes of crude oil are balanced but where either the
purchase or the sale prices are not fixed at the time the transactions are
entered into. In these cases we are subject to the risk that prices may change
or that price changes will not occur as anticipated.
Our ability to increase our profitability and cash flow will depend to a
large extent on our success in making wise decisions regarding sources of supply
and demand for crude oil, our skill in handling the transportation and storage
of crude oil and our ability to respond to changes in the markets. The marketing
3
<PAGE> 8
of crude oil is complex and requires detailed current knowledge of crude oil
sources and outlets and a familiarity with a number of factors including:
- types of crude oil;
- individual refinery demand for specific grades of crude oil;
- area market price structures for the different grades of crude oil;
- location of customers;
- availability of transportation facilities; and
- timing and costs (including storage) involved in delivering crude oil to
the appropriate customer.
Technical and structural improvements in the markets for crude oil may have an
adverse effect on our performance.
We realize margins because of our ability to take advantage of our
gathering, storage and transportation assets and our ability to effect
transactions at many different delivery points. Developments in the markets for
crude oil or petroleum products, such as the development of more accurate price
reporting mechanisms or the introduction of additional futures contracts
involving new delivery locations and products, may adversely affect our margins.
Environmental and other regulatory costs and liabilities could affect our cash
flow.
Our business is heavily regulated by federal, state and local agencies with
respect to environmental, safety and other regulatory matters. This regulation
increases our cost of doing business. We may be subject to substantial penalties
if we fail to comply with any regulation. We cannot assure you that regulatory
changes enacted by regulatory agencies that have jurisdiction over us will not
increase our cost of conducting business or otherwise negatively impact our
profitability, cash flow and financial condition.
We are subject to numerous laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. If an accidental leak or spill occurs in one of our pipelines or at
a storage facility, we may have to pay a significant amount to clean up the leak
or spill. The resulting costs and liabilities could negatively affect the level
of cash available to pay amounts due on our debt and for distributions to
unitholders. Although we believe that we are in compliance in all material
respects with all applicable environmental laws and regulations, we could be
adversely affected by environmental costs and liabilities that may be incurred
or increased costs resulting from failure to obtain all required regulatory
consents and approvals. As to all of our properties, we cannot assure you that
past operating practices, including those that were state of the art at the time
employed, will not result in significant future environmental liabilities. In
addition, we cannot assure you that in the future regulatory agencies with
jurisdiction over us will not enact additional environmental regulations that
will negatively affect our profitability, cash flow and financial condition.
Our pipelines are subject to rate regulation as well as laws relating to
safety and the environment. Federal and state agencies could change the tariffs
we may charge for common carrier pipeline transportation or impose additional
safety or environmental requirements, any of which could affect our
profitability, cash flow and financial condition.
Our rapid growth may cause difficulties integrating new operations.
Part of our business strategy includes acquiring additional assets that
will allow us to increase distributions to unitholders. In the last few years,
we have made several acquisitions that significantly increased our asset base.
Unexpected costs or challenges may arise whenever assets with different
operations are combined. Successful acquisitions require management and other
personnel to devote significant amounts of time to integrating the acquired
assets with existing operations. These efforts may
4
<PAGE> 9
temporarily distract their attention from day-to-day business, the development
or acquisition of new properties and other business opportunities.
RISKS RELATED TO OUR PARTNERSHIP STRUCTURE
Cash distributions to our unitholders are not guaranteed and may fluctuate;
Enron's commitment to support cash distributions on common units will expire
after 2001.
Our cash distributions are not guaranteed and may fluctuate with our
performance. Enron has a commitment to contribute to us up to $29 million ($19.7
million of which is available) if necessary to support our ability to pay the
minimum quarterly distribution of $0.475 per unit ($1.90 annualized). In
addition to the current commitment, Enron has previously contributed $21.9
million to help us pay the minimum quarterly distribution. However, Enron's
commitment to support the minimum quarterly distribution extends only to
quarters through December 31, 2001.
Our unitholders will have limited voting rights and will not control our
general partner.
We are a limited partnership, operated under the direction of our general
partner. This structure affects our common unitholders in various ways
including:
- the voting rights of common unitholders are more limited than those of
holders of capital stock in a corporation;
- our common unitholders have no right to participate in our management and
have no right to elect our general partner or members of its board of
directors;
- our partnership agreement contains provisions making it difficult to
replace our general partner; and
- our general partner and its affiliates may have conflicts of interest
with our common unitholders and with us.
We do not have the same flexibility as corporations to accumulate cash and
equity to protect against illiquidity in the future.
Unlike a corporation, our partnership agreement requires us to make
quarterly distributions to our partners of all available cash, consisting of all
cash receipts less disbursements and any amounts reserved for commitments and
contingencies, including capital and operating costs and debt covenant
requirements. The value of our common units is likely to decrease if the amount
we distribute per unit decreases. Accordingly, if we experience a liquidity
problem in the future and are required to reduce distributions on our common
units, we may not be able to issue equity on favorable terms.
Our partnership agreement modifies the fiduciary duties of our general partner
under Delaware law.
Our partnership agreement modifies fiduciary duties of our general partner
to the limited partners under Delaware law. These modifications of state law
standards of fiduciary duty may limit the ability of unitholders to challenge
successfully the actions of the general partner as being a breach of what would
otherwise have been a fiduciary duty.
Unitholders may have negative tax consequences if we default on our debt or
sell assets.
If we default on any of our debt, the lenders will have the right to sue us
for non-payment. Such an action could cause an investment loss and cause
negative tax consequences for unitholders through the realization of taxable
income by unitholders without a corresponding cash distribution. Likewise, if we
were to dispose of assets and realize a taxable gain while there is substantial
debt outstanding and proceeds of the sale were applied to the debt, unitholders
could have increased taxable income without a corresponding cash distribution.
5
<PAGE> 10
Systems integration issues could adversely affect the preparation of timely
and accurate financial information.
During the first quarter of 2000, we identified certain systems integration
issues relating to our new computerized marketing and accounting system, and we
immediately commenced an extensive review and analysis of the implementation of
the new system. As a result of these efforts, we identified and quantified the
impacts of the systems integration issues relating to our new computerized
marketing and accounting system and recorded appropriate financial statement
adjustments in the first quarter of 2000. We have implemented and continue to
implement additional control processes and procedures that we believe are
sufficient to permit the preparation of timely and accurate financial
information, including additional preventative and monitoring controls to ensure
the integrity and reliability of financial information generated by the system
as well as additional system training for users. Although we believe we have
identified all material systems integration issues which contributed to the
conditions identified in the first quarter of 2000, we can give no assurance
that we may not continue to experience integration issues associated with our
new computerized marketing and accounting system in the future.
RISKS RELATED TO OUR CAPITAL STRUCTURE
Further issuances of units by us could result in dilution for unitholders or
hinder any of our future financings.
The market price of our common units could drop as a result of sales of a
large number of common units in the market or the perception that sales of
common units could occur. These factors could also make it more difficult for us
to raise funds through future offerings of common units. In this respect you
should consider several factors.
First, on February 12, 1999, our unitholders approved a proposal that
authorized us to issue an additional 10 million common units for any business
purpose, 3.5 million of which were issued in a public offering in 1999. The
remaining authorized units may be issued on terms and conditions established by
our general partner in its sole discretion without further approval of any
limited partners. Our partnership agreement also authorizes us to issue other
limited partner interests and other equity under the conditions specified in our
partnership agreement.
Second, our general partner has the right, which it may from time to time
assign in whole or in part to any of its affiliates, to purchase common units,
subordinated units or other equity securities from us whenever, and on the same
terms that, we issue securities to persons other than our general partner and
its affiliates, to the extent necessary to maintain the percentage interest of
our general partner and its affiliates in us that existed immediately prior to
each issuance.
Third, if some or all of our outstanding subordinated units are converted
into common units, the amount of available cash necessary to pay the minimum
quarterly distribution with respect to all of our common units would be
increased proportionately, thereby resulting in a dilution of the interest of
existing common unitholders in our cash distributions.
Finally, if we issue more units, Enron's commitment to support our minimum
quarterly distributions will not increase, thereby resulting in a dilution of
the support obligation per unit.
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USE OF PROCEEDS
We will not receive any of the proceeds from the sale of the common units
offered by the selling shareholder.
CAPITALIZATION
The following table sets forth our capitalization on June 30, 2000. You
should read our historical financial statements and notes that are included in
this prospectus for additional information about our capital structure.
<TABLE>
<CAPTION>
JUNE 30, 2000
--------------
(IN THOUSANDS)
<S> <C>
Short-term debt:
Repurchase agreements(1).............................. $ 52,704
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Total short-term debt......................... $ 52,704
========
Long-term debt.......................................... $235,000
Additional partnership interests........................ 9,318
Partners' Capital
Common Unitholders.................................... 60,702
Subordinated Unitholders.............................. 41,137
General Partner....................................... 7,546
--------
Total Partners' Capital....................... $109,385
========
</TABLE>
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(1) The crude oil repurchase agreements are used for short-term liquidity needs
and allow us to finance the storage of crude oil. We sell crude oil to the
financial institution on a spot basis and agree to repurchase the crude oil
at the same price plus a premium which, in the past, has been approximately
LIBOR plus 0.55%. We store the crude oil we sell as an agent for the
financial institution. Each repurchase agreement is settled at the end of 30
days, and can be renewed monthly; however, either party may terminate the
repurchase agreement. While the repurchase agreements have default, cross-
default, and acceleration provisions, there are no maintenance or financial
covenants associated with the agreements.
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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
The following table sets forth, for the periods indicated, the high and low
sale prices per common unit, as reported on the New York Stock Exchange
Composite Tape, and the amount of cash distributions paid per common unit. The
last reported sale price of common units on the NYSE on September 26, 2000, was
$15.9375 per common unit.
<TABLE>
<CAPTION>
PRICE RANGE CASH
----------------- DISTRIBUTIONS
HIGH LOW PER COMMON UNIT
------- ------- ---------------
<S> <C> <C> <C>
1997
First Quarter................................... $22.375 $19.750 $0.475
Second Quarter.................................. 21.625 18.375 0.475
Third Quarter................................... 20.000 17.125 0.475
Fourth Quarter.................................. 20.625 14.750 0.475
1998
First Quarter................................... $19.188 $17.250 $0.475
Second Quarter.................................. 18.125 14.375 0.475
Third Quarter................................... 17.000 11.250 0.475
Fourth Quarter.................................. 20.000 15.500 0.475
1999
First Quarter................................... $17.500 $15.375 $0.475
Second Quarter.................................. 18.750 17.000 0.475
Third Quarter................................... 19.250 14.563 0.475
Fourth Quarter.................................. 16.500 12.250 0.475
2000
First Quarter................................... $14.250 $11.125 $0.475
Second Quarter.................................. 15.000 13.188 0.475
Third Quarter (through September 26, 2000)...... 16.125 13.0625
</TABLE>
As of August 14, 2000, there were approximately 390 record holders of our
common units, and there were an estimated 15,600 beneficial owners of the common
units held in a street name. There is no established public trading market for
our subordinated units. Generally, we will distribute 100% of our available
cash, as defined in our partnership agreement, within 45 days after the end of
each quarter to unitholders of record and to our general partner. Available cash
consists generally of all of our cash receipts adjusted for cash distributions
and net changes to reserves. The full definition of available cash is set forth
in our partnership agreement and amendments thereto, a form of which is filed or
has been filed previously as an exhibit hereto. Distributions of available cash
to the subordinated unitholders will be subject to the prior rights of the
common unitholders to receive the minimum quarterly distribution of $0.475 per
unit for each quarter during the subordination period and to receive any
arrearages in the distribution of the minimum quarterly distribution on the
common units for prior quarters during the subordination period.
Enron has agreed that it will contribute up to $29 million to us in
exchange for additional partnership interests if necessary to support our
ability to pay the minimum quarterly distribution on common units with respect
to quarters ending on or prior to December 31, 2001. Enron purchased $2.5
million of additional partnership interests in connection with the distribution
for the first quarter of 1999 and $6.8 million of additional partnership
interests in connection with the distribution for the fourth quarter of 1999.
8
<PAGE> 13
SELECTED HISTORICAL FINANCIAL DATA
The following selected historical financial data as of and for each of the
years in the five year period ended December 31, 1999 are derived from our
audited financial statements. The data as of and for the six month periods ended
June 30, 1999 and 2000 are derived from our unaudited financial statements,
which are included elsewhere herein.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
----------------------- --------------------------------------------------------------
2000 1999 1999 1998(1) 1997 1996 1995
---------- ---------- ---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue.......................... $5,196,630 $3,692,460 $8,664,401 $5,294,697 $7,646,099 $7,469,730 $5,088,240
Cost of sales.................... 5,077,567 3,583,967 8,452,086 5,162,092 7,533,054 7,320,203 4,996,439
---------- ---------- ---------- ---------- ---------- ---------- ----------
Gross margin..................... 119,063 108,493 212,315 132,605 113,045 149,527 91,801
Operating expenses............... 78,667 74,815 153,194 104,425 96,158 101,945 72,951
Depreciation and amortization.... 16,859 16,490 33,136 20,951 16,518 15,720 10,512
Impairment of assets............. -- -- -- -- 7,961 -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income (loss).......... 23,537 17,188 25,985 7,229 (7,592) 31,862 8,338
Interest and related charges..... (15,342) (13,820) (29,817) (10,165) (6,661) (3,659) (3,930)
Other income (expense), net...... (1,086) 1,348 1,617 (1,131) (146) 606 1,312
---------- ---------- ---------- ---------- ---------- ---------- ----------
Income (loss) from continuing
operations(2).................. $ 7,109 $ 4,716 $ (2,215) $ (4,067) $ (14,399) $ 28,809 $ 5,720
========== ========== ========== ========== ========== ========== ==========
Net income (loss)(2)(7).......... $ 7,109 $ 6,463 $ (468) $ (4,067) $ (14,399) $ 28,809 $ (61,433)
========== ========== ========== ========== ========== ========== ==========
Basic income (loss) per unit:
Common......................... $ 0.25 $ 0.24 $ (0.06) $ (0.17) $ (0.75) $ 1.50 $ (3.54)
========== ========== ========== ========== ========== ========== ==========
Subordinated................... $ 0.25 $ 0.31 $ 0.06 $ (0.26) $ (0.75) $ 1.50 $ (3.54)
========== ========== ========== ========== ========== ========== ==========
Diluted net income (loss) from
continuing operations per
unit........................... $ 0.25 $ 0.26 $ (0.02) $ (0.21) $ (0.75) $ 1.50 $ 0.33
========== ========== ========== ========== ========== ========== ==========
Cash distributions per common
unit........................... $ 0.95 $ 0.95 $ 1.90 $ 1.90 $ 1.90 $ 1.90 $ 1.80
========== ========== ========== ========== ========== ========== ==========
BALANCE SHEET DATA (AT END OF
PERIOD):
Total assets..................... $1,428,904 $1,241,035 $1,558,661 $ 965,820 $ 782,921 $1,026,197 $ 696,127
Total debt(3).................... 287,704 357,198 309,055 328,313 109,300 62,728 87,200
Partners' capital(2)(4).......... 109,385 89,805 120,117 75,582 62,093 106,173 75,819
Additional partnership
interests(5)................... 9,318 2,547 2,547 21,928 12,775 9,091 9,091
OTHER FINANCIAL DATA:
Capital expenditures(6).......... 6,559 47,064 58,729 266,569 22,837 6,723 67,022
Cash distributions to
unitholders.................... 17,841 14,168 30,380 22,842 29,681 28,831 12,218
</TABLE>
---------------
(1) Includes one month of results of operations associated with the acquisition
of assets from Koch on December 1, 1998. See additional discussion in Note 4
to our audited financial statements included elsewhere herein.
(2) Includes non-recurring charges in 1997 of (i) $6.5 million impairment of an
information system development project, (ii) $1.5 million impairment of
three Ohio products terminals held for sale and (iii) $2.0 million of
severance costs related to the exit of the East of Rockies refined products
business and corporate realignment. Includes non-recurring charges in 1999
of $7.8 million of costs related to mid-continent natural gas liquids
activity and $2.0 million of severance costs for reduction of workforce. See
additional discussion in Notes 6 and 7 to our audited financial statements
included elsewhere herein.
(3) Excludes other long-term liabilities.
9
<PAGE> 14
(4) The increase in partners' capital in 1999 is due to the issuance of
3,500,000 common units to the public in September 1999. See additional
discussion in Note 8 to the our audited financial statements included
elsewhere herein.
(5) In February 1999, Enron contributed the $21.9 million additional partnership
interests to us in exchange for common units pursuant to its commitment made
in connection with the support agreement discussed in note 13 to our audited
financial statements included elsewhere herein. In May 1999, Enron provided
additional common unit distribution support through the issuance by us of
$2.5 million in additional partnership interests related to the three months
ended March 31, 1999. In February 2000, Enron provided additional common
unit distribution support through the issuance by us of $6.8 million in
additional partnership interests related to the three months ended December
31, 1999.
(6) Includes $52.6 million in 1995 for the purchase of crude gathering and
pipeline assets in Mississippi and Alabama. Includes $12.0 million in 1997
for the purchase of crude gathering and pipeline assets in Arkansas,
Louisiana and Texas. Includes $258.1 million in 1998 for the purchase of
crude oil gathering and transportation assets in multiple states. The six
months ended June 30, 1999 included $33.0 million for the purchase of
pipeline assets in West Texas and New Mexico. Includes $38.4 million in 1999
for the purchase of crude oil transportation and storage assets in New
Mexico and Texas. See additional discussion in Note 4 to our audited
financial statements included elsewhere herein.
(7) The net loss for 1995 includes a loss from discontinued operations of
$65,838 ($3.79 per unit) resulting from EOTT's decision to exit the West
Coast processing and asphalt business and an extraordinary loss of $1,315
($0.08 per unit) from the termination of a credit facility.
10
<PAGE> 15
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Through our affiliated limited partnerships, EOTT Energy Operating Limited
Partnership, EOTT Energy Canada Limited Partnership, and EOTT Energy Pipeline
Limited Partnership, we purchase, gather, transport, store and resell crude oil
and other petroleum products. Our principal business segments are North American
Crude Oil -- East of Rockies, Pipeline Operations and West Coast Operations (see
the notes to our financial statements for certain financial information by
business segment).
Gathering and Marketing Operations
In general, as we purchase crude oil in our gathering and marketing
operations, we establish a margin by selling crude oil for physical delivery to
third party users, such as independent refiners or major oil companies, or by
entering into a future delivery obligation with respect to futures contracts on
the NYMEX, thereby minimizing or reducing exposure to price fluctuations.
Through these transactions, we seek to maintain positions that are substantially
balanced between crude oil purchases and sales or future delivery obligations.
As a result, changes in the absolute price level for crude oil do not
necessarily impact the margin from gathering and marketing.
Although we generally maintain a balanced position in terms of overall
volumes, some risks cannot be fully hedged, such as a portion of certain basis
risks. Basis risk arises when crude oil is acquired by a purchase or exchange
that does not meet the specifications of the crude oil we are contractually
obligated to deliver, whether in terms of geographic location, grade or delivery
schedule. We seek to limit price risk and maintain margins through a combination
of physical sales, NYMEX hedging activities and exchanges of crude oil with
third parties. It is our policy not to acquire and hold crude oil, futures
contracts or other derivative products for the purpose of speculating on crude
oil price changes.
Our operating results are sensitive to a number of factors including:
grades or types of crude oil, individual refinery demand for specific grades of
crude oil, area market price structures for the different grades of crude oil,
location of customers, availability of transportation facilities, and timing and
costs (including storage) involved in delivering crude oil to the appropriate
customer.
Gross margin from gathering, marketing and pipeline operations varies from
period-to-period, depending to a significant extent upon changes in the supply
and demand of crude oil and the resulting changes in United States crude oil
inventory levels. The gross margin from gathering and marketing operations is
generated by the difference between the price of crude oil at the point of
purchase and the price of crude oil at the point of sale, minus the associated
costs of gathering and transportation. In addition to purchasing crude oil at
the wellhead, we purchase crude oil in bulk at major pipeline terminal points
and major marketing points and enter into exchange transactions with third
parties. These bulk and exchange transactions are characterized by large volumes
and narrow profit margins on purchase and sales transactions, and the absolute
price levels for crude oil do not necessarily bear a relationship to gross
margin, although such price levels significantly impact revenues and cost of
sales. Because period-to-period variations in revenues and cost of sales are not
generally meaningful in analyzing the variation in gross margin for gathering
and marketing operations, such changes are not addressed in the following
discussion.
We operate the business differently as market conditions change. During
periods when the demand for crude oil is weak, the market for crude oil is often
in contango, meaning that the price of crude oil in a given month is less than
the price of crude oil in a subsequent month. In a contango market, storing
crude oil is favorable, because storage owners at major trading locations can
simultaneously purchase production at low current prices for storage and sell at
higher prices for future delivery. When there is a higher demand than supply of
crude oil in the near term, the market is backwardated, meaning that the price
of crude oil in a given month exceeds the price of crude oil in a subsequent
month. A backwardated market has a positive impact on marketing margins because
crude oil gatherers can capture a premium for prompt deliveries.
11
<PAGE> 16
Pipeline Operations
Pipeline revenues and gross margins are primarily a function of the level
of throughput and storage activity and are generated by the difference between
the regulated published tariff and the fixed and variable costs of operating the
pipeline. A majority of the pipeline revenues are generated by transporting
crude oil at published pipeline tariffs for the North American Crude Oil -- East
of Rockies business segment. Approximately 76.2% of the tariff revenues of the
Pipeline Operations business segment for the six months ended June 30, 2000,
were generated from tariffs charged to the North American Crude Oil -- East of
Rockies business segment. Changes in revenues and pipeline operating costs,
therefore, are relevant to the analysis of financial results of the Pipeline
Operations business segment and are addressed in the following discussions of
the Pipeline Operations business segment.
The following review of the results of operations and financial condition
should be read in conjunction with our financial statements and notes thereto
included elsewhere herein.
Results of Operations
We reported net income of $4.9 million or $0.17 per diluted unit for the
second quarter of 2000 compared to net income of $2.2 million or $0.09 per
diluted unit for the second quarter of 1999. Excluding the impact of
mark-to-market accounting for certain energy contracts, net income for the
second quarter of 2000 was $4.8 million or $0.17 per diluted unit, compared to
net income of $1.1 million, or $0.05 per diluted unit in the same period last
year. Results for the second quarter of 2000 include $2.5 million of
nonrecurring income resulting from an insurance settlement related to the theft
of natural gas liquids product in 1999, offset by nonrecurring charges of $1.0
million related to severance charges for a former officer. The second quarter
2000 results exclusive of nonrecurring items primarily reflect an increase in
operating income revenues from the Pipeline Operations segment associated with
the acquisition of assets from Texas-New Mexico Pipeline Company, combined with
improved crude oil market conditions in North American Crude Oil -- East of the
Rockies segment. These increases were partially offset by reduced margins in
West Coast Operations and increased operating and interest costs.
We reported a net loss of $0.5 million or $0.02 per diluted unit for 1999,
a net loss of $4.1 million or $0.21 per diluted unit for 1998, and a net loss of
$14.4 million or $0.75 per diluted unit for 1997. We reported net income of $9.3
million or $0.37 per diluted unit in 1999 excluding nonrecurring charges of $9.8
million or $0.39 per diluted unit, which consisted primarily of a $6.2 million
charge for the apparent theft of natural gas liquids product, concealment of
commercial activities and other unauthorized actions by a former employee, $1.6
million related to incremental costs to terminate contracts prior to maturity
during the wind down of the mid-continent natural gas liquids activity, and a $2
million severance charge for recent workforce reductions. We reported a net loss
of $4.4 million or $0.23 per diluted unit in 1997, excluding nonrecurring
charges of $10.0 million or $0.52 per diluted unit, which consisted primarily of
a $6.5 million impairment of an information systems development project, a $1.5
million impairment of three Ohio products terminals held for sale and a $2
million severance charge associated with the realignment initiatives discussed
further in the notes to our audited financial statements included elsewhere
herein. The adoption of Issue 98-10 in the first quarter of 1999 included a $1.7
million cumulative effect as of January 1, 1999 and approximately $5.6 million
of net unrealized mark-to-market losses (which includes the $6.2 million charge
related to the unauthorized natural gas liquids activities) for the twelve
months ended December 31, 1999.
12
<PAGE> 17
Selected financial data for our business segments are summarized below, in
millions:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
------------------- ------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Revenues:
N.A. Crude Oil -- East of
Rockies....................... $4,827.2 $3,454.3 $8,042.8 $4,637.8 $6,072.6
Pipeline Operations.............. 68.1 52.6 118.5 31.5 19.4
West Coast Operations............ 360.2 273.8 654.0 590.1 811.2
Corporate and Other(1)........... -- -- -- 110.7 760.2
Intersegment eliminations........ (58.9) (88.2) (150.9) (75.4) (17.3)
-------- -------- -------- -------- --------
Total.................... $5,196.6 $3,692.5 $8,664.4 $5,294.7 $7,646.1
======== ======== ======== ======== ========
Gross margin:
N.A. Crude Oil -- East of
Rockies(2).................... $ 40.3 $ 42.0 $ 78.2 $ 92.0 $ 82.6
Pipeline Operations.............. 69.1 52.0 115.7 30.9 19.5
West Coast Operations............ 9.7 14.5 18.4 9.7 9.3
Corporate and Other(1)........... -- -- -- -- 1.6
-------- -------- -------- -------- --------
Total.................... $ 119.1 $ 108.5 $ 212.3 $ 132.6 $ 113.0
======== ======== ======== ======== ========
Operating Income (Loss):
N.A. Crude Oil -- East of
Rockies(2).................... $ 1.3 $ 1.0 $ (2.5) $ 28.0 $ 19.5
Pipeline Operations.............. 34.6 24.3 51.0 4.3 1.8
West Coast Operations............ (1.5) 4.4 (2.2) 0.2 0.1
Corporate and Other(1)........... (10.9) (12.5) (20.3) (25.3) (29.0)
-------- -------- -------- -------- --------
Total.................... $ 23.5 $ 17.2 $ 26.0 $ 7.2 $ (7.6)
======== ======== ======== ======== ========
</TABLE>
---------------
(1) 1998 and 1997 results include the East of Rockies refined products business,
which was exited in 1997.
(2) Includes intersegment transportation costs from the Pipeline Operations
segment for the transport of crude oil at published pipeline tariffs.
Intersegment transportation costs from the Pipeline Operations segment were
$53.2 million and $42.5 million for the six months ended June 30, 2000 and
1999, respectively, and they were $89.9 million, $24.5 million and $13.7
million for the twelve months ended December 31, 1999, 1998 and 1997,
respectively.
The North American Crude Oil -- East of Rockies business segment and West
Coast Operations business segment are characterized by generally very thin and
volatile profit margins on purchase and sale transactions, and the absolute
price levels for crude oil and other petroleum products do not necessarily bear
a direct relationship to margins per barrel, although such price levels
significantly impact revenues and cost of sales. Gross margin is the difference
between the sales price of crude oil or other petroleum products and the cost of
crude oil and products purchased, including costs paid to third parties for
transportation and handling charges. As a result, period-to-period variations in
revenues and cost of sales are not meaningful, and therefore are not discussed
for the North American Crude Oil -- East of Rockies and West Coast Operations
business segments. Pipeline Operations revenues are primarily a function of the
level of crude oil transported through the pipeline, known as throughput, and
the applicable pipeline tariffs.
Six Months Ended June 30, 2000 Compared with Six Months Ended June 30,
1999.
North American Crude Oil -- East of Rockies: The North American Crude Oil
-- East of Rockies segment had operating income of $1.3 million for the first
half of 2000, compared to operating income of $1.0 million for the same period
in 1999. Excluding the impact of mark-to-market accounting for certain
13
<PAGE> 18
energy contracts, the North American Crude Oil -- East of Rockies segment had
operating income of $3.7 million in the first half of 2000 compared to an
operating loss $1.7 million for the same period in 1999. Gross margin decreased
$1.7 million to $40.3 million in the first half of 2000 due primarily to
unrealized mark-to-market losses being recorded in the first half for certain
energy contracts. Crude oil lease volumes averaged 412,800 barrels per day for
the six months ended June 30, 2000 compared to an average of 412,900 barrels per
day for the six months ended June 30, 1999. Operating expenses of $39.0 million
for the first half 2000 were $2.0 million lower than in the first half of 1999
due primarily to lower employee related costs partially offset by higher
operating costs.
Pipeline Operations: Pipeline Operations had operating income of $34.6
million for the first half of 2000 compared to operating income of $24.3 million
for the same period in 1999. Revenues for the first half of 2000 increased $15.5
million to $68.1 million due primarily to increased activity related to the
acquisition of pipelines from Texas-New Mexico Pipeline Company in May 1999.
Approximately $53.2 million and $42.5 million of revenues for the six months
ended June 30, 2000 and 1999, respectively, were generated from tariffs charged
to the North American Crude Oil -- East of Rockies segment. Pipeline volumes
averaged 592,600 barrels per day for the six months ended June 30, 2000 compared
to 448,000 barrels per day for the six months ended June 30, 1999. Operating
expenses of $34.5 million for the first half of 2000 were $6.8 million higher
than in the first half of 1999 due to higher employee related costs, operating
costs and depreciation associated with the acquisition of assets from Texas-New
Mexico Pipeline Company.
West Coast Operations: West Coast Operations had an operating loss of $1.5
million for the first half of 2000, compared to operating income of $4.4 million
for the same period in 1999 primarily due to lower margins associated with the
crude oil blending operations primarily as a result of increasing competitive
pressures, offset by $2.5 million of nonrecurring cash received in the second
quarter of 2000 in connection with an insurance claim filed by EOTT related to
the theft of natural gas liquids product by a former employee. Operating
expenses of $11.2 million for the first half of 2000 were $1.1 million higher
than in the first half of 1999 due to higher operating costs partially offset by
lower employee related costs.
Corporate and Other: Corporate and Other costs were $10.9 million for the
first half of 2000 compared to $12.5 million in the first half of 1999. The
decrease is due primarily to lower system operating costs and insurance costs
partially offset by nonrecurring severance charges related to a former officer.
Interest and related charges in the first half of 2000 were $15.3 million
compared to $13.8 million for the same period in 1999. The increase is due
primarily to higher interest rates on borrowings for the financing of the
acquisitions of assets from Koch and Texas-New Mexico Pipeline Company. Other
income (expense), net, consisting primarily of discount fees on the sale of
receivables, gains (losses) on transactions denominated in foreign currency and
gains (losses) on sales of fixed assets, was an expense of $1.7 million in the
first half 2000 compared to income of $1.0 million for the same period in 1999
primarily due to discount fees on the sale of receivables.
Twelve Months Ended December 31, 1999 Compared with Twelve Months Ended
December 31, 1998
North American Crude Oil -- East of Rockies. The North American Crude
Oil -- East of Rockies segment had an operating loss of $2.5 million in 1999
compared to operating income of $28.0 million in 1998. As a result of the
acquisition of assets from Koch, the North American Crude Oil -- East of Rockies
segment is incurring increased transportation costs from the Pipeline Operations
segment due to the significant increase in the volume of crude oil transported
at higher published tariff rates as well as incurring additional operating costs
associated with the asset acquisitions. Intersegment transportation costs
charged by the Pipeline Operations segment were $89.9 million and $24.5 million
for the years ended December 31, 1999 and 1998, respectively. Gross margin
decreased $13.8 million to $78.2 million due primarily to increased
transportation costs or tariffs paid to the Pipeline Operations segment. Lease
crude oil purchases were up significantly from an annual average of 285,600 bpd
for 1998 to an annual average of 408,800 bpd in 1999 due to the acquisition of
assets from Koch. Operating expenses of $80.7 million for 1999 were $16.7
million higher than 1998 due primarily to higher operating costs and employee
related costs associated with the acquisition of assets from Koch in December
1998.
14
<PAGE> 19
Pipeline Operations. Pipeline Operations had operating income of $51.0
million in 1999 compared to $4.3 million in 1998. Revenues, which include eight
months of activity related to the asset acquisition from Texas-New Mexico
Pipeline Company in 1999, increased $87.0 million to $118.5 million in 1999 due
primarily to increased activity related to the acquisitions of pipelines from
Koch and Texas-New Mexico Pipeline Company. Approximately $89.9 million or 76%
and $24.5 million or 78% of revenues for the years ended December 31, 1999 and
1998, respectively, were generated from tariffs charged to the North American
Crude Oil -- East of Rockies segment. Pipeline volumes were 513,700 bpd in 1999
compared to 188,300 bpd in 1998. Operating expenses of $64.7 million in 1999
were $38.1 million higher than 1998 due primarily to higher employee related
costs, operating costs and depreciation associated with the acquisitions of
assets from Koch and Texas-New Mexico Pipeline Company.
West Coast Operations. West Coast Operations had an operating loss of $2.2
million in 1999 compared to operating income of $0.2 million in 1998. Excluding
nonrecurring charges of $7.8 million for 1999, West Coast Operations had
operating income of $5.6 million. Nonrecurring charges reflect a $6.2 million
charge for the apparent theft of natural gas liquids product, concealment of
commercial activities and other unauthorized actions by a former employee and
$1.6 million related to incremental costs to terminate contracts prior to their
maturity in winding down the mid-continent natural gas liquids activity. The
mid-continent natural gas liquids activity originally served as a supply source
for the West Coast crude oil blending operations prior to the acquisition of
assets from Koch. Gross margin increased $8.7 million to $18.4 million due
primarily to the acquisition of crude oil gathering and natural gas liquid
assets from Koch. Operating expenses of $20.6 million in 1999 were $11.1 million
higher than in 1998 due primarily to higher employee related costs, operating
costs and depreciation with the acquisition of assets from Koch.
Corporate and Other. Corporate and other costs of $20.3 million for 1999
were $5.0 million lower compared to 1998, due primarily to a $1.0 million
write-off of certain information system development costs in 1998 and lower
severance costs in 1999. Interest and related charges for 1999 were $29.8
million compared to $10.2 million in 1998 due to the higher average debt in 1999
due to the financing of the acquisitions from Koch and Texas-New Mexico Pipeline
Company. Other income (expense), net, consisting primarily of gains on
transactions denominated in foreign currency and gains on sales of fixed assets,
increased $2.5 million to income of $0.7 million in 1999.
Twelve Months Ended December 31, 1998 Compared with Twelve Months Ended
December 31, 1997
North American Crude Oil -- East of Rockies. Operating income for the North
American Crude Oil -- East of Rockies segment was $28.0 million in 1998 compared
to $19.5 million in 1997. Gross margin increased $9.4 million to $92.0 million
due primarily to renegotiations of uneconomic lease contracts during 1997 and
improved crude grade and basis differentials in 1998. North American Crude
Oil -- East of Rockies lease crude oil purchases were up slightly from an annual
average of 282,400 bpd for 1997 to an annual average of 285,600 bpd in 1998.
Operating expenses of $64.0 million for 1998 were $0.9 million higher than 1997
due primarily to increased depreciation and amortization related to the
acquisitions of assets from Koch partially offset by a reduction in employee
related costs.
Pipeline Operations. Pipeline Operations had operating income of $4.3
million in 1998 compared to $1.8 million in 1997. Revenues increased $12.1
million to $31.5 million due primarily to increased activity related to the
acquisition of pipelines from Koch. Pipeline Operations delivered volumes were
185,300 bpd in 1998 compared to 142,000 bpd in 1997. Operating expenses of $26.6
million in 1998 were $8.9 million higher than in 1997 due primarily to increased
benefits and employee related costs, increased operating costs and incremental
depreciation and amortization associated with the acquisition of pipelines from
Koch.
West Coast Operations. West Coast Operations had operating income of $0.2
million in 1998 compared to $0.1 million in 1997. Gross margin increased $0.4
million to $9.7 million due primarily to the acquisition of crude oil gathering
and natural gas liquid assets from Koch partially offset by a lower of cost or
market adjustment of certain propane inventories. Operating expenses of $9.5
million in 1998 were
15
<PAGE> 20
$0.3 million higher than in 1997 due primarily to higher benefits and other
employee related costs partially offset by reduced operating costs.
Corporate and Other. Corporate and other costs of $25.3 million for 1998
were $3.7 million lower compared to 1997 due primarily to a non-recurring $6.5
million non-cash impairment associated with the termination of an information
system development project and $1.5 million impairment of three Ohio products
terminals held for sale due to the exit of the East of Rockies refined products
business in 1997 partially offset by increased legal expenses, system operating
costs, casualty and liability insurance costs, a non-recurring write-off of
certain information system development costs and severance payments made to a
former officer of our general partner. Interest and related charges for 1998
were $10.2 million compared to $6.7 million in 1997. The increase is due
primarily to higher average short-term debt required to meet working capital
needs, primarily related to higher average crude inventories during 1998 and
debt used to finance the acquisition of assets from Koch in the third and fourth
quarters of 1998. Other income (expense), net, consisting primarily of gains
(losses) on transactions denominated in foreign currency; gains (losses) on the
sale of property, plant and equipment; and litigation settlements decreased $1.0
million to a loss of $1.8 million in 1998 due to an increase in litigation
settlements in 1998.
LIQUIDITY AND CAPITAL RESOURCES
General
Management anticipates that short-term liquidity as well as sustaining
capital expenditures for the foreseeable future will be funded primarily by cash
generated from operations in addition to lines of credit provided by Enron and
commodity repurchase agreements. To the extent we make significant acquisitions
in the future, we may be required to seek financing from other sources. No
assurance can be given that this financing will be available from Enron or
another source. We may also issue additional limited partner interests, the
proceeds from which could be used to reduce indebtedness, provide additional
funds for acquisitions or other needs.
Cash Flows From Operating Activities
Net cash provided by operating activities totaled $29.7 million for the
first six months of 2000 compared to net cash provided by operating activities
of $26.2 million for the same period in 1999 primarily due to reduced cash
requirements related to NYMEX hedging activities.
Net cash provided by operating activities totaled $69.3 million in 1999
compared to $18.6 million in 1998 primarily due to the sale of a $50.0 million
receivable from Koch.
Cash Flows From Investing Activities
Net cash used in investing activities totaled $6.0 million for the first
six months of 2000 compared to $42.5 million for the same period in 1999. Cash
additions to property, plant, and equipment of $6.6 million in 2000 primarily
include $3.1 million for information systems hardware and software and $1.9
million for pipeline, storage tank and related facility improvements. Proceeds
from asset sales were $0.5 million in the first six months of 2000 compared to
$0.5 million in the first six months of 1999. Acquisitions of $33.0 million
during 1999 primarily reflect the purchase of assets from Texas-New Mexico
Pipeline Company.
Net cash used in investing activities totaled $53.3 million in 1999
compared to $224.7 million in 1998, primarily due to the asset acquisition from
Texas-New Mexico Pipeline Company in 1999 and the asset acquisitions from Koch
in 1998. Cash additions to property, plant, and equipment of $54.7 million in
1999 primarily include $33.0 million representing cash consideration for the
asset acquisition from Texas-New Mexico Pipeline Company, $8.8 million for
pipeline connections and improvements, and $7.2 million for computer hardware
and software. Proceeds from asset sales were $1.4 million in 1999 compared to
$7.3 million in 1998.
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<PAGE> 21
Our general partner estimates that capital expenditures necessary to
maintain the existing asset base at current operating levels will be
approximately $9 -- $11 million each year. The level of our capital expenditures
will vary depending upon prevailing energy markets, general economic conditions
and the current regulatory environment.
Cash Flows From Financing Activities
Net cash used in financing activities totaled $32.4 million for the first
six months of 2000 compared to net cash provided of $17.0 million for the same
period in 1999. The 2000 amount primarily represents a reduction of repurchase
agreements outstanding and distributions paid to all common unitholders for the
period October 1, 1999 through March 31, 2000.
Net cash used in financing activities totaled $1.5 million in 1999 compared
to net cash provided by financing activities of $205.4 million in 1998. The 1999
amount represents borrowings to fund working capital needs and acquisition
financing reduced by distributions paid to unitholders for the period October 1,
1998 through September 30, 1999. The 1998 amount primarily represents short-term
borrowings to fund working capital needs and borrowings from Enron to finance
the asset acquisitions from Koch, reduced by distributions paid to unitholders
of record for the period October 1, 1997 through September 30, 1998.
Cash distributions paid to unitholders were $30.4 million and $22.8 million
for 1999 and 1998, respectively. Due to the losses incurred during 1997, the
1997 third quarter distribution to all common and special unitholders was paid
utilizing $3.7 million in cash support from Enron. The 1997 fourth quarter
distribution was paid in February 1998 using $3.8 million in cash support from
Enron. The 1998 first and second quarter distributions were paid using $5.3
million in cash support from Enron. The 1999 first quarter distribution was paid
using $2.5 million in cash support from Enron. Pursuant to the support
agreement, as discussed in note 13 to our audited financial statements included
elsewhere herein, all additional partnership interests outstanding at December
31, 1998 were contributed to us in February 1999.
Acquisition of Assets
On July 1, 1998, we acquired crude oil gathering and transportation assets
in West Texas and New Mexico from Koch. The asset purchase included
approximately 300 miles of common carrier pipelines, associated storage
facilities for approximately 500,000 barrels and lease crude oil purchase
contracts for up to 40,000 barrels of crude oil per day. The purchase price was
approximately $28.5 million and was financed with short-term borrowings from
Enron.
On December 1, 1998, we acquired certain additional crude oil gathering and
transportation assets (the "Assets"), in key oil producing regions from Koch.
The total purchase price of the Assets was $235.6 million, which included
consideration of $184.5 million in cash, 2,000,000 common units, 2,000,000
subordinated units and $11.4 million in transaction costs. We financed the
majority of the cash purchase price through short-term borrowings from Enron.
See additional discussion regarding Enron financing in note 4 to our audited
financial statements included elsewhere herein.
On May 1, 1999, we acquired crude oil transportation and storage assets in
West Texas and New Mexico from Texas-New Mexico Pipeline Company, which included
approximately 1,800 miles of common carrier crude oil pipelines. We paid $33
million in cash and financed the acquisition using short-term borrowings from
Enron.
Working Capital and Credit Resources
On December 1, 1998, Enron increased its existing credit facility with us
to provide additional credit support in the form of guarantees, letters of
credit and working capital loans through December 31, 2001. The total amount of
the Enron facility is $1.0 billion, and it contains sublimits of $100 million
for working capital loans and $900 million for guarantees and letters of credit.
Letter of credit fees are based on actual
17
<PAGE> 22
charges by the banks which range from .20% -- .375% per annum. Interest on
outstanding loans is charged at LIBOR plus 250 basis points per annum.
The Enron facility is subject to defined borrowing base limitations
relating to our activities and to the maintenance and protection of the
collateral. The Enron facility permits distributions to unitholders subject to
certain limitations based our earnings and other factors. These covenants and
restrictions are not expected to materially affect our ability to operate our
ongoing business. The Enron facility is secured by a first priority lien on and
security interest in all of our receivables and inventory. The borrowing base is
the sum of cash and cash equivalents, specified percentages of eligible
receivables, inventory, and products contracted for or delivered but not billed.
The Enron facility is non-recourse to our general partner and the general
partner's assets. We are restricted from entering into additional financing
arrangements without the prior approval of Enron.
At December 31, 1998, we had a term loan of $175 million outstanding with
Enron under a financing arrangement to fund a portion of the cash consideration
paid to Koch for the assets purchased in 1998 and to refinance indebtedness
incurred in prior acquisitions. The term loan had a scheduled maturity of
December 31, 1999. The interest rate on the term loan was LIBOR plus 300 basis
points. As discussed further below, the term loan was repaid in the fourth
quarter of 1999 utilizing a portion of the net proceeds from the issuance of the
11% senior notes.
In addition, at December 31, 1998, we had $42 million of debt outstanding
with Enron under a $100 million bridge loan to finance a portion of the cash
consideration for the acquisition of assets from Koch. The interest rate on the
bridge loan was initially LIBOR plus 400 basis points. At the end of each
three-month period, the spread on the bridge loan increased by 25 basis points.
The bridge loan was unsecured, and its maturity date was December 31, 1999. As
discussed below, the bridge loan was repaid utilizing a portion of the net
proceeds from the issuance of 3,500,000 common units.
On September 29, 1999, we issued 3,500,000 common units to the public, with
net proceeds to us of $52.9 million. On October 1, 1999, we issued to the public
$235 million of 11% senior notes. The senior notes are due October 1, 2009, and
interest is paid semiannually on April 1 and October 1. The senior notes are
fully and unconditionally guaranteed by all of our operating limited
partnerships. On or after October 1, 2004, we may redeem the notes, and prior to
October 1, 2002, we may redeem up to 35% of the notes with proceeds of public or
private sales of equity at specified redemption prices. Provisions of the senior
notes could limit additional borrowings, sale and lease back transactions,
affiliate transactions, distributions to unitholders or merger, consolidation or
sale of assets if certain financial performance ratios are not met. The net
proceeds from the issuance of the 11% senior notes and the issuance of the
common units were used to repay the $175 million term loan from Enron, the $42
million bridge loan from Enron and $57.3 million of short-term borrowings
outstanding under the working capital facility from Enron.
At December 31, 1999, we had $143.5 million in letters of credit
outstanding under the Enron facility. In addition, guarantees outstanding
totaled $427.0 million of which $378.5 million were used.
At December 31, 1998, we had $44.4 million in letters of credit and $28.3
million in loans outstanding under the Enron facility at an average annual
interest rate of approximately 6.1%. The amount outstanding at December 31, 1998
under the term loan was $175.0 million with an average annual interest rate of
8.5%. Under the bridge loan, the amount outstanding was $42.0 million with an
average annual interest rate of 9.5%. In addition, guarantees outstanding
totaled $366.4 million of which $290.9 million were used.
Our general partner believes that the Enron facility and commodity
repurchase agreements discussed below will be sufficient to support our crude
oil purchasing activities and working capital and liquidity requirements. No
assurance, however, can be given that our general partner will not be required
to reduce or restrict our gathering and marketing activities because of
limitations on its ability to obtain credit support and financing for its
working capital needs.
Our ability to obtain letters of credit to support our purchases of crude
oil or other petroleum products is fundamental to our gathering and marketing
activities. Additionally, we have a significant need
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<PAGE> 23
for working capital due to the large dollar volume of marketing transactions in
which we engage. Any significant decrease in our financial strength, regardless
of the reason for such decrease, may increase the number of transactions
requiring letters of credit or other financial support, may make it more
difficult for us to obtain such letters of credit, and/or may increase the cost
of obtaining them. This could in turn adversely affect our ability to maintain
or increase the level of our purchasing and marketing activities or otherwise
adversely affect our profitability and available cash.
Our partnership agreement authorizes us to issue additional limited partner
interests, the proceeds from which could be used to provide additional funds for
acquisitions or other needs.
At December 31, 1999, we have outstanding forward commodity repurchase
agreements of approximately $74.1 million. Pursuant to the agreements, which had
terms of thirty days, we repurchased the crude oil inventory on January 21, 2000
for approximately $74.5 million. At December 31, 1998, we had outstanding
forward commodity repurchase agreements of approximately $83.0 million. Pursuant
to the agreements, which had terms of thirty days, we repurchased the crude oil
inventory on January 20, 1999 for approximately $83.4 million.
We have entered into an agreement with a third party that provides for the
sale of up to an aggregate amount of $100 million of certain trade receivables
outstanding at any one time. As of December 31, 1999, $50 million of receivables
had been sold under this agreement. Discount fees related to the sales are
reflected in other, net expenses. We have accounted for these transactions as a
sale under the provisions of Statement of Financial Accounting Standards No.
125, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishment of Liabilities," and the related cash received is reflected as
cash provided by operating activities in our statements of cash flows.
Generally, we will distribute 100% of our available cash within 45 days
after the end of each quarter to unitholders of record and to our general
partner. Available cash consists generally of all of our cash receipts, adjusted
for our cash distributions and net changes to reserves. The full definition of
"available cash" is set forth in our partnership agreement and amendments
thereto, forms of which have been filed as exhibits to this registration
statement. Distributions of available cash to the subordinated unitholders are
subject to the prior rights of the common unitholders to receive the minimum
quarterly distribution for each quarter during the subordination period, and to
receive any arrearages in the distribution of the minimum quarterly distribution
on the common units for prior quarters during the subordination period.
The minimum quarterly distribution is $0.475 per unit. Enron has committed
to provide total cash distribution support in an amount necessary to pay minimum
quarterly distributions, with respect to quarters ending on or before December
31, 2001, in an amount up to an aggregate of $29 million ($19.7 million of which
remains available) in exchange for additional partnership interests. See further
discussion in note 13 to our audited financial statements included elsewhere
herein regarding Enron's distribution support.
SUMMARIZED FINANCIAL INFORMATION OF THE GENERAL PARTNER
EOTT Energy Corp., an indirect wholly owned subsidiary of Enron Corp.,
serves as our general partner. Summary financial information for 1999 and 1998
is shown below, in thousands:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
-----------------
1999 1998
------- -------
<S> <C> <C>
Balance Sheet Data (at end of period)
Total assets.............................................. $52,904 $43,099
Total liabilities......................................... 3,841 1,212
Shareholder's equity...................................... 49,063 41,887
Income Statement Data:
Net income (loss)................................. $ (539) $(4,005)
</TABLE>
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<PAGE> 24
Enron Corp. is a publicly traded company listed on the New York Stock
Exchange. Financial information about Enron Corp. can be obtained from its
filings with the Securities and Exchange Commission pursuant to the Securities
Exchange Act of 1934.
YEAR 2000
A Year 2000 problem was anticipated which could have resulted from the use
in computer hardware and software of two digits rather than four digits to
define the applicable year. The use of two digits was a common practice for
decades when computer storage and processing was much more expensive than today.
When computer systems must process dates both before and after January 1, 2000,
two-digit year "fields" may create processing ambiguities that can cause errors
and system failures. For example, computer programs that have date-sensitive
features may recognize a date represented by "00" as the year 1900, instead of
2000.
The Year 2000 problem has caused no material disruption to our
mission-critical facilities or operations, and resulted in no material costs. We
will remain vigilant for Year 2000 related problems that may yet occur due to
hidden defects in our computer hardware or software or at our mission-critical
external entities. We anticipate that the Year 2000 problem will not create
material disruptions to its mission-critical facilities or operations, and will
not create material costs.
OTHER MATTERS
During the first quarter of 2000, we identified certain systems integration
issues relating to our new computerized marketing and accounting system, and we
immediately commenced an extensive review and analysis of the implementation of
the new system. As a result of these efforts, we identified and quantified the
impacts of the systems integration issues relating to our new computerized
marketing and accounting system and recorded appropriate financial statement
adjustment in the first quarter of 2000. We have implemented and continue to
implement additional control processes and procedures that we believe are
sufficient to permit the preparation of timely and accurate financial
information, including additional preventative and monitoring controls to ensure
the integrity and reliability of financial information generated by the system
as well as additional system training for users.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities". The Statement establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. The
Statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and requires
that a company must formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting. SFAS No. 133, as amended, is
effective for fiscal years beginning after June 15, 2000. The standard cannot be
applied retroactively, but early adoption is permitted. We have not yet
determined the impact of adopting SFAS No. 133; however, this standard could
increase volatility in earnings and partners' capital, through other
comprehensive income.
We have been engaged in discussions with Koch Petroleum Group, L.P. (Koch)
to modify a 15-year contract, which began December 1, 1998, to supply crude oil
to Koch at market based prices. The contract specifies that either party may
require that the other party renegotiate the contract if certain changes in
market conditions or other changes occur. Although we believe that this matter
will be satisfactorily resolved with Koch, we can give no assurance regarding
the outcome of these discussions with Koch or the potential impact of this
long-term contract on our future operating results.
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<PAGE> 25
OUTLOOK
We will continue to pursue attractive acquisition or business combination
opportunities to increase the scale of our business, add cash flow, and reduce
earnings variability. Acquisitions that result in increased lease purchase
volumes should help to enhance our gathering and marketing opportunities. Our
management is committed to continually improving internal business processes in
all operational, marketing, and administrative areas and thereby achieve
improvements in productivity.
Results from operations in the second quarter of 2000 for the North
American Crude Oil -- East of Rockies business continued to be favorable and
management anticipates that market conditions in the last half of 2000 will be
comparable to the first six months of 2000 if crude oil prices remain strong. In
addition, gross margins in the first half of 2000 for the West Coast Operations
were lower when compared to the first six months of 1999 as a result of
increasing competitive conditions. These competitive conditions may continue to
put pressure on gross margins for the West Coast Operations for the remainder of
2000.
Historically, the crude oil gathering and marketing business has been very
competitive with thin and variable profit margins. Market conditions and the
amount of crude oil produced cannot be projected with certainty. We intend to
continue to pay minimum quarterly distributions to all our common unitholders.
We paid second quarter distributions to all our common unitholders on August 14,
2000 without any distribution support from Enron; however, due to the changing
market conditions which affects operating results, it is possible that
distribution support from Enron may be needed to pay minimum quarterly
distributions in the future. Enron has committed to provide total cash
distribution support in an amount necessary to pay minimum quarterly
distributions up to $29 million ($19.7 million of which remains available)
through the fourth quarter 2001, which should further assure common unitholders
of continued reliable distributions.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We enter into forwards, futures and other contracts primarily for the
purpose of hedging the impact of market fluctuations on assets, liabilities or
other contractual commitments. The use of financial instruments may expose us to
market and credit risks resulting from adverse changes in commodity prices,
interest rates and foreign exchange rates. The major market risks are discussed
below.
Commodity Price Risk. Commodity price risk is a consequence of gathering
crude oil at the lease and marketing the crude oil to refineries or other trade
partners. We use forwards, futures, swaps and options to mitigate price exposure
and manage this risk on a portfolio basis.
Interest Rate Risk. Interest rate risk is the result of having variable
rate debt obligations, as changing interest rates impact the discounted value of
future cash flows.
Foreign Currency Exchange Rate Risk. Foreign currency exchange rate risk is
the result of our Canadian operations. The primary purpose of our foreign
currency hedging activities is to protect against the volatility associated with
foreign currency purchase and sale transactions.
COMMODITY PRICE AND FOREIGN CURRENCY RISK
We have performed a value at risk analysis of virtually all of our
financial assets and liabilities. Value at risk incorporates numerous variables
that could impact the fair value of our investments, including commodity prices
and foreign exchange rates, as well as correlation within and across these
variables. We estimate value at risk commodity and foreign exchange exposures
using a model based on Monte Carlo simulation of delta/gamma positions which
captures a significant portion of the exposure related to open futures
contracts. The value at risk method utilizes a one-day holding period and a 95%
confidence level. Cross-commodity correlations are used as appropriate. The use
of the value at risk model allows management to aggregate risks, compare risk on
a consistent basis and identify the drivers of risk.
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<PAGE> 26
The following table illustrates the value at risk for commodity price and
foreign currency risk (in millions):
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
-------------
1999 1998
----- ----
<S> <C> <C>
Commodity price(1).......................................... $(1.5) $3.8
Foreign currency exchange rate.............................. $ -- $ --
</TABLE>
---------------
(1) The above value at risk amount represents derivative commodity instruments,
primarily commodity futures contracts, entered into to hedge future physical
crude oil purchase commitments. The commitments to purchase physical crude
oil have not been included in the above value at risk computation.
INTEREST RATE RISK
Our exposure to changes in interest rates primarily results from our
short-term and long-term debt with both fixed and floating interest rates. The
Enron facility has a maturity of December 2001: however, the borrowings under
the facility are for working capital and are classified as short-term
obligations. If the borrowings were held to maturity, the average interest rates
would be LIBOR plus 250 basis points. At December 31, 1999, no amounts were
outstanding under the Enron facility. In October 1999, we issued $235 million of
11% senior notes due in 2009. At year-end the fair value of these notes
approximated the carrying value.
Accounting Policies
Accounting policies for price risk management and hedging activities are
described in note 2 to our audited financial statements included elsewhere
herein.
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<PAGE> 27
BUSINESS
GENERAL
We are engaged in the purchasing, gathering, transporting, trading, storage
and resale of crude oil, refined petroleum products, natural gas liquids and
related activities through our affiliated limited partnerships, EOTT Energy
Operating Limited Partnership, EOTT Energy Canada Limited Partnership, and EOTT
Energy Pipeline Limited Partnership. We have three principal business segments:
North American -- East of Rockies crude oil gathering and marketing operations;
Pipeline Operations; and West Coast Operations, which includes crude oil
gathering and marketing, refined products marketing and a natural gas liquids
business.
In 1999, we formed EOTT Energy Finance Corp. as a direct wholly-owned
subsidiary. This entity was set up before our debt offering to facilitate
investors' ability to purchase our senior notes.
EOTT Energy Corp., a Delaware corporation and an indirect wholly-owned
subsidiary of Enron Corp., serves as our sole general partner. In addition to
owning approximately 2% of our general partner interests, our general partner
owns approximately 25% of our limited partner interests in the form of
subordinated units. Enron, through its ownership of our common units, holds an
approximate 12% interest in our partnership.
OVERVIEW
We are one of the largest independent crude oil gathering and marketing
companies in North America. We gather and market from over 40,000 oil wells in
18 states and Canada, averaging 428,700 barrels per day during 1999. In
addition, we are engaged in interstate and intrastate crude oil transportation,
crude oil terminalling and storage activities, and crude oil blending. Most of
the crude oil we purchase directly from the oil well, which we call "lease crude
oil," is delivered to refiners and other customers nationwide. We transport
crude oil through pipelines, including approximately 8,300 miles of our pipeline
and gathering systems, and trucking operations, which includes a fleet of 259
owned or leased trucks.
We engage in the following business activities:
- GATHERING AND MARKETING. We gather, store and transport crude oil in the
United States and Canada. This involves purchasing and gathering crude
oil from producers and other sellers for subsequent sale to refiners and
other customers. We gather crude oil from over 6,000 producers and
operators, of which approximately 89% of the volumes are from independent
producers and the remaining 11% are from major integrated oil companies.
We also provide certain accounting and administrative services to some
producers and operators. We believe that our ability to offer reliable
and reasonably priced services to producers and operators is a key factor
in maintaining lease crude oil volumes and in obtaining new lease
volumes. Most of these operations are included in the North American
Crude Oil -- East of Rockies business segment.
- PIPELINE OPERATIONS. Through our common carrier pipeline systems, we
transport crude oil for our gathering and marketing operations and for
third parties pursuant to published tariff rates regulated by the Federal
Energy Regulatory Commission and state regulatory authorities. We
transported 513,700 barrels per day in 1999, a significant portion of
which was transported for our own gathering and marketing operations. We
conduct these operations in our Pipeline Operations business segment.
Approximately 76% of the revenues of the Pipeline Operations business
segment for the twelve months ended December 31, 1999, were generated
from tariffs charged to the North American Crude Oil -- East of Rockies
business segment.
- CRUDE OIL BLENDING AND NATURAL GAS LIQUIDS PROCESSING. We blend West
Coast sour crude with sweet crude oil and natural gas liquids to upgrade
heavy sour crude oil into a medium gravity Alaskan North Slope type of
crude oil, which is sold to Los Angeles Basin refineries. In addition, we
have a gas processing plant, a fractionation plant, and refrigerated
propane storage and related
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<PAGE> 28
distribution facilities, which provide natural gas liquids to our crude
oil blending operation as well as other services for the natural gas
liquids operations. We conduct these operations in our West Coast
Operations business segment.
We operate gathering systems in all major production areas in the lower 48
states. The 18 states in which we gather have represented, on average,
approximately 97% of the production in the lower 48 states from 1985 to 1997,
according to the most recent data available from the American Petroleum
Institute. These states have had a historical average annual oil production
decline rate of 2.6% over the same period; however, this may not necessarily
represent the decline rates in the particular fields from which we gather crude
oil.
NORTH AMERICAN CRUDE OIL -- EAST OF ROCKIES OPERATIONS
Our crude oil gathering and marketing operations consist of purchasing and
gathering crude oil from producers and operators for subsequent sale to refiners
and other customers. Our gathering activities are conducted in the 18 states
which represent approximately 97% of the crude oil production in the lower 48
states. Gathering and marketing of crude oil consists of:
- purchasing lease crude oil from producers and operators at the oil well
and in bulk from aggregators at major pipeline interconnects and
marketing locations,
- transporting crude oil on our own proprietary or common carrier
pipelines, through our fleet of trucks or on assets owned and operated by
third parties,
- buying and selling crude oil or exchanging it for either another grade of
crude oil or for crude oil at a different geographic location in order to
increase margins or meet contract delivery requirements, and
- marketing crude oil to refiners, large integrated oil companies and other
customers.
As a gatherer and marketer, we seek to earn profits primarily by buying
crude oil at competitive prices, efficiently transporting and handling the
purchased crude oil and marketing the crude oil to refinery customers or other
trade partners. We purchase and sell crude oil primarily under contracts with
30-day renewable terms, with some contracts having terms from two months to one
year. In addition, in December of 1998, we entered into a 15-year supply
contract at market-based prices with Koch Oil Company for less than 25% of our
lease crude oil volumes.
Crude Oil Gathering
In a typical producer's operation, crude oil flows from the oil well to a
separator where the petroleum gases are removed. After separation, the crude oil
is treated to remove water, sand and other contaminants and is then moved into
the producer's on-site storage tanks. When the tank is full, the producer
contacts our field personnel to purchase and transport the crude oil to market.
We utilize our pipelines and trucks to transport most of the crude oil purchased
to market.
We engage in several types of purchases, sales and exchanges of crude oil.
Most transactions we enter into are at market responsive prices for a term or
duration of 90 days or less, with a large number of transactions on a 30-day
renewable basis. These purchases are automatically renewable on a month-to-
month basis until terminated by either party. The purchases are typically based
on our posted prices, or the price at which we are willing to pay producers in a
particular region, plus a bonus. The bonus is determined based on grade of oil,
transportation costs and competitive factors. Both the posted price and the
bonus change in response to market conditions. Posted prices can change daily,
and bonuses, in general, can change every 30 days as contracts renew. Conducting
business under these short-term contracts with multiple producers helps us
reduce the overall basis risk and variability in the crude oil gathering and
marketing business. See "Business -- Risk Management Services/Derivatives."
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<PAGE> 29
The North American Crude Oil -- East of Rockies operation is organized into
seven operating regions. Of the 428,700 barrels per day of lease crude oil we
purchased in 1999, approximately 408,800 barrels per day or 95% was gathered in
the North American Crude Oil -- East of Rockies business segment. The remainder
of the lease crude oil was gathered in the West Coast region.
Crude Oil Marketing
The marketing of crude oil is complex and requires detailed knowledge of
the crude oil market and a familiarity with a number of factors including: types
of crude oil, individual refinery demand for specific grades of crude oil, area
market price structures for the different grades of crude oil, location of
customers, availability of transportation facilities and timing and costs
(including storage) involved in delivering crude oil to the appropriate
customer. We market crude oil through our extensive gathering and marketing
asset base which allows us to select among several transportation, storage and
delivery alternatives.
Generally, as we purchase lease crude oil, we enter into corresponding sale
transactions involving physical deliveries of crude oil to third party users,
such as independent refineries, or corresponding sales of futures contracts on
the NYMEX. This process enables us to hedge against price fluctuations until we
make physical delivery of the crude oil. After purchase of a lease barrel, we
may re-market that barrel both in the futures and physical markets in order to
maximize the value of the lease crude oil volumes. Throughout the process, we
seek to maintain a substantially balanced position at all times with respect to
lease volumes; however, we have certain risks which cannot be completely hedged
such as basis risks (the risk that price relationships between delivery points,
grades of crude oil or delivery periods will change) and the risk that
transportation costs will change. It is our policy not to hold any inventory for
the purpose of speculating on price changes.
Market conditions have a direct effect on our marketing strategy. During
periods when the demand for crude oil is weak, the market for crude oil is often
in contango, meaning that the price of crude oil in a given month is less than
the price of crude oil in a subsequent month. In a contango market, storing
crude oil is favorable, because storage owners at major trading locations can
simultaneously purchase production at low current prices for storage and sell at
higher prices for future delivery. When there is a higher demand than supply of
crude oil in the near term, the market is backwardated, meaning that the price
of crude oil in a given month exceeds the price of crude oil in a subsequent
month. A backwardated market has a positive impact on marketing margins because
crude oil gatherers can capture a premium for prompt deliveries.
Producer Services
Purchasing crude oil from producers and operators is done on the basis of
competitive pricing and reliable and responsive customer service. We believe our
ability to offer enhanced customer services to producers and operators is an
important factor in maintaining lease crude oil volumes and in obtaining new
volumes. Services offered include gathering capabilities, timely pickup of crude
oil from producers' tanks at the lease or production point, accurate measurement
of crude oil volumes delivered, and certain accounting and administrative
services. Accounting and administrative services include processing division
orders (dividing payments among the several owners of interests in a lease),
providing statements of the crude oil purchased by us each month, disbursing
production proceeds to interest owners and calculation and payment of severance
and production taxes on behalf of interest owners. In order to compete
effectively, we must efficiently handle title and division order issues and
payment and regulatory reporting of all severance and production taxes. We must
do this in a professional and timely manner, thereby ensuring the prompt and
correct processing or payment of crude oil production proceeds and taxes. These
producer services will continue to be a key component in our strategy as the
smaller producers find it difficult to maintain these services internally.
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PIPELINE OPERATIONS
Our pipeline operations provide the vital link between our crude oil
purchasing and marketing activities. We own and operate approximately 8,300
miles of crude oil gathering and transmission pipelines covering thirteen
states, including approximately 7,400 miles of regulated intrastate and
interstate common carrier pipeline systems. There are approximately 15.1 million
barrels of storage capacity associated with field tanks. By state, the pipeline
assets are as follows:
<TABLE>
<CAPTION>
EOTT COMMON CARRIER PIPELINE MILES BY STATE EOTT PROPRIETARY PIPELINE MILES BY STATE
-------------------------------------------- --------------------------------------------
MILES MILES
----- -----
<S> <C> <C> <C>
Alabama.............................. 56 Alabama.............................. 38
Arkansas............................. -- Arkansas............................. 2
California........................... 16 California........................... 159
Colorado............................. 332 Colorado............................. --
Kansas............................... 795 Kansas............................... --
Louisiana............................ 412 Louisiana............................ 131
Mississippi.......................... 293 Mississippi.......................... 267
Montana.............................. 118 Montana.............................. --
Nebraska............................. 56 Nebraska............................. --
New Mexico........................... 1,174 New Mexico........................... 158
North Dakota......................... 489 North Dakota......................... --
Oklahoma............................. 1,389 Oklahoma............................. 33
Texas................................ 2,256 Texas................................ 82
----- ---
Total...................... 7,386 Total................................ 870
===== ===
</TABLE>
Through these pipeline systems, we transport crude oil for the North
American Crude Oil -- East of Rockies and West Coast business segments and third
party customers pursuant to published tariff rates regulated by the Federal
Energy Regulatory Commission and state regulatory authorities. Accordingly, we
offer transportation services to any shipper of crude oil, provided that the
crude oil meets the conditions and specifications contained in the applicable
pipeline tariff. During 1999, our pipeline operations transported approximately
513,700 barrels per day through our regulated pipeline systems. Pipeline
revenues are primarily a function of the level of crude oil transported through
the pipeline, known as throughput, and the applicable pipeline tariffs.
Approximately 76% of the revenues from the Pipeline Operations business segment
for the twelve months ended December 31, 1999, were generated from tariffs
charged to the North American Crude Oil -- East of Rockies business segment. The
operating income from the Pipeline Operations business segment is generated by
the difference between the published tariff and the fixed and variable costs of
operating the pipelines.
We believe that pipelines provide the lowest-cost method of transportation,
and accordingly, we have focused on increasing the percentage of barrels
transported on pipelines through acquisitions of pipeline assets. Our extensive
pipeline network allows us to be the low-cost operator in many of the regions in
which we operate. In addition, we have the opportunity to add incremental cash
flow at marginal additional cost given that our pipeline system operates at
approximately two-thirds of capacity.
WEST COAST OPERATIONS
We conduct a number of business activities in the petroleum market on the
West Coast, including the following: (i) crude oil blending; (ii) lease crude
oil gathering and marketing; (iii) natural gas liquids marketing; and (iv)
refined petroleum products marketing. These business activities are operated as
an integrated business, with the lease crude oil and gas fractionation
operations being the primary components in the crude oil blending operations.
We acquired assets from Koch in 1998 that improved the transportation
economics of the blending and marketing activities and greatly expanded the
existing natural gas liquids marketing business on the
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West Coast. These assets primarily included a gas processing plant with 20
million cubic feet per day of gas processing capacity, a fractionation plant
with 8,000 barrels per day of fractionation capacity and five million gallons of
refrigerated propane storage along with related distribution facilities.
The primary function of lease crude oil gathering on the West Coast is to
support the crude blending operation. We purchase crude oil from a number of
producers on the West Coast, ranging from small independents to major oil
companies. The West Coast lease crude oil volumes are transported by a variety
of pipeline gathering systems as well as by truck, either owned by us or through
third parties.
The acquisition of the fractionation plant from Koch has given us the
ability to produce natural gasoline, which is a valuable component of the crude
blending operation. The fractionator and the associated five million gallon
refrigerated storage facility have also turned us into a major participant in
the wholesale marketing of propane on the West Coast.
The bulk of our profitability in the West Coast market is derived from
crude oil blending. The margins for the West Coast crude oil business are
primarily tied to our ability to upgrade heavy sour crude into a medium gravity,
Alaskan North Slope type of crude oil, called Line 63. To accomplish this, we
gather crude oil by truck and pipeline and deliver it to proprietary blend
stations strategically placed along our gathering system.
In addition, the West Coast Operations include a refined petroleum products
marketing business. This business specializes mostly in marketing distillate and
gasoline at terminals located between Seattle and San Diego.
PROPERTIES
At year end 1999, we owned and operated 8,300 miles of active crude oil
gathering and transmission pipelines, including the assets acquired from Koch
Pipeline Company, L.P. and Texas-New Mexico Pipeline Company discussed below,
covering thirteen states (Alabama, Arkansas, California, Louisiana, Mississippi,
New Mexico, Oklahoma, Texas, Kansas, Nebraska, Colorado, Montana and North
Dakota), including 7,400 miles of regulated intrastate and interstate common
carrier pipeline systems located in Alabama, Louisiana, Mississippi, Texas, New
Mexico, Oklahoma, Kansas, Nebraska, Colorado, California, Montana and North
Dakota. There are approximately 15.1 million barrels of storage capacity
associated with these pipelines and field tanks. We have operated the pipeline
systems with regular and continuous maintenance. Inspections and tests have been
performed at prescribed intervals in an effort to ensure the integrity of the
systems.
In two separate transactions, on July 1 and December 1, 1998, we acquired
approximately 4,200 miles of intrastate and interstate common carrier pipelines
in Texas, Oklahoma, Kansas, Nebraska, Colorado, Louisiana, California, Montana,
North Dakota, and South Dakota from Koch Pipeline Company, L.P. Storage
associated with the pipeline systems totals approximately 3.5 million barrels.
In addition, we acquired a gas processing plant referred to as Plant 8, with 20
million cubic feet per day of gas processing capacity; a fractionation plant
with 8,000 bpd of fractionation capacity; 5 million gallons of refrigerated
propane storage and related distribution facilities.
On May 1, 1999, we acquired crude oil transportation and storage assets in
West Texas and New Mexico from Texas-New Mexico Pipeline Company which included
approximately 1,800 miles of common carrier crude oil pipelines.
We operate six active barge facilities in Louisiana, and one in Alabama.
Approximately 2.2 million barrels of storage capacity are associated with these
barge facilities. We own three terminal facilities for the storage and
terminalling of bulk petroleum products in Ohio, which are currently held for
sale, and one refined products terminal in Alabama. Approximately 431,000
barrels of storage capacity are associated with these bulk petroleum product
facilities.
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RISK MANAGEMENT SERVICES/DERIVATIVES
We attempt to minimize our exposure to commodity prices. Generally, as we
purchase lease crude oil at prevailing market prices, we enter into
corresponding sales transactions involving physical deliveries of crude oil to
third party users, such as refiners or other customers, or a sale of futures
contracts on the NYMEX. This process gives us the opportunity to profit on the
transaction at the time of purchase and to effect a substantially balanced
position, thereby minimizing or reducing our exposure to price fluctuations that
may occur after the initial purchase.
Sophisticated price risk management strategies, including those involving
price hedges using NYMEX futures contracts, are very important in maintaining or
increasing our gross margins. Such hedging techniques require significant
resources dedicated to the management of futures positions and physical
inventories. Another important element of the hedging techniques is the accurate
estimation of lease crude oil volumes that will actually be purchased when we
pick them up from the producers. We effect transactions both in the futures and
physical markets in order to deliver the crude oil to its highest value location
or otherwise to maximize the value of the crude oil we control. Throughout the
process, we seek to maintain a substantially balanced position at all times. It
is our policy not to acquire and hold crude oil, other petroleum products,
futures contracts or other derivative products for the purpose of speculating on
price changes. Nevertheless, we do have certain risks that cannot be completely
hedged such as basis risks (the risk that price relationships between delivery
points, grades of crude oil or delivery periods will change) and the risk that
transportation costs will change, and from time to time enters into transactions
providing for purchases and sales in future periods in which the volumes of
crude oil are balanced but where either the purchase or sale prices are not
fixed at the time at which the transactions are consummated. In such cases, we
are subject to the risk that prices may change or that price changes will not
occur as anticipated. Our ability to maintain or increase the gross margins and
to protect our company from adverse price changes is dependent on the success of
the marketing and price risk management strategies. We can make no assurance
that the marketing and price risk management strategies will be successful in
protecting our company from risks or in maintaining the gross margins at
desirable levels.
CREDIT
Credit review and analysis are also integral to our lease crude oil
purchases. Payment for all or substantially all of the monthly lease crude oil
gathered is sometimes made to the operator of the lease. The operator, in turn,
is responsible for the correct payment and distribution of such production
proceeds to the proper parties. In these situations, we determine whether the
operator has sufficient financial resources to make such payments and
distributions and to indemnify and defend us in the event any third party should
bring a protest, action or complaint in connection with the ultimate
distribution of production proceeds by the operator.
When we market crude oil, we determine the amount, if any, of the line of
credit to be extended to any given customer. We use a proprietary credit rating
system that analyzes credit suitability and determines the amount of credit
extended. Since typical sales transactions can involve tens of thousands of
barrels of crude oil, the risk of non-payment and non-performance by customers
is a major consideration in our business. As a result, we reserve for bad debts;
however, beginning with our first full year of operations, 1995, the loss
experience has totaled less than $1.0 million per fiscal year. We believe our
sales are made to creditworthy entities or entities with adequate credit
support, of which approximately two-thirds have investment grade credit ratings.
COMPETITION
Competitive factors in the crude oil gathering and marketing business
include price, quality of service, transportation facilities, financial strength
and knowledge of products and markets. There are a number of major structural
and economic changes impacting all of our market segments that are driving new
customer needs, changing competitor dynamics and, consequently, creating new
challenges and
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opportunities for responsive market participants. The decline in domestic lease
crude oil production has made competition among gatherers and marketers even
more intense.
We compete with major oil companies, large independent crude gatherers and
a large number of small independent gatherers. Our principal competitors in the
purchase of leasehold crude oil production are Scurlock Permian Oil Corporation
(now owned by Plains All American), Equiva (the joint venture of Shell and
Texaco Trading & Transportation Co., Inc.), Amoco Oil Company (now BP Amoco
PLC), Genesis Energy, L.P., Sun Refining & Marketing and TEPPCO Partners, L.P.
ENVIRONMENTAL MATTERS
We are subject to federal, state and local laws and regulations relating to
the protection of the environment. At the federal level, such laws include,
among others, the Clean Air Act, the Clean Water Act, the Oil Pollution Act, the
Resource Conservation and Recovery Act, the Comprehensive Environmental
Response, Compensation and Liability Act, and the National Environmental Policy
Act, as each may be amended from time to time. Failure to comply with these laws
and regulations may result in the assessment of administrative, civil, and
criminal penalties. Moreover, compliance with such laws and regulations in the
future could prove to be costly, and there can be no assurance that we will not
incur such costs in material amounts.
The Clean Air Act controls, among other things, the emission of volatile
organic compounds, nitrogen oxides, and all other ozone-producing compounds in
order to protect national ambient air quality in accordance with standards
established for ozone and other pollutants. Such emissions may occur from the
handling or storage of petroleum or natural gas. The sources of emissions that
are subject to control and the types of controls required are a matter of
individual state air quality control implementation plans that set forth
emission limitations. Both federal and state laws impose substantial
administrative, civil and even criminal penalties for violation of applicable
requirements. As part of the regular overall evaluation of our current
operations, we are reviewing the operating permit status of certain of our
properties. We believe that our overall operations are in substantial compliance
with applicable air requirements.
The Clean Water Act, as amended by the Oil Pollution Act of 1990 ("OPA"),
controls, among other things, the discharge of oil and other petroleum products
into waters of the United States. The Clean Water Act provides penalties for any
unauthorized discharges of pollutants (including petroleum products) into waters
of the United States and imposes substantial potential liability for the costs
of responding to an unauthorized discharge of pollutants, such as an oil spill.
State laws for the control of water pollution also provide varying
administrative, civil and criminal penalties and liabilities in the event of a
release of petroleum or other related products in surface waters or the ground.
Federal and state permits for such water discharges may be required.
OPA also imposes a variety of requirements on "responsible parties" for oil
and gas facilities related to the prevention of oil spills and liability for
damages resulting from such spills in waters of the United States. The term
"responsible party" includes the owner or operator of an oil or gas facility
that could be the source of an oil spill affecting jurisdictional waters of the
United States. OPA assigns liability to each responsible party for oil spill
removal costs and a variety of public and private damages from oil spills. OPA
establishes a liability limit for onshore facilities of up to $350 million while
the limit for offshore facilities is all removal costs plus up to $75 million in
other damages. However, a party cannot take advantage of liability limits if the
spill is caused by gross negligence or willful misconduct, if the spill resulted
from violation of a federal safety, construction or operating regulation, or if
a party fails to report a spill or to cooperate fully in the cleanup. Few
defenses exist to the liability for oil spills imposed by OPA. OPA also imposes
other requirements on facility operators, such as the preparation of an oil
spill response plan, and a demonstration of the operator's ability to pay for
environmental cleanup and restoration costs likely to be incurred in connection
with an oil spill. For onshore facilities that have the ability to affect waters
of the United States, recent amendments to OPA require an operator to
demonstrate $10 million in financial responsibility, and $35 million in
financial responsibility for offshore facilities. On August 11, 1998, the U.S.
Minerals Management Service ("MMS") promulgated a final rule
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implementing the financial responsibility requirements set forth under the OPA
amendments. The financial responsibility may be increased to a maximum of $150
million if the MMS determines that a greater amount is justified based on
specific risks posed by the operations or if the worst case oil spill discharge
volume possible at the facility may exceed the applicable threshold volumes
specified under the MMS final rule. Failure to comply with these OPA
requirements or inadequate cooperation in a spill event may subject a
responsible party to administrative, civil or criminal actions. Our general
partner fully anticipates that we will be able to satisfy the MMS's requirements
for financial responsibility under OPA, as amended, and the final rule.
We generate wastes, including hazardous wastes, that are subject to the
federal Resources Conservation and Recovery Act ("RCRA") and comparable state
statutes. The U.S. Environmental Protection Agency ("EPA") and various state
agencies have limited the approved methods of disposal for certain hazardous and
nonhazardous wastes. Furthermore, certain wastes generated by us that are
currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes" and therefore be subject to more rigorous and
costly operating and disposal requirements.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
transported or disposed or arranged for the transport or disposal of the
hazardous substances that have been released at the site. Persons who are or
were responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment. In
the ordinary course of our operations, substances may be generated that fall
within the definition of "hazardous substances." Moreover, we may own or operate
properties that in the past were operated by third parties whose operations were
not under our control. Those properties and any wastes that may have been
disposed on them may be subject to CERCLA, RCRA and analogous state laws, and we
potentially could be required to remediate such properties.
The National Environmental Policy Act ("NEPA") may apply to certain
extensions or additions to a pipeline system. Under NEPA, if any project is to
be undertaken which would significantly affect the quality of the environment
and require a permit or approval from a federal agency, the federal agency may
require preparation of a detailed environmental impact study. The issuance by a
federal agency of a permit or approval to construct or extend a pipeline system
may constitute a major federal action under this Act. The effect of NEPA may be
to delay or prevent construction of new facilities or to alter their location,
design or method of construction. Similar state laws may also be applicable.
In addition to the foregoing, we are subject to state environmental laws
and regulations that address environmental considerations that may be of
particular concern to a state.
Our management believes that there are no outstanding potential liabilities
or claims relating to safety and environmental matters the resolution of which,
individually or in the aggregate, would have a materially adverse effect on our
financial position or results of operations and that we have used reasonably
diligent efforts to comply, in all material respects, with all applicable
environmental laws and regulations. No assurance can be given, however, as to
the amount or timing of future expenditures for environmental remediation or
compliance, and actual future expenditures may be different from the amounts
currently anticipated. In the event of future increases in costs, we may be
unable to pass on those increases to its customers.
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REGULATION
We are subject to a variety of federal and state regulations relating to
its interstate and intrastate pipeline transportation and safety activities,
motor carrier activities, and commodities trading business, the most significant
of which are discussed below.
Pipeline FERC Regulation
Interstate Regulation Generally. Our interstate common carrier pipeline
operations are subject to rate regulation by the FERC under the provisions of
the Interstate Commerce Act ("ICA"). These operations include the Hobbs Pipeline
in New Mexico and Texas, the crude oil system in Mississippi and Alabama ("the
Mississippi-Alabama Pipeline"), the crude oil systems acquired from CITGO
Pipeline Company ("CITGO Pipelines"), portions of the crude oil systems acquired
from Koch Pipeline, L.P. ("Koch Pipelines") and crude oil systems acquired from
Texas-New Mexico Pipeline Company ("Texas-New Mexico Pipelines"). The ICA
requires, among other things, that petroleum pipeline rates be just and
reasonable and non-discriminatory. The ICA permits interested parties 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 the 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 collected during the pendency of the
investigation in excess of those that would have been collected under the prior
tariff. In addition, the FERC, upon complaint or on its own motion and after
investigation, may order a carrier to change its rate 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.
We have annually amended our tariffs on all of our regulated pipelines as
provided by FERC regulations effective July 1 of each year beginning in 1995.
Although no assurance can be given that the tariffs charged by us will
ultimately be upheld if challenged, we believe that the tariffs now in effect
for all of our pipelines are within the maximum rates allowed under the current
FERC guidelines.
Energy Policy Act of 1992 and Subsequent Developments. In October 1992,
Congress passed the Energy Policy Act of 1992, which, among other things,
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 several orders, including Order No. 561. Beginning January 1, 1995,
Order No. 561 enables petroleum pipelines to change their rates within
prescribed ceiling levels that are tied to an inflation index. Rate increases
made pursuant to the indexing methodology are 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. A pipeline must, as a general
rule, utilize the indexing methodology to change its rates. The FERC, however,
retained cost-of-service ratemaking, market-based rates, and settlement as
alternatives to the indexing approach, which alternatives may be used in certain
specified circumstances. In addition to the regulatory considerations noted
above, it is expected that the Hobbs, Mississippi-Alabama, CITGO, Koch and
Texas-New Mexico Pipelines tariff rates will continue to be constrained by
competitive and other market factors.
State Regulation. Our intrastate pipeline transportation activities are
subject to various state laws and regulations, as well as orders of regulatory
bodies pursuant thereto.
Petroleum Pipeline Safety Regulation. Our petroleum pipelines are subject
to regulation by the Department of Transportation with respect to the design,
installation, testing, construction, operation, replacement, and management of
pipeline facilities. In addition, we must permit access to and copying of
records, and to make certain reports and provide information as required by the
Secretary of Transportation. Comparable regulation exists in some states in
which we conduct intrastate common carrier or private pipeline operations.
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Pipeline safety issues are currently receiving significant attention in
various political and administrative arenas at both the state and federal
levels. Significant expenses could be incurred by us if additional safety
requirements are imposed that exceed the current pipeline control system
capabilities.
Trucking Regulation
Generally, we operate our fleet of trucks as a private carrier.
Additionally, we are engaged in contract carrier hauling of crude oil in
Louisiana and natural gas liquids in California for third parties, and in
Oklahoma, Alabama and Mississippi we haul salt water, crude oil and other fluids
for others as a common carrier. Although a private or common carrier that
transports property in interstate commerce is not required to obtain operating
authority from the Surface Transportation Board, the carrier is subject to
certain motor carrier safety regulations issued by the Department of
Transportation. The trucking regulations extend to driver operations, keeping of
log books, truck manifest preparations, safety placards on the trucks and
trailer vehicles, drug and alcohol testing, safety of operation and equipment,
and many other aspects of truck operations. We are also subject to Occupational
Safety and Health Administration ("OSHA") regulations with respect to its
trucking operations.
We provide contract and common carrier services in these states pursuant to
permits issued by the various state regulatory agencies. Accordingly, as a
common or contract carrier, we are also subject to certain safety regulations
related to service and operations.
Commodities Regulation
Our price risk management operations are subject to constraints imposed
under the Commodity Exchange Act (the "CEA"). The futures and options contracts
that are traded on the NYMEX are subject to strict regulation by the Commodity
Futures Trading Commission (the "CFTC"). Although NYMEX futures contracts
include contracts on sweet crude oil, propane, No. 2 heating oil and other
refined petroleum products, there are many products that we will purchase and
sell for which no futures contracts are available, due in part to the strict
regulatory scheme for futures contracts. In addition, the trading volumes and
pricing bases of futures contracts on some products are such that the ability to
use them to hedge our price risks may be limited.
Other Regulation
After exiting the East of Rockies refined products business, we primarily
market refined gasoline at the wholesale level in 4 states. We market both
reformulated and conventional gasoline in ozone nonattainment areas during
control periods. We are subject to extensive federal and state laws and
regulations governing product specifications, transfer documentation, record
keeping and sampling. Many of these laws and regulations impose significant
financial penalties for non-compliance.
LEGAL PROCEEDINGS
We are, in the ordinary course of business, a defendant in various
lawsuits, some of which are covered in whole or in part by insurance. Although
no assurance can be given, our general partner believes that the ultimate
resolution of litigation, individually and in the aggregate, will not have a
materially adverse impact on our financial position or results of operations.
Various legal actions have arisen in the ordinary course of business, the most
significant of which are discussed below.
State of Texas Royalty Suit. We were served on November 9, 1995 with a
petition styled The State of Texas, et al. vs. Amerada Hess Corporation, et al.
The matter was filed in District Court in Lee County, Texas and involves several
major and independent oil companies and marketers as defendants. The plaintiffs
are attempting to put together a class action lawsuit alleging that the
defendants acted in concert to buy oil owned by members of the plaintiff class
in Lee County, Texas, and elsewhere in Texas, at "posted" prices, which the
plaintiffs allege were lower than true market prices. There is not sufficient
information in the petition to fully quantify the allegations set forth in the
petition, but our general partner believes that any such claims against us will
prove to be without merit.
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The State of Texas, et al. vs. Amerada Hess Corporation, et al., Cause No.
97-12040; In the 53rd Judicial District Court of Travis County, Texas (Common
Purchaser Act Suit). This case was filed on October 23, 1997 in Austin by the
Texas Attorney General's office and involves several major and independent oil
companies and marketers as defendants. We were served on November 18, 1997. The
petition states that the State of Texas brought this action in its sovereign
capacity to collect statutory penalties recoverable under the Texas Common
Purchaser Act, arising from defendants' alleged willful breach of statutory
duties owed to royalty, overriding royalty and working interest owners of crude
oil sold to defendants, as well as alleged breach of defendants' common law and
contractual duties. The plaintiffs also allege that the defendants have engaged
in discriminatory pricing of crude oil. This case appears to be similar to the
State of Texas Royalty Suit filed by the State of Texas on November 9, 1995. We
and several of the defendants reached a settlement with the State in the Common
Purchaser Act Suit in a Settlement Agreement dated August 5, 1999. Settlement
amounts for each defendant were confidential. This settlement disposed of any
claims the State may have in the State of Texas Royalty Suit, discussed above,
but did not dismiss that case. Also, any severance tax claims the State may have
were specifically excluded from this settlement. However, no severance tax
claims were asserted in the petition filed by the plaintiffs.
McMahon Foundation and J. Tom Poyner vs. Amerada Hess Corporation, et al.
(Including EOTT Energy Operating Limited Partnership), Civil Action No.
H-96-1155; United States District Court, Southern District of Texas, Houston
Division (Texas Federal Anti-Trust Suit). This suit was filed on April 10, 1996
as a class action complaint for violation of the federal antitrust laws and
involves several major and independent oil companies and marketers as
defendants. The relevant area is the entire continental United States, except
for Alaska, New York, Ohio, Pennsylvania, West Virginia and the Wilmington Field
at Long Beach, California. The plaintiffs claim that there is a combination and
conspiracy among the defendant oil companies to fix, depress, stabilize and
maintain at artificially low levels the price paid for the first purchase of
lease production oil sold from leases in which the class members own interests.
This was allegedly accomplished by agreement of the defendants to routinely pay
for first purchases at posted prices rather than competitive market prices and
maintain them in a range below competitive market prices through an undisclosed
scheme of using posted prices in buy/sell transactions among themselves to
create the illusion that posted prices are genuine market prices. The plaintiffs
allege violations from October of 1986 forward. No money amounts were claimed,
and it is not possible to determine any potential exposure until further
discovery is done.
Randolph Energy, Inc., et al. vs. Amerada Hess Corporation, et al., Civil
Action No. 2:97CV273PG; In the United States District Court for the Southern
District of Mississippi, Jackson Division (Mississippi Federal Anti-Trust
Suit). We received the summons in this matter on August 18, 1997. The case was
filed on August 5, 1997 and is a class action complaint for alleged violation of
the federal antitrust laws which involves several major and independent oil
companies and marketers as defendants. The plaintiffs claim that this litigation
arises out of a combination and conspiracy of the defendant oil companies to
fix, depress, stabilize and maintain at artificially low levels the prices paid
for the first purchase of lease production oil sold from leases in which the
class members own interests. The issues appear to be a duplication of the issues
in the Texas Federal Anti-Trust Suit previously discussed. No money amounts were
claimed, and it is not possible to determine any potential exposure until
further discovery is done.
Cameron Parish School Board, et al. vs. Texaco, Inc., et al.; Civil Action
No. C-98-111; In the United States District Court for the Western District of
Louisiana, Lake Charles Division (Louisiana Federal Anti-Trust Suit). This case
was originally filed as a state law claim in Louisiana. When the case was
removed to federal court, the anti-trust claims were added, similar to the
claims made in the Texas Federal Anti-Trust Suit and the Mississippi Federal
Anti-Trust Suit. The plaintiffs claim that this litigation arises out of a
combination and conspiracy of the defendant oil companies to fix, depress,
stabilize and maintain at artificially low levels the prices paid for the first
purchase of lease production oil sold from leases in which the class members own
interests. The issues appear to be a duplication of the issues in the Texas
Federal Anti-Trust Suit and the Mississippi Federal Anti-Trust Suit, both
previously discussed. On October 22, 1998, the judge granted the Plaintiffs'
motion to amend the petition and add
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additional defendants. We and our general partner were added to the case as
defendants at that time. No money amounts were claimed and it is not possible to
determine any potential exposure until further discovery is done.
The Texas Federal Anti-Trust Suit, the Mississippi Federal Anti-Trust Suit
and the Louisiana Federal Anti-Trust Suit, along with several other suits to
which we are not a party, were consolidated and transferred to the Southern
District of Texas by Transfer Order dated January 14, 1998. The Judicial Panel
on Multidistrict Litigation made this recommendation due to similarity of issues
in the cases. We and our general partner, along with a number of other
defendants, have entered into a class-wide settlement with the defendants which
was approved by the Court on April 7, 1999, with a Final Judgment entered on
August 11, 1999. Several appeals have been filed concerning the settlement.
Consequently, the settlement has not been funded, nor has the case been
dismissed.
Assessment for Crude Oil Production Tax from the Comptroller of Public
Accounts, State of Texas. We received a letter from the Comptroller's Office
dated October 9, 1998 assessing us for severance taxes the Comptroller's Office
alleges are due on a difference the Comptroller's Office believes exists between
the market value of crude oil and the value reported on our crude oil tax report
for the period of September 1, 1994 through December 31, 1997. The letter states
that the action, based on a desk audit of our crude oil production reports, is
partly to preserve the statute of limitations where crude oil severance tax may
not have been paid on the true market price of the crude oil. The letter further
states that the Comptroller's position is similar to claims made in several
lawsuits, including the Texas Federal Anti-Trust Suit, in which we are a
defendant. The amount of the assessment, including penalty and interest, is
approximately $1.1 million. While the claim is still being reviewed, our general
partner believes we should be without liability in this matter.
We believe that we have obtained or have applied for all of the necessary
permits required by federal, state, and local environmental agencies for the
operation of our business. Further, we believe that there are no outstanding
liabilities or claims relating to environmental matters individually and in the
aggregate, which would have a material adverse impact on our financial position
or results of operations.
EMPLOYEES
Our general partner employs approximately 1,400 people. We have no
employees represented by labor unions, and our general partner believes that the
relationships with its employees are good.
34
<PAGE> 39
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
As is common with publicly traded limited partnerships, we do not employ
any of the persons responsible for managing or operating our business, but
instead we reimburse our general partner for its services. Set forth below is
certain information concerning the directors and executive officers of the
general partner. All directors of the general partner are elected annually by
and may be removed by Enron Liquids Holding Corp., a wholly owned subsidiary of
Enron Corp., as the sole shareholder of the general partner. All executive
officers serve at the discretion of the board of directors of the general
partner.
<TABLE>
<CAPTION>
YEARS EMPLOYED
BY ENRON OR ITS
NAME AGE SUBSIDIARIES POSITION
---- --- --------------- --------
<S> <C> <C> <C>
Stanley C. Horton.............. 50 26 Chairman of the Board and Chief Executive
Officer
Dana R. Gibbs.................. 41 8 President, Chief Operating Officer and Director
John H. Duncan................. 72 -- Director
Dee S. Osborne................. 69 -- Director
Edward O. Gaylord.............. 69 -- Director
Daniel P. Whitty............... 69 -- Director
Kenneth L. Lay................. 58 22 Director
Lawrence Clayton, Jr........... 47 -- Senior Vice President and Chief Financial
Officer
Mary Ellen Coombe.............. 49 20 Vice President, Human Resources and
Administration
Molly M. Sample................ 45 9 General Counsel
David R. Hultsman.............. 56 1 Vice President, Business Transformation
Lori L. Maddox................. 36 4 Controller
Susan Ralph.................... 50 9 Treasurer
</TABLE>
Stanley C. Horton was elected to the EOTT Energy Corp. Board of Directors
in May 1998. He was elected Chairman of the Board of EOTT Energy Corp. in May
2000 and became Chief Executive Officer in June 2000. Mr. Horton is the Chairman
and Chief Executive Officer of Enron Gas Pipeline Group and has held that
position since January 1997. From February 1996 to January 1997, he was
Co-Chairman and Chief Operating Officer of Enron Operations Corp. From June 1993
to February 1996, he was President and Chief Operating Officer of Enron Pipeline
and Liquids Group. Mr. Horton was appointed to the Partnership Policy Committee
of Northern Border Partners, L.P. in December 1998. Mr. Horton serves on the
Board of Directors of the Interstate Natural Gas Association. He also serves as
Second Vice Chairman and Treasurer of Gas Industry Standards Board and as Vice
Chairman of Gas Research Institute.
Dana R. Gibbs joined EOTT Energy Corp. as Executive Vice President in April
1999 and became President, Chief Operating Officer and Director in June 2000. He
served as Vice President of Enron North America Corp. from 1992 to 1999. Prior
to joining Enron, he was Vice President Finance to MG Natural Gas Corp. from
1990 to 1992. Mr. Gibbs served as Experienced Manager with Arthur Andersen LLP
where he worked for nine years.
John H. Duncan was elected to the EOTT Energy Corp. Board of Directors in
January 1993 and appointed to the Compensation Committee in February 1993. Mr.
Duncan's principal occupation has been investments since 1990. Mr. Duncan is
also a director of Azurix Corp. and Group I Automotive Inc.
Dee S. Osborne was elected to the EOTT Energy Corp. Board of Directors and
appointed to the Audit Committee and Compensation Committee in February 1993.
Mr. Osborne serves as President of Crest Investment Company, Chairman of Digital
and Wireless Communications, L.L.C. and Vice Chairman of Jacintoport Terminal
Company. He is a director of Ocean Energy, Inc., Trustee of Scott & White
Memorial Hospital and Chairman Elect, University of Texas, Houston Health
Science Center.
Edward O. Gaylord has served as a member of the Board of Directors since
January 1993. Mr. Gaylord served as Chairman of the Board of EOTT Energy Corp.
from February 1993 until May
35
<PAGE> 40
2000. He was elected in December 1995 as a member of the Audit Committee. Mr.
Gaylord owned and managed Gaylord & Company, a private venture capital firm, and
he has owned interests in and managed various trucking, storage and
manufacturing entities in his career of more than 30 years. Mr. Gaylord serves
on the Board of Directors of Imperial Sugar Company, Seneca Foods Corporation,
Federal Reserve Bank of Dallas -- Houston Branch, and the General Partner of
Kinder Morgan Energy Partners, L.P.
Daniel P. Whitty was elected to the EOTT Energy Corp. Board of Directors in
January 1993 and appointed to the Audit Committee and the Compensation Committee
in February 1993. Mr. Whitty is an independent financial consultant and serves
as the Chairman of the Audit Committee of Northern Border Partners, L.P. and as
a director of Enron Equity Corp. He has also served as a director of Methodist
Retirement Communities, Inc. and a Trustee of the Methodist Retirement Trust.
Until his retirement in 1988, Mr. Whitty served 35 years with Arthur Andersen
LLP and was elected to its worldwide partnership in 1962.
Kenneth L. Lay was elected to the EOTT Energy Corp. Board of Directors in
January 1993. Mr. Lay has been Chairman of the Board and Chief Executive Officer
of Enron for over fourteen years. Mr. Lay is also a director of Eli Lily and
Company, Compaq Computer Corporation, Azurix Corp. and Trust Company of the
West.
Lawrence Clayton, Jr. has served as Senior Vice President and Chief
Financial Officer since September 2000. Prior to joining EOTT Energy Corp., Mr.
Clayton was Senior Vice President and Chief Financial Officer at Aquila Energy
Corporation, an integrated energy marketer and processor. From June 1990 to May
1994, he served as Vice President and Chief Financial Officer of Sunrise Energy
Services, Inc., a natural gas service company.
Mary Ellen Coombe has served as Vice President, Human Resources and
Administration of EOTT Energy Corp. since December 1992. Ms. Coombe has served
in various Human Resources and Administration positions within Enron over the
past nineteen years.
Molly M. Sample has served as General Counsel since September 2000. Ms.
Sample has served in various legal positions since joining the Company in April
1991.
David R. Hultsman joined EOTT Energy Corp. as Vice President, Business
Transformation in May 1999. From June 1997 to July 1998, he was Senior Director
Enterprise Operations to Boston Chicken Inc. and Einstein Bagels, Inc. From
November 1996 to May 1997 he was Vice President Information Services with West
Teleservices. Mr. Hultsman was Director, Columbia/HCA National Call Center
January through November 1996 and served as Vice President and President of
Information Systems, TESORO Petroleum Corp. in 1995.
Lori L. Maddox has served as Controller since October 1996. Prior to
joining EOTT Energy Corp., Ms. Maddox was associated with Arthur Andersen LLP
where she became a Senior Manager and served in the Energy Group for ten years.
Susan C. Ralph joined Enron Corp. in October 1991 and has served as
Treasurer of EOTT Energy Corp. since 1996. Prior to joining EOTT Energy Corp.,
Ms. Ralph served as Vice President and Director of Gorges Foodservices, Inc. and
has held various positions in the commercial banking industry.
Officers of EOTT Energy Corp. will not receive any additional compensation
for serving EOTT Energy Corp. as members of the Board of Directors or any of its
committees.
BOARD OF DIRECTORS
Our board of directors is comprised of seven individuals. Each member of
our board of directors who is not an employee or officer of EOTT or Enron will
receive an annual fee of $16,000 for serving as a director. In addition,
non-employee directors will be paid a fee of $2,000 for each director's meeting
attended and $1,000 for each committee meeting attended. Members of the audit
committee receive an annual fee of $4,000 for serving in the audit committee.
36
<PAGE> 41
COMMITTEES OF BOARD OF DIRECTORS
Audit Committee
Our audit committee reviews and monitors our financial statements and
accounting practices, makes recommendations to our board regarding the selection
of independent auditors and reviews the results and scope of the audit and other
services provided by our independent auditors. The audit committee will also
prepare a report to be included in our annual proxy statement. The audit
committee is currently composed of Daniel P. Whitty, Edward O. Gaylord and Dee
S. Osborne.
Compensation Committee
The compensation committee is responsible for the administration of our
executive compensation plans. The compensation committee is currently composed
of John H. Duncan, Daniel P. Whitty and Dee S. Osborne.
EXECUTIVE COMPENSATION
The following table summarizes certain information regarding compensation
paid or accrued by us during each of the last three fiscal years to the Chief
Executive Officer and each of our four other most highly compensated executive
officers:
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
ANNUAL COMPENSATION -------------------------
------------------------------- RESTRICTED SECURITIES
OTHER ANNUAL STOCK UNDERLYING OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION AWARDS OPTIONS/SARS COMPENSATION
--------------------------- ---- ------- ------ ------------ ---------- ------------ ------------
($) ($) ($)(1) ($)(2) (#)(3) ($)(4)
<S> <C> <C> <C> <C> <C> <C> <C>
Michael D. Burke............ 1999 340,008 -- -- -- 47,200 2,104
Chief Executive Officer 1998 212,504 30,000 -- -- 500,000 800
and President 1997 -- -- -- -- -- --
Mary Ellen Coombe........... 1999 160,000 40,000 -- -- -- 6,838
Vice President, Human 1998 160,000 15,100 -- -- -- 3,308
Resource and
Administration 1997 160,000 -- -- -- 32,000 1,129
Stephen W. Duffy............ 1999 168,333 30,000 -- -- -- 6,282
Vice President and 1998 160,000 25,100 -- -- -- 3,308
General Counsel 1997 160,000 -- -- -- 32,000 1,129
Lori L. Maddox.............. 1999 150,000 35,000 -- -- -- 53,063
Controller/CAO 1998 146,666 10,100 -- -- 6,000 500
1997 110,000 -- -- -- 3,000 --
Susan Ralph................. 1999 135,000 40,000 -- -- -- 38,102
Treasurer 1998 109,167 5,100 -- -- 6,000 1,887
1997 100,000 -- -- -- 3,000 --
</TABLE>
---------------
(1) None of the officers listed above had "Perquisites and Other Personal
Benefits" with a value greater than the lesser of $50,000 or 10% of reported
salary and bonus.
(2) Restricted stock awards have not been granted to the officers listed above
during the reporting period.
37
<PAGE> 42
(3) The amounts shown include options granted in 1999, 1998 and 1997 for Enron
Corp. common stock and EOTT subordinated units as follows: Mr. Burke, 47,200
Enron stock options for 1999, 100,000 Enron stock options, and 400,000 EOTT
unit options for 1998; Ms. Coombe and Mr. Duffy, 32,000 Enron stock options
for 1997; Ms. Maddox, and Ms. Ralph 6,000 Enron stock options for 1998, and
3,000 Enron stock options for 1997.
(4) The amounts include the value of Enron Corp. common stock allocated to
employees' special subaccounts under Enron's employee stock ownership plan,
and matching contributions to employees' Enron Corp. savings plan accounts.
Under retention agreements, Ms. Maddox and Ms. Ralph received onetime
retention payments in February 1999 of $50,000 and $35,000 respectively.
STOCK OPTION GRANTS DURING 1999
The following table sets forth information with respect to grants of
options pursuant to the officers named in the Summary Compensation Table and all
employee optionees as a group. No unit options were granted during 1999 under
our unit option plan. Stock options were granted during 1999 under Enron's 1994
Stock Plan. No SAR units were granted during 1999, and none are outstanding.
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS
-------------------------------------------------
% OF TOTAL
OPTIONS/ OPTIONS/SARS EXERCISE
SARS GRANTED TO OR BASE
GRANTED EMPLOYEES IN PRICE EXPIRATION
NAME (2) FISCAL YEAR ($/SH) DATE
---- ---------- ------------ -------- ----------
<S> <C> <C> <C> <C> <C>
Michael D. Burke........ EOTT -- -- -- --
Enron Corp. 47,200 0.14% $32.6875 1/25/06
Mary E. Coombe.......... EOTT -- -- -- --
Enron Corp. -- -- -- --
Stephen W. Duffy........ EOTT -- -- -- --
Enron Corp. -- -- -- --
Lori L. Maddox.......... EOTT -- -- -- --
Enron Corp. -- -- -- --
Susan Ralph............. EOTT -- -- -- --
Enron Corp. -- -- -- --
All Employee and EOTT -- -- -- N/A
Director Optionees.... Enron Corp. 34,446,667(4) 100% $38.1638(3) N/A
All Stock/Unitholders... EOTT -- -- -- --
Enron Corp. N/A N/A N/A N/A
Optionee Gain as % of EOTT N/A N/A N/A N/A
all Unitholders Enron Corp. N/A
Gain................ N/A N/A N/A
<CAPTION>
POTENTIAL REALIZABLE VALUE AT ASSUMED
ANNUAL RATES OF STOCK PRICE APPRECIATION
FOR OPTION TERM(1)
------------------------------------------
NAME 0%(3) 5% 10%
---- ----- --------------- ---------------
<S> <C> <C> <C>
Michael D. Burke........ $ -- $ -- $ --
$ -- $ 628,095 $ 1,463,729
Mary E. Coombe.......... $ -- $ -- $ --
$ -- $ -- $ --
Stephen W. Duffy........ $ -- $ -- $ --
$ -- $ -- $ --
Lori L. Maddox.......... $ -- $ -- $ --
$ -- $ -- $ --
Susan Ralph............. $ -- $ -- $ --
$ -- $ -- $ --
All Employee and $ -- $ -- $ --
Director Optionees.... $ -- $ 2,141,370,466(6) $ 3,409,774,586(6)
All Stock/Unitholders... $ -- $ -- $ --
$ -- $44,480,621,930(6) $70,827,956,490(6)
Optionee Gain as % of -- -- --
all Unitholders
Gain................ -- 4.81% 4.81%
</TABLE>
---------------
(1) The dollar amounts under these columns represent the potential realizable
value of each grant of Enron Corp. stock options assuming that the market
price of the common stock appreciates in value from the date of grant at the
5% and 10% annual rates prescribed by the SEC and therefore are not intended
to forecast possible future appreciation, if any, of the price of the common
stock.
The dollar amounts under these columns represent the potential realizable
value of each grant of EOTT Energy Corp. unit options assuming the
subordinated unit option converts to a common unit option and the market
price of a common unit appreciates in value from the date of grant at the 5%
and 10% annual rates prescribed by the SEC. The dollar amounts shown are not
intended to forecast possible future appreciation, if any, of the price of
common units.
(2) Represents Enron Corp. stock options awarded during 1999 under Enron's 1994
Stock Plan. Mr. Burke was awarded stock options with a 7-year term, which
vested 20% at grant and 20% on January 25, 2000, and will vest 20% on each
January 25, 2001, 2002 and 2003.
(3) An appreciation in stock price, which will benefit all stockholders, is
required for optionees to receive any gain. A stock price appreciation of
zero percent would render the option without value to the optionees.
38
<PAGE> 43
(4) Includes shares issued on December 31, 1999 under the All Employee Stock
Option Program to employees hired during 1999.
(5) Weighted average exercise price of all Enron stock options granted to
employees in 1999.
(6) Appreciation for all employee and director optionees is calculated using the
maximum allowable option term of ten years, even though in some cases the
actual option term is less than ten years. Appreciation for all shareholders
is calculated using an assumed ten-year option term, the weighted average
exercise price for all employee and director optionees ($38.1638) and the
number of shares of common stock issued and outstanding on December 31,
1999.
AGGREGATED OPTIONS/SAR EXERCISES DURING 1999 AND OPTION/SAR VALUES AT DECEMBER
31, 1999
The following table sets forth information with respect to the officers
named in the Summary Compensation Table concerning the exercise of options under
EOTT's and Enron's option plans during the last fiscal year and unexercised
options and SARs held as of the end of the fiscal year:
<TABLE>
<CAPTION>
VALUE OF UNEXERCISED
NUMBER OF SECURITIES IN-THE-MONEY
UNDERLYING UNEXERCISED OPTIONS/SARS AT
SHARES OPTIONS/SARS AT DECEMBER 31, 1999
ACQUIRED VALUE DECEMBER 31, 1999 ($)(1)(2)
ON REALIZED --------------------------- ---------------------------
NAME EXERCISE ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- -------- -------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
M. Burke............. EOTT -- $ -- -- 400,000 $ -- $ --
Enron Corp. -- -- 59,440 87,760 1,044,705 1,375,695
----------
Subtotal $1,375,695
M.E. Coombe.......... EOTT -- $ -- -- 60,000 $ -- $ --
Enron Corp. -- -- 60,800 8,000 $1,939,925 192,000
----------
Subtotal $ 192,000
S. Duffy............. EOTT -- $ -- -- 60,000 $ -- $ --
Enron Corp. 4,000 $50,000 20,000 8,000 $ 480,000 192,000
----------
Subtotal $ 192,000
L. Maddox............ EOTT -- $ -- -- -- $ -- $ --
Enron Corp. -- -- 5,250 3,750 124,219 88,218
----------
Subtotal $ 88,218
S. Ralph............. EOTT -- $ -- -- -- $ -- $ --
Enron Corp. -- -- 5,250 3,750 $ 124,219 88,218
----------
Subtotal $ 88,218
</TABLE>
---------------
(1) The dollar value in this column for our options was calculated by assuming
the subordinated unit option converts to a common unit option and
determining the difference between the fair market value of the common units
and the exercise value of the option at the end of the fiscal year. The
value of our common units at year-end 1999 was $13.00 and the subordinated
unit grant price is $15.00.
(2) The dollar value in this column for Enron Corp. stock options was calculated
by determining the difference between the fair market value underlying the
option as of December 31, 1999 ($44.3750) and the grant price.
39
<PAGE> 44
LONG TERM INCENTIVE PLAN AWARDS IN 1999
In October 1997, our board of directors adopted the EOTT Energy Corp. Long
Term Incentive Plan. The long-term incentive plan is intended to provide key
employees with phantom appreciation rights, which are rights to receive cash
based on our performance prior to the time the phantom appreciation right is
redeemed. The long-term incentive plan has a five year term beginning January 1,
1997 and awards vest in 25% increments over a four year period following the
grant year. The following table provides information concerning awards of
phantom appreciation rights under the long-term incentive plan during 1999 to
the officers named in the Summary Compensation Table.
<TABLE>
<CAPTION>
PERFORMANCE FUTURE ESTIMATED
NUMBER OR OTHER PAYMENTS UNDER
OF SHARES, PERIOD UNTIL NON-STOCK BASED PLANS(1)
UNITS OR MATURATION -------------------------------------
NAME RIGHTS PAYOUT THRESHOLD $ TARGET $ MAXIMUM $
---- ---------- ------------ ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
M. Burke..................... EOTT 300,000 5 Years $ -- $2,586,000 $5,040,000
M.E. Coombe.................. EOTT 50,000 5 Years $ -- $ 431,000 $ 840,000
S. Duffy..................... EOTT 50,000 5 Years $ -- $ 431,000 $ 840,000
L. Maddox.................... EOTT 30,400 5 Years $ -- $ 262,048 $ 510,720
S. Ralph..................... EOTT 30,400 5 Years $ -- $ 262,048 $ 510,720
</TABLE>
Future estimated payments were based on a 10% targeted growth for each year
of the 5-year performance period. Maximum payments were estimated at a 20%
growth rate for the 5 year performance period.
ENRON BENEFIT AND COMPENSATION PLANS
Our employees continue benefit accrual under the Enron Corp. Cash Balance
Pension Plan and continue to be eligible for participation in the Enron Corp.
Savings Plan.
RETIREMENT PLANS AND SUPPLEMENTAL BENEFIT PLANS
Enron maintains the Enron Corp. Cash Balance Pension Plan which is a
noncontributory defined benefit plan to provide retirement income for employees
of Enron and its subsidiaries. Through December 31, 1994, participants in the
cash balance plan with five years or more of service were entitled to retirement
benefits in the form of an annuity based on a formula that uses a percentage of
final average pay and years of service. In 1995, Enron's board of directors
adopted an amendment to and restatement of the cash balance plan changing the
plan's name from the Enron Corp. Retirement Plan to the Enron Corp. Cash Balance
Plan. In connection with a change to the retirement benefit formula, all members
became fully vested in retirement benefits earned through December 31, 1994. The
formula in place prior to January 1, 1995 was suspended and replaced with a
benefit accrual in the form of a cash balance of 5% of annual base pay beginning
January 1, 1996. Under the cash balance plan, each employee's accrued benefit
will be credited with interest based on 10-year Treasury Bond yields. Directors
who are not employees are not eligible to participate in the cash balance plan.
Enron also maintains a noncontributory employee stock ownership plan which
covers all eligible employees. Allocations to individual employees' retirement
accounts within the employee stock ownership plan offset a portion of benefits
earned under the cash balance plan prior to December 31, 1994. December 31, 1993
was the final date on which employee stock ownership plan allocations were made
to employees' retirement accounts.
In addition, Enron has a supplemental retirement plan that is designed to
assure payments to certain employees of that retirement income that would be
provided under the cash balance plan except for the dollar limitation on accrued
benefits imposed by the Internal Revenue Code of 1986, as amended.
The following table sets forth the estimated annual benefits payable under
normal retirement at age 65, assuming current remuneration levels without any
salary projection, and participation until normal
40
<PAGE> 45
retirement at age 65, with respect to the officers named in the Summary
Compensation Table under the provisions of the foregoing retirement plans:
<TABLE>
<CAPTION>
ESTIMATED CURRENT ESTIMATED
CURRENT CREDITED CREDITED YEARS COMPENSATION ANNUAL
YEARS OF OF SERVICE AT COVERED BENEFIT PAYABLE
SERVICE AT AGE 65 BY PLANS UPON RETIREMENT
---------------- -------------- ------------ ---------------
<S> <C> <C> <C> <C>
M. Burke....................... 1.6 10.8 $340,008 $31,072
M.E. Coombe.................... 19.3 35.2 $160,000 $75,108
S. Duffy....................... 12.9 31.4 $168,333 $68,834
L. Maddox...................... 3.3 33.0 $150,000 $99,113
S. Ralph....................... 8.4 23.3 $135,000 $32,439
</TABLE>
---------------
Note: The estimated annual benefits payable are based on the straight life
annuity form without adjustment for any offset applicable to a
participant's retirement subaccount in Enron's Employee Stock Ownership
Plan.
EOTT ENERGY CORP. SEVERANCE PLAN
The EOTT Energy Corp. Severance Pay Plan as amended provides for the
payment of benefits to employees who are terminated for failing to meet
performance objectives or standards, or who are terminated due to reorganization
or economic factors. The amount of benefits payable for performance related
terminations is based on length of service and may not exceed six weeks' pay in
the event such employee signs a waiver and release of claims agreement. For
those terminated as the result of reorganization or economic circumstances, the
benefit is based on length of service with one week's pay per year of service up
to an amount of a maximum payment of 26 weeks of base pay. If the employee signs
a waiver and release of claims agreement, the severance pay benefits are
doubled. The plan provides a grandfather provision for those employees whose
employment date is prior to January 1, 1993. This provision provides a severance
benefit equal to two weeks of base pay multiplied by the number of full or
partial years of service, plus two weeks of base pay for each $10,000 (or
portion of $10,000) included in the employee's annual base pay, provided the
employee signs a waiver and release of claims agreement. In the event we have an
unapproved change of control, any employee who is involuntarily terminated
within two years following the change of control will be eligible for severance
benefits equal to two weeks of base pay multiplied by the number of full or
partial years of service, plus two weeks of base pay for each $10,000 (or
portion of $10,000) included in the employee's annual base pay. Under no
circumstances will the total severance pay benefit exceed 52 weeks of pay.
Severance arrangements for Mr. Gibbs, Ms. Coombe, and Mr. Duffy include an
involuntary termination provision pursuant to which the executive officer will
receive severance pay equal to up to two years base salary. An involuntary
termination includes (a) termination without cause; (b) a termination within 90
days after the happening of one of the following events without the approval of
the executive officer: (i) a substantial and/or material reduction in the nature
or scope of the executive officer's duties and/or responsibilities, which
results in the executive officer no longer having an officer status and results
in an overall material and substantial reduction from the duties and stature of
the officer position he presently holds, which reduction remains in place and
uncorrected for 30 days following written notice of such breach to our general
partner by the executive officer, (ii) a reduction in the executive officer's
base pay or an exclusion from a benefit plan or program (except the executive
officer may be subject to exclusion from a benefit plan or program as part of a
general cutback for all employees or officers) or (iii) a change in the location
for the primary performance of the executive officer's services under the
agreement to a city which is more than 100 miles away from such location; and
(c) a termination by the executive officer within one year after a change of
control of our general partner if one of the events described in (b) has
occurred. The severance agreement, the confidential information and noncompete
provisions will continue for one year.
41
<PAGE> 46
EMPLOYMENT AGREEMENTS
Mr. Burke entered into an employment agreement with us in May 1998. After
he resigned from his position as President and Chief Executive Officer in June
2000, this agreement was cancelled and superseded by a new employment agreement
with us effective as of July 1, 2000. The term of this agreement runs through
January 31, 2003. Mr. Burke's position is Special Assistant to the Chairman. The
agreement provides for a monthly base salary of $4,333.33. Under the agreement,
the following grants previously received by Mr. Burke were waived and rescinded:
a January 1, 2000 grant of options to purchase 100,000 of our subordinated
units; grants of 90,828 and 300,000 dated May 18, 1998 and March 2, 1999 under
our long-term incentive plan; and a grant of 400,000 subordinated units on May
18, 1998 under our unit option plan.
Mr. Gibbs entered into an employment agreement with EOTT Energy Corp. on
April 1, 1999 for a term of three years. The agreement provides for an annual
base salary of not less than $200,000 and an annual incentive plan target of 50%
with a maximum pay-out of 100% of annual base salary. The agreement further
provides a retention bonus of $100,000 payable in January 2000 and January 2001.
Per the agreement, Mr. Gibbs received a grant of 53,475 phantom appreciation
right units under our long-term incentive plan. The agreement provides for post
employment non-compete obligations in the event of termination.
42
<PAGE> 47
CERTAIN TRANSACTIONS
CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES
We have extensive ongoing relationships with Enron and its affiliates.
Enron's indirect, wholly owned subsidiary, EOTT Energy Corp., serves as our
general partner. Our general partner's employees participate in some employee
benefit plans administered by Enron. Our general partner owns, in addition to
its approximately 2% general partner interest, subordinated units representing
approximately a 29% interest in us, and Enron owns common units representing
approximately a 14% interest in us. The members of the board of directors of our
general partner are elected by a wholly-owned subsidiary of Enron. Our interests
could conflict with the interests of Enron and its affiliates, including our
general partner, and in such case our general partner will generally have a
fiduciary duty to resolve the conflicts in a manner that is in our best
interest.
Unless otherwise provided for in a partnership agreement, the laws of
Delaware and Texas generally require a general partner of a partnership to
adhere to fiduciary duty standards, under which it owes its partners the highest
duties of good faith, fairness and loyalty. Because of the competing interests
identified above, our partnership agreement contains provisions that modify some
of these fiduciary duties. For example, our partnership agreement states that
our general partner, its affiliates and its officers and directors will not be
liable for monetary damages to us, our limited partners or their assignees for
errors of judgment or for any acts or omissions if our general partner and they
acted in good faith. Our partnership agreement allows our general partner and
its board of directors to take into account the interests of parties in addition
to ours in resolving conflicts of interest. Our partnership agreement provides
that our general partner will not be in breach of its obligations under our
partnership agreement or its duties to us or our unitholders if the resolution
of a conflict is fair and reasonable to us. The latitude given in our
partnership agreement in connection with resolving conflicts of interest may
significantly limit the ability of a unitholder to challenge what might
otherwise be a breach of fiduciary duty. Our partnership agreement provides that
a purchaser of common units is deemed to have consented to conflicts of interest
and actions of our general partner and its affiliates that might otherwise be
prohibited and to have agreed that the conflicts of interest and actions do not
constitute a breach by our general partner of any duty stated or implied by law
or equity. Our audit committee (which is composed of persons who are not
officers or employees of our general partner or any of its affiliates) will, at
the request of our general partner, review conflicts of interest that may arise
between our general partner and its affiliates, on the one hand, and our
unitholders or us, on the other. Any resolution of a conflict approved by our
audit committee is conclusively deemed fair and reasonable to us. We are
required to indemnify our general partner, its affiliates and their respective
officers, directors, employees, agents and trustees to the fullest extent
permitted by law against liabilities, costs and expenses incurred by any of them
who acted in good faith and in a manner reasonably believed to be in or (in the
case of a person other than our general partner) not opposed to, our best
interests and, with respect to any criminal proceedings, had no reasonable cause
to believe the conduct was unlawful.
Our extensive ongoing relationships with Enron include:
- an Ancillary Agreement pursuant to which Enron has committed to
contribute to us up to $29 million ($19.7 million of which remains
available) if necessary to support our ability to pay the minimum
quarterly distribution on our common units with respect to quarters
ending on or prior to December 31, 2001;
- a Corporate Services Agreement pursuant to which Enron has agreed to
provide corporate staff and support services. Our general partner
proposes to enter into an agreement with an affiliate of Enron on a
similar basis, pursuant to which our general partner would outsource
pipeline operations and environmental and other matters to the Enron
affiliate.
- agreements with Enron affiliates regarding the gathering and purchase by
us of volumes of crude oil and condensate; and
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<PAGE> 48
- a $1 billion credit facility provided by Enron to us.
Under our partnership agreement, with some limited exceptions, affiliates
of our general partner are not restricted from engaging in any business
activities, including those in competition with us. As a result, other conflicts
of interest may arise between affiliates of our general partner and us. Our
partnership agreement provides that, subject to limited exceptions, it shall not
constitute a breach of our general partner's fiduciary duties to our unitholders
or to us for any affiliate of our general partner to engage in direct
competition with us including, without limitation, the gathering, transportation
and marketing of crude oil and refined petroleum products.
TRANSACTIONS WITH ENRON AND RELATED PARTIES
General and Administrative. As is commonly the case with publicly traded
partnerships, we do not directly employ any persons responsible for managing or
operating our business or for providing services relating to day-to-day business
affairs. Our general partner manages our business. We reimburse our general
partner for its direct and indirect costs. Those costs were $3.8 million, $3.3
million and $3.6 million for the years ended December 31, 1999, 1998 and 1997,
respectively and are included in operating expenses. Management believes that
the charges were reasonable.
Financing of Acquisitions. As discussed further in Note 4 to our audited
financial statements included elsewhere herein, on July 1, 1998 and December 1,
1998, we acquired crude oil gathering and transportation assets from Koch which
was financed primarily with borrowings from Enron. In addition, we acquired
crude oil transportation and storage assets from Texas-New Mexico Pipeline
Company which was financed using short-term borrowings from Enron. See further
discussion in Note 8 to our audited financial statements included elsewhere
herein regarding the repayment of borrowings from Enron.
Support Agreement. Pursuant to a support agreement dated September 21, 1998
(a) Enron agreed to make loans to us to fund the cash portion of the
consideration paid to Koch for the assets we purchased at closing as discussed
in Note 4 to our financial statements and to refinance indebtedness incurred in
the prior acquisition of assets from Koch on July 1, 1998, (b) Enron agreed to
increase and extend our credit facility with Enron to $1 billion through
December 31, 2001, (c) we agreed to issue 1,150,000 special units to Enron, (d)
Enron agreed to contribute $21.9 million in additional partnership interests to
us on the earlier of the date of unitholder approval of certain proposals,
discussed further in Note 12 to our audited financial statements included
elsewhere herein, or May 17, 1999, (e) Enron agreed that if certain proposals
were approved by the unitholders it would extend its cash distribution support
through the fourth quarter of 2001, and (f) we agreed that, if any more
additional partnership interests were issued prior to approval of certain
proposals by the unitholders, we would issue additional common units at $19.00
per share in exchange for such additional partnership interests. We obtained
unitholder approval of these proposals on February 12, 1999. Pursuant to the
support agreement, in December 1998, we borrowed from Enron a $42 million bridge
loan and a $175 million term loan, which were repaid in October 1999, and
entered into a $1 billion credit facility with Enron, to replace our existing
$600 million credit facility.
Special Units. Effective July 16, 1996, we created a new class of limited
partner interest designated as special units. The special units ranked pari
passu with the common units in all distributions and upon liquidation and were
voted as a class with the common units. In connection with the support
agreement, we issued 1,150,000 special units to Enron in December 1998 and, as
discussed further below, Enron contributed $21.9 million in additional
partnership interests to us in February 1999. The special units were converted
into common units in March 1999 on a one-for-one basis pursuant to the support
agreement following the favorable vote of unitholders in February 1999.
Additional Partnership Interests. As of December 31, 1998, Enron had paid
$21.9 million in distribution support. In exchange for the distribution support,
Enron received additional partnership interests in our company. Additional
partnership interests have no voting rights and are non-distribution bearing;
however, additional partnership interests will be entitled to be redeemed if,
with respect to any quarter, the minimum quarterly distribution and any common
unit arrearages have been paid, but only to
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<PAGE> 49
the extent that available cash with respect to such quarter exceeds the amount
necessary to pay the minimum quarterly distribution on all units and any common
unit arrearages. As discussed in Note 12 to our audited financial statements
included elsewhere herein, certain unitholder approvals were obtained on
February 12, 1999 and as a result, Enron increased its cash distribution support
to $29 million and extended it through the fourth quarter of 2001 and
contributed the $21.9 million in additional partnership interests outstanding at
December 31, 1998 pursuant to its commitment made in connection with the support
agreement. On May 14, 1999 and February 14, 2000, Enron paid $2.5 million and
$6.8 million, respectively, in support of our first and fourth quarter 1999
distributions to our common unitholders and received additional partnership
interests.
PRINCIPAL SHAREHOLDERS
Our general partner knows of no one who beneficially owns in excess of five
percent of our common units except as set forth in the table below.
<TABLE>
<CAPTION>
AMOUNT AND NATURE
OF BENEFICIAL
NAME AND ADDRESS OWNERSHIP AS OF PERCENT
TITLE OF CLASS OF BENEFICIAL OWNER FEBRUARY 15, 2000 OF CLASS
-------------- ------------------- ----------------- --------
<S> <C> <C> <C>
Common Units.......................... Enron Corp. 3,276,811 17.74
Subordinated Units 1400 Smith Street 7,000,000(1) 77.78
General Partner Interest Houston, Texas 77002 1(1)(2) 100.00
Common Units.......................... Koch Pipeline Company 1,700,000 9.20
Subordinated Units 4111 East 37th Street N. 2,000,000 22.22
Wichita, Kansas 67220
</TABLE>
---------------
(1) Held by our general partner, an indirect subsidiary of Enron Corp.
(2) The reporting of the interest held by our general partner shall not be
deemed to be a concession that such interest represents a security.
The following table sets forth certain information as of February 15, 2000,
regarding the beneficial ownership of (i) our common units and (ii) the common
stock of Enron Corp., the parent company of our general partner, by all
directors of our general partner, each of the named executive officers and all
directors and executive officers as a group.
<TABLE>
<CAPTION>
AMOUNT AND NATURE OF BENEFICIAL OWNERSHIP
-------------------------------------------------------------
SOLE VOTING SHARED VOTING SOLE VOTING
AND INVESTMENT AND INVESTMENT LIMITED OR NO PERCENT
TITLE OF CLASS NAME POWER(1) POWER INVESTMENT POWER OF CLASS
-------------- ---- -------------- -------------- ---------------- --------
<S> <C> <C> <C> <C> <C>
EOTT Energy Partners, Michael D. Burke........ 78,900 -- -- *
L.P. Common Units Mary Ellen Coombe....... 60,000 -- -- *
O. Horton Cunningham.... -- -- -- *
Stephen W. Duffy........ 60,000 -- -- *
John H. Duncan.......... 8,500 -- -- *
Edward O. Gaylord....... 5,000 -- -- *
Dana R. Gibbs........... 6,000 -- -- *
Stanley C. Horton....... 10,000 -- -- *
Kenneth L. Lay.......... -- 5,000 -- *
Lori L. Maddox.......... -- -- -- *
Dee S. Osborne.......... -- -- -- *
Susan C. Ralph.......... 300 500 -- *
Daniel P. Whitty........ -- -- -- *
All directors and
executive officers as
a group (13 in
number)............... 228,700 5,500 -- 1.26%
</TABLE>
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<PAGE> 50
<TABLE>
<CAPTION>
AMOUNT AND NATURE OF BENEFICIAL OWNERSHIP
-------------------------------------------------------------
SOLE VOTING SHARED VOTING SOLE VOTING
AND INVESTMENT AND INVESTMENT LIMITED OR NO PERCENT
TITLE OF CLASS NAME POWER(1) POWER INVESTMENT POWER OF CLASS
-------------- ---- -------------- -------------- ---------------- --------
<S> <C> <C> <C> <C> <C>
Enron Corp. Common Michael D. Burke........ 68,895 -- 83 *
Stock Mary Ellen Coombe....... 69,309 -- 26,884 *
Stephen W. Duffy........ 28,405 -- -- *
John H. Duncan.......... 168,962 58,000 180 *
Edward O. Gaylord....... -- -- 42 *
Dana R. Gibbs........... 75,855 -- 884 *
Stanley C. Horton....... 494,360 3,607 37,898(2) *
Kenneth L. Lay.......... 5,351,124 2,396,912 267,486 1.10%
Lori L. Maddox.......... 7,513 -- 92 *
Susan C. Ralph.......... 2,263 -- 1,234 *
All directors and
executive officers as
a group (13 in
number)............... 6,266,686 2,458,519 334,783(2) 1.24%
</TABLE>
---------------
* Less than 1 percent
(1) The above table includes subordinated units which are subject to conversion
into common units and which are subject to unit options exercisable within
60 days as follows: Ms. Coombe, 60,000 units; Mr. Duffy, 60,000 units; and
all directors and executive officers as a group, 120,000 units. The above
table also includes shares of common stock of Enron Corp. which are subject
to stock options exercisable within 60 days as follows: Mr. Duncan, 41,088
shares, for which he has shared voting and investment power for 38,160 of
such shares; Mr. Burke, 68,893 shares; Mr. Lay, 5,534,145 shares, for which
he has shared voting and investment power for 1,615,330 of such shares; Ms.
Coombe, 68,893; Mr. Duffy, 28,013; Mr. Gibbs, 74,599; Mr. Horton, 396,998;
Ms. Maddox, 7,513; Ms. Ralph, 2,263 shares and all directors and executive
officers as a group, 6,222,405 shares.
(2) Includes 2,591 shares held by the spouse of Mr. Horton, for which he may be
deemed to have shared voting and investment power.
The table also includes shares owned by certain members of the families (or
family or charitable trusts or foundations) of the directors or executive
officers, including shares in which pecuniary interest may be disclaimed.
SELLING SHAREHOLDER
The following table sets forth the name and address of the selling
shareholder, the number of common units beneficially owned by the selling
shareholder, and the number of common units offered by the selling shareholder.
<TABLE>
<CAPTION>
NUMBER OF
NUMBER OF COMMON UNITS COMMON UNITS
SELLING SHAREHOLDER BENEFICIALLY OWNED OFFERED
------------------- ---------------------- ------------
<S> <C> <C>
Koch Pipeline Company, L.P. 1,700,000 1,700,000
4111 East 37th Street North
Wichita, Kansas 67220
</TABLE>
The common units being offered are owned by the selling shareholder, which
acquired them from us pursuant to transactions exempt from the registration
requirements of the Securities Act. The selling shareholder also owns 2,000,000
subordinated units and will continue to own those subordinated units after the
offering.
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<PAGE> 51
DESCRIPTION OF OUR COMMON UNITS
Generally, our common units represent limited partner interests that
entitle the holders to participate in our cash distributions and to exercise the
rights or privileges available to limited partners under our partnership
agreement. For a description of the relative rights and preferences of holders
of common units, holders of subordinated units and our general partner in and to
cash distributions, together with a description of the circumstances under which
subordinated units convert into common units, see "Cash Distribution Policy."
Our limited partners are the holders of the 18,476,011 common units and the
holders of the 9,000,000 subordinated units.
Our outstanding common units are listed on the NYSE under the symbol "EOT."
Any additional common units we issue will also be listed on the NYSE.
The transfer agent and registrar for our common units is the First Chicago
Trust Company of New York.
MEETINGS/VOTING
Each holder of common units is entitled to one vote for each common unit on
all matters submitted to a vote of the unitholders.
STATUS AS LIMITED PARTNER OR ASSIGNEE
Except as described below under "-- Limited Liability," the common units
will be fully paid, and unitholders will not be required to make additional
capital contributions to us.
Each purchaser of common units offered by this prospectus must execute a
Transfer Application (the form of which is attached as Appendix I to this
prospectus) whereby the purchaser requests admission as a substituted limited
partner and makes representations and agrees to provisions stated in the
Transfer Application. If this action is not taken, a purchaser will not be
registered as a record holder of common units on the books of our transfer agent
or issued a common unit certificate. Purchasers may hold common units in nominee
accounts.
An assignee, pending its admission as a substituted limited partner, is
entitled to an interest in us equivalent to that of a limited partner with
respect to the right to share in allocations and distributions, including
liquidating distributions. Our general partner will vote and exercise other
powers attributable to common units owned by an assignee who has not become a
substituted limited partner at the written direction of the assignee.
Transferees who do not execute and deliver transfer applications will be treated
neither as assignees nor as record holders of common units and will not receive
cash distributions, federal income tax allocations or reports furnished to
record holders of common units. The only right the transferees will have is the
right to admission as a substituted limited partner in respect of the
transferred common units upon execution of a transfer application in respect of
the common units. A nominee or broker who has executed a transfer application
with respect to common units held in street name or nominee accounts will
receive distributions and reports pertaining to its common units.
LIMITED LIABILITY
Assuming that a limited partner does not participate in the control of our
business within the meaning of the Delaware Revised Uniform Limited Partnership
Act (the "Delaware Act") and that he otherwise acts in conformity with the
provisions of our partnership agreement, his liability under the Delaware Act
will be limited, subject to some possible exceptions, generally to the amount of
capital he is obligated to contribute to us in respect of his units plus his
share of any undistributed profits and assets.
Under the Delaware Act, a limited partnership may not make a distribution
to a partner to the extent that at the time of the distribution, after giving
effect to the distribution, all liabilities of the partnership, other than
liabilities to partners on account of their partnership interests and
liabilities for which the recourse of creditors is limited to specific property
of the partnership, exceed the fair value of the assets of
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<PAGE> 52
the limited partnership. For the purposes of determining the fair value of the
assets of a limited partnership, the Delaware Act provides that the fair value
of the property subject to liability of which recourse of creditors is limited
shall be included in the assets of the limited partnership only to the extent
that the fair value of that property exceeds the nonrecourse liability. The
Delaware Act provides that a limited partner who receives a distribution and
knew at the time of the distribution that the distribution was in violation of
the Delaware Act is liable to the limited partnership for the amount of the
distribution, for three years from the date of the distribution.
REPORTS AND RECORDS
As soon as practicable, but in no event later than 120 days after the close
of each fiscal year, our general partner will furnish each unitholder of record
(as of a record date selected by our general partner) an annual report
containing our audited financial statements for the past fiscal year. These
financial statements will be prepared in accordance with generally accepted
accounting principles. In addition, no later than 90 days after the close of
each quarter, (except the fourth quarter) our general partner will furnish each
unitholder of record (as of a record date selected by our general partner) a
report containing our unaudited financial statements and any other information
required by law.
Our general partner will use all reasonable efforts to furnish each
unitholder of record information reasonably required for tax reporting purposes
within 90 days after the close of each fiscal year. Our general partner's
ability to furnish this summary tax information will depend on the cooperation
of unitholders in supplying information to our general partner. Each unitholder
will receive information to assist him in determining his U.S. federal and state
and Canadian federal and provincial tax liability and filing his U.S. federal
and state and Canadian federal and provincial income tax returns.
A limited partner can, for a purpose reasonably related to the limited
partner's interest as a limited partner, upon reasonable demand and at his own
expense, have furnished to him:
- a current list of the name and last known address of each partner;
- a copy of our tax returns;
- information as to the amount of cash and a description and statement of
the agreed value of any other property or services, contributed or to be
contributed by each partner and the date on which each became a partner;
- copies of our partnership agreement, our certificate of limited
partnership, amendments to either of them and powers of attorney which
have been executed under our partnership agreement;
- information regarding the status of our business and financial condition;
and
- any other information regarding our affairs as is just and reasonable.
Our general partner may, and intends to, keep confidential from the limited
partners trade secrets or other information the disclosure of which our general
partner believes in good faith is not in our best interest or which we are
required by law or by agreements with third parties to keep confidential.
CASH DISTRIBUTION POLICY
One of our principal objectives is to generate cash from our operations and
to distribute cash to our partners each quarter. We are required to distribute
to our partners 100% of our available cash each quarter. Our available cash is
defined in our partnership agreement and is generally the sum of the cash we
receive in a quarter less cash disbursements, adjusted for net changes in
reserves.
During a subordination period the holders of our common units are entitled
to receive each quarter a minimum quarterly distribution of $0.475 per unit
($1.90 annualized) prior to any distribution of available cash to holders of our
subordinated units. The subordination period is defined generally as the period
that will end if we have distributed at least the minimum quarterly distribution
on all outstanding units each
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<PAGE> 53
quarter for four consecutive quarters and our adjusted available cash
constituting cash from operations, as defined in our partnership agreement, for
each of the last two quarters was at least 110% of the amount that would have
been sufficient to enable us to distribute the minimum quarterly distribution on
all outstanding units on a fully diluted basis.
During the subordination period, our cash is distributed first 98% to the
holders of common units and 2% to our general partner until there has been
distributed to the holders of common units an amount equal to the minimum
quarterly distribution. Any additional cash is distributed 98% to the holders of
subordinated units and 2% to our general partner until there has been
distributed to the holders of subordinated units an amount equal to the minimum
quarterly distribution. If the subordination period ends, the rights of the
holders of subordinated units will no longer be subordinated to the rights of
the holders of common units.
Our general partner is entitled to incentive distributions if the amount we
distribute with respect to any quarter exceeds levels specified in our
partnership agreement. Under the quarterly, incentive distribution provisions,
generally our general partner is entitled to 15% of amounts we distribute in
excess of $0.525 per common unit, 25% of amounts we distribute in excess of
$0.625 per common unit and 50% of amounts we distribute in excess of $0.725 per
common unit.
The minimum quarterly distribution and the amounts that trigger incentive
distributions at various levels are subject to adjustment, as described in our
partnership agreement. Our partnership agreement characterizes cash
distributions as either distributions of cash from operations or distributions
of cash from interim capital transactions. Generally, cash from operations
refers to cash generated by the operation of our business after deducting
related cash expenditures, reserves, debt service and other items specified in
our partnership agreement, and cash from interim capital transactions refers to
cash generated from borrowings, sales of debt and equity securities and sales or
other dispositions of assets for cash, with some exceptions. To avoid the
difficulty of trying to determine whether available cash distributed is cash
from operations or cash from interim capital transactions, our partnership
agreement provides that all cash distributed will be considered cash from
operations unless the amount distributed exceeds the cash generated from our
operations since June 30, 1995. Any excess will be considered cash from interim
capital transactions. We do not anticipate that we will distribute significant
amounts of cash from interim capital transactions, but if we do distribute cash
from interim capital transactions the distribution will be treated as a return
of capital, and the minimum quarterly distribution amount and the amounts that
trigger incentive distributions will be adjusted downward. In that case the
adjusted minimum quarterly distribution will be $0.475 multiplied by a fraction,
the numerator of which is the total per unit cash from interim capital
transactions distributed and the denominator of which is $20. The amounts that
trigger incentive distributions at various levels will also be adjusted to the
levels described above multiplied by the same fraction.
Enron has committed to contribute to us up to $29 million ($19.7 million of
which remains available) if necessary to support our ability to pay the minimum
quarterly distribution on our common units with respect to quarters ending on or
prior to December 31, 2001. In exchange for contributions under Enron's support
obligation, we will issue additional partnership interests that are not entitled
to cash distributions or voting rights. These additional partnership interests
must be redeemed by us, at Enron's option, with any available cash in excess of
the amount needed to pay the minimum quarterly distribution on all units plus
any arrearages in the minimum quarterly distribution on common units during the
subordination period. After Enron's obligation to provide distribution support
expires, actual quarterly distributions of available cash will depend solely on
our performance.
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<PAGE> 54
DESCRIPTION OF OUR PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of our partnership
agreement. Our partnership agreement and all amendments thereto have been filed
as exhibits to our Form 10-K. The following provisions of our partnership
agreement are summarized elsewhere in this prospectus:
- distributions of our available cash are described under "Cash
Distribution Policy;"
- allocations of taxable income and other tax matters are described under
"Tax Considerations;" and
- rights of holders of common units, are described under "Description of
Our Common Units."
PURPOSE
Our purpose under our partnership agreement is limited to serving as the
limited partner of our operating partnerships and engaging in any business
activities that may be engaged in by our operating partnership or that is
approved by our general partner. The partnership agreements of our operating
partnerships provide that they may engage in any activity that was engaged in by
our predecessors at the time of our initial public offering or reasonably
related thereto and any other activity approved by our general partner.
POWER OF ATTORNEY
Each limited partner, and each person who acquires a unit from a unitholder
and executes and delivers a transfer application, grants to our general partner
and, if appointed, a liquidator, a power of attorney to, among other things,
execute and file documents required for our qualification, continuance or
dissolution. The power of attorney also grants the authority for the amendment
of, and to make consents and waivers under, our partnership agreement.
CAPITAL CONTRIBUTIONS
Unitholders are not obligated to make additional capital contributions,
except as described below under "Description of Our Common Units -- Limited
Liability."
REIMBURSEMENT OF OUR GENERAL PARTNER
Our general partner does not receive any compensation for its services as
our general partner. It is, however, entitled to be reimbursed for all of its
costs incurred in managing and operating our business. Our partnership agreement
provides that our general partner will determine the expenses that are allocable
to us in any reasonable manner determined by our general partner in its sole
discretion.
ISSUANCE OF ADDITIONAL SECURITIES
Our partnership agreement authorizes us to issue an unlimited number of
additional limited partner interests and other equity securities that are equal
in rank with or junior to our common units on terms and conditions established
by our general partner in its sole discretion without the approval of any
limited partners. During the subordination period, however, except as set forth
in the following paragraph, we may not issue an aggregate of more than
approximately 10 million additional common units or an equivalent number of
units that are equal in rank with our common units, in each case, without the
approval of the holders of at least two-thirds of our outstanding common units.
During the subordination period, we may issue an unlimited number of common
units to finance an acquisition or a capital improvement that would have
resulted, on a pro forma basis, in an increase in per unit adjusted available
cash constituting cash from operations, as provided in our partnership
agreement.
In no event may we issue partnership interests that are senior to our
common units without the approval of the holders of at least two-thirds of our
outstanding common units.
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<PAGE> 55
It is possible that we will fund acquisitions through the issuance of
additional common units or other equity securities. Holders of any additional
common units we issue will be entitled to share equally with the then-existing
holders of common units in our cash distributions. In addition, the issuance of
additional partnership interests may dilute the value of the interests of the
then-existing holders of common units in our net assets.
In accordance with Delaware law and the provisions of our partnership
agreement, we may also issue additional partnership interests that, in the sole
discretion of our general partner, may have special voting rights to which
common units are not entitled.
Our general partner has the right, which it may from time to time assign in
whole or in part to any of its affiliates, to purchase common units,
subordinated units or other equity securities whenever, and on the same terms
that, we issue those securities to persons other than our general partner and
its affiliates, to the extent necessary to maintain their percentage interests
in us that existed immediately prior to the issuance. The holders of common
units will not have preemptive rights to acquire additional common units or
other partnership interests in us.
AMENDMENTS TO OUR PARTNERSHIP AGREEMENT
Amendments to our partnership agreement may be proposed only by our general
partner. In general, proposed amendments must be approved by holders of at least
two-thirds of our outstanding units. However, in some limited circumstances,
more particularly described in our partnership agreement, our general partner
may make amendments to our partnership agreement without the approval of our
limited partners or assignees.
Any amendment that materially and adversely affects the rights or
preferences of any type or class of limited partner interests in relation to
other types of classes of limited partner interest or our general partner
interest will require the approval of at least a majority of the type or class
of limited partner interest so affected (excluding any limited partner interests
held by our general partner or its affiliates).
WITHDRAWAL OR REMOVAL OF OUR GENERAL PARTNER
Except as described below, our general partner has agreed not to withdraw
voluntarily as our general partner prior to April 1, 2004 without obtaining the
approval of the holders of at least two-thirds of our outstanding units,
excluding those held by our general partner and its affiliates, and furnishing
an opinion of counsel regarding limited liability and tax matters. On or after
April 1, 2004, our general partner may withdraw as general partner without first
obtaining approval of any unitholder by giving 90 days' written notice, and that
withdrawal will not constitute a violation of our partnership agreement. In
addition, our general partner may withdraw without unitholder approval upon 90
days' notice to our limited partners if at least 50% of our outstanding common
units are held or controlled by one person and its affiliates other than our
general partner and its affiliates. In addition, our partnership agreement
permits our general partner in some limited instances to sell or otherwise
transfer all of its general partner interest without the approval of our
unitholders. There are no restrictions on Enron's ability to sell the capital
stock of our general partner.
Upon the withdrawal of our general partner under any circumstances, the
holders of a majority of our outstanding units (other than those owned by the
withdrawing general partner), may select a successor to that withdrawing general
partner. If a successor is not elected, or is elected but an opinion of counsel
regarding limited liability and tax matters cannot be obtained, we will be
dissolved, wound up and liquidated, unless within 180 days after that
withdrawal, the holders of a majority of our outstanding units agree in writing
to continue our business and to appoint a successor general partner.
Our general partner may not be removed unless that removal is approved by
the vote of the holders of not less than two-thirds of our outstanding units,
excluding units held by our general partner and its affiliates, and we receive
an opinion of counsel regarding limited liability and tax matters. Any removal
of this kind is also subject to the approval of a successor general partner by
the vote of the holders of a
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<PAGE> 56
majority of our outstanding units, excluding those held by our withdrawing
general partner and its affiliates.
Our partnership agreement also provides that if our general partner is
removed under circumstances where cause does not exist, the subordination period
will end, any outstanding additional partnership interests will be redeemable at
Enron's option and Enron's obligation to support distributions on common units
will terminate.
LIQUIDATION AND DISTRIBUTION OF PROCEEDS
Upon our dissolution, unless we are reconstituted and continued as a new
limited partnership, the person authorized to wind up our affairs (the
liquidator) will, acting with all the powers of our general partner that the
liquidator deems necessary or desirable in its good faith judgment, liquidate
our assets. The proceeds of the liquidation will be applied as follows: (i)
first, towards the payment of all of our creditors and the creation of a reserve
for contingent liabilities and (ii) then, to all partners in accordance with the
positive balance in the respective capital accounts. Under some circumstances
and subject to some limitations, the liquidator may defer liquidation or
distribution of our assets for a reasonable period of time. If the liquidator
determines that a sale would be impractical or would cause loss to the partners,
our general partner may distribute assets to partners in kind.
CHANGE OF MANAGEMENT PROVISIONS
Our partnership agreement contains specific provisions that are intended to
discourage a person or group from attempting to remove our general partner or
otherwise change management.
LIMITED CALL RIGHT
If at any time our general partner and its affiliates own 80% or more of
the issued and outstanding limited partner interests of any class, our general
partner will have the right to purchase all, but not less than all, of the
outstanding limited partner interests of that class that are held by
non-affiliated persons. The record date for determining ownership of the limited
partner interests would be selected by our general partner on at least 10 but
not more than 60 days' notice. The purchase price in the event of a purchase
under these provisions would be the greater of (i) the current market price (as
defined in our partnership agreement) of the limited partner interests of the
class as of the date five days prior to the mailing of written notice of its
election to purchase the units and (ii) the highest cash price paid by our
general partner or any of its affiliates for any limited partner interest of the
class purchased within the 90 days preceding the date our general partner mails
notice of its election to purchase the units.
INDEMNIFICATION
Under our partnership agreement, in most circumstances, we will indemnify
our general partner, its affiliates and their officers and directors to the
fullest extent permitted by law, from and against all losses, claims or damages
any of them may suffer by reason of their status as general partner, officer or
director, as long as the person seeking indemnity acted in good faith and in a
manner believed to be in or not opposed to our best interest. Any
indemnification under these provisions will only be out of our assets. Our
general partner shall not be personally liable for, or have any obligation to
contribute or loan funds or assets to us to enable us to effectuate
indemnification. We are authorized to purchase insurance against liabilities
asserted against and expenses incurred by persons for our activities, regardless
of whether we would have the power to indemnify the person against liabilities
under our partnership agreement.
REGISTRATION RIGHTS
Under our partnership agreement, we have agreed to register for resale
under the Securities Act and applicable state securities laws any common units,
subordinated units or other partnership securities proposed to be sold by our
general partner or any of its affiliates or their assignees if an exemption from
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the registration requirements is not otherwise available. We are obligated to
pay all expenses incidental to the registration, excluding underwriting
discounts and commissions.
TAX CONSIDERATIONS
This section is a summary of all of the material federal income tax
considerations that may be relevant to you and, to the extent set forth below
under "-- Legal Opinions and Advice," represents the opinion of our counsel
Vinson & Elkins L.L.P. ("Counsel"), insofar as it relates to matters of United
States federal income tax law and legal conclusions. This section is based upon
current provisions of the Internal Revenue Code of 1986 (the "Code"), existing
and proposed regulations thereunder and current administrative rulings and court
decisions, all of which are subject to change. Subsequent changes may cause the
tax consequences to vary substantially from the consequences described below.
We have made no attempt in the following discussion to comment on all
federal income tax matters affecting our unitholders or us. Moreover, the
discussion focuses on our unitholders who are individual citizens or residents
of the United States and has only limited application to corporations, estates,
trusts or non-resident aliens. Accordingly, you should consult, and should
depend on, your own tax advisor in analyzing the federal, state, local and
foreign tax consequences to you of the ownership or disposition of common units.
LEGAL OPINIONS AND ADVICE
Counsel has expressed its opinion that, based on the accuracy of
representations and subject to the qualifications set forth in the detailed
discussion that follows, for federal income tax purposes: we and our operating
limited partnerships will each be treated as a partnership; and owners of common
units (with some exceptions, as described in "-- Limited Partner Status" below)
will be treated as our partners (but not partners of the operating limited
partnerships). In addition, all statements as to matters of law and legal
conclusions contained in this section, unless otherwise noted, reflect the
opinion of Counsel. Counsel has also advised us that, based on current law, the
following general description of the principal federal income tax consequences
that should arise from the ownership and disposition of common units, insofar as
it relates to matters of law and legal conclusions, addresses all material tax
consequences to our unitholders who are individual citizens or residents of the
United States.
We have not requested any ruling from the Internal Revenue Service (the
"IRS") with respect to the foregoing issues or any other matter affecting our
unitholders or us. An opinion of counsel represents only counsel's best legal
judgment and does not bind the IRS or the courts. Thus, we cannot assure you
that the opinions and statements set forth in this prospectus would be sustained
by a court if contested by the IRS. The costs of any contest with the IRS will
be borne directly or indirectly by our unitholders and our general partner.
Furthermore, we cannot assure you that our treatment or an investment in us will
not be significantly modified by future legislative or administrative changes or
court decisions. Any modification may or may not be retroactively applied.
PARTNERSHIP STATUS
A partnership is not a taxable entity and incurs no federal income tax
liability. Instead, each partner is required to take into account his allocable
share of items of our income, gain, loss, deduction and credit in computing his
federal income tax liability, regardless of whether cash distributions are made.
Distributions by us to a unitholder are generally not taxable unless the amount
of any cash distributed is in excess of his adjusted basis in his partnership
interest.
Pursuant to certain Treasury Regulations effective January 1, 1997 (the
"Check-the-Box Regulations"), an entity in existence on January 1, 1997, will
generally retain its current classification for federal income tax purposes. As
of January 1, 1997, each of our operating limited partnerships and we were
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classified and taxed as a partnership. Pursuant to the Check-the-Box
Regulations, this prior classification will be respected for all periods prior
to January 1, 1997, if:
- the entity had a reasonable basis for the claimed classification;
- the entity recognized the federal tax consequences of any change in
classification within five years prior to January 1, 1997; and
- the entity was not notified prior to May 8, 1996 that the entity
classification was under examination.
Based on these regulations and the applicable federal income tax law, Counsel
has opined that we and each of our operating limited partnerships have been and
will be classified as a partnership for federal income tax purposes. In
rendering its opinion, Counsel has relied on factual representations and
covenants made by our general partner and us:
- neither we nor any of our operating limited partnerships have elected or
will elect to be treated as an association taxable as a corporation;
- except as otherwise required by Section 704 of the Code and regulations
promulgated thereunder, our general partner has had and will have, in the
aggregate, an interest in each material item of our income, gain, loss,
deduction or credit equal to at least 1% at all times during our
existence;
- a representation and covenant of our general partner that our general
partner has and will maintain, in the aggregate, a minimum capital
account balance in us equal to 1% of our total positive capital account
balances;
- for each taxable year, less than 10% of our gross income has been and
will be derived from sources other than (i) the exploration, development,
mining or production, processing, refining, transportation or marketing
of any mineral or natural resource, including oil, gas or products
thereof and naturally occurring carbon dioxide or (ii) other items of
income as to which Counsel has opined or will opine will be "qualifying
income" within the meaning of Section 7704(d) of the Code; and
- we and each of our operating limited partnerships are organized and will
be operated in accordance with (i) all applicable partnership statutes,
(ii) its or our respective partnership agreement and (iii) its or our
description in this Registration Statement.
Counsel's opinion as to our partnership classification in the event of a change
in our general partner is based upon the assumption that the new general partner
will satisfy the foregoing representations and covenants.
Section 7704 of the Code provides that publicly-traded partnerships will,
as a general rule, be taxed as corporations. However, an exception (the "Natural
Resource Exception") exists with respect to publicly-traded partnerships 90% or
more of the gross income of which for every taxable year consists of "qualifying
income." Qualifying income includes income and gains derived from the
transportation and trading of oil and petroleum products and natural gas
processing as conducted by us. Other types of qualifying income include interest
(from other than a financial business), dividends, gains from the sale of real
property and gains from the sale or other disposition of capital assets held for
the production of income that otherwise constitutes qualifying income. We
estimate that less than 5% of our gross income is not qualifying income under
this test; however, this estimate could change from time to time. Based upon and
subject to that estimate, the factual representations made by us and the general
partner and a review of the applicable legal authorities, Counsel is of the
opinion that at least 95% of our gross income constitutes qualifying income.
If we fail to meet the Natural Resource Exception (other than a failure
determined by the IRS to be inadvertent that is cured within a reasonable time
after discovery), we will be treated as if we had transferred all of our assets
(subject to liabilities) to a newly-formed corporation (on the first day we fail
to meet the Natural Resource Exception) in return for stock in the corporation,
and then distributed the stock to our unitholders in liquidation of their
interests in us. This contribution and liquidation should be
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tax-free to our unitholders and us, so long as we, at such time, do not have
liabilities in excess of the basis of our assets. Thereafter, we would be
treated as a corporation for federal income tax purposes.
If we were treated as an association or otherwise taxable as a corporation
in any taxable year, as a result of a failure to meet the Natural Resource
Exception or otherwise, our items of income, gain, loss, deduction and credit
would be reflected only on our tax return rather than being passed through to
our unitholders, and our net income would be taxed at the entity level at
corporate rates. In addition, any distribution made to our unitholders would be
treated as either taxable dividend income (to the extent of our current or
accumulated earnings and profits), in the absence of earnings and profits as a
nontaxable return of capital (to the extent of his basis in his common units) or
taxable capital gain (after his basis in the common units is reduced to zero).
Accordingly, our treatment as an association taxable as a corporation would
result in a material reduction in a unitholder's cash flow and after-tax return.
The discussion below is based on the assumption that we will be classified
as a partnership for federal income tax purposes.
LIMITED PARTNER STATUS
Our unitholders who have become limited partners will be treated as
partners for federal income tax purposes. Moreover, the IRS has ruled that
assignees of partnership interests who have not been admitted to a partnership
as partners, but who have the capacity to exercise substantial dominion and
control over the assigned partnership interests, will be treated as partners for
federal income tax purposes. On the basis of this ruling, except as otherwise
described herein, Counsel is of the opinion that (a) assignees who have executed
and delivered Transfer Applications and are awaiting admission as limited
partners and (b) our unitholders whose common units are held in street name or
by a nominee and who have the right to direct the nominee in the exercise of all
substantive rights attendant to the ownership of their common units will be
treated as partners for federal income tax purposes. As this ruling does not
extend, on its facts, to assignees of common units who are entitled to execute
and deliver Transfer Applications and thereby become entitled to direct the
exercise of attendant rights, but who fail to execute and deliver Transfer
Applications, Counsel's opinion does not extend to these persons. Income, gain,
deductions, losses or credits would not appear to be reportable by these
unitholders, and any cash distributions received by these unitholders would
therefore be fully taxable as ordinary income. These holders should consult
their own tax advisors with respect to their status as partners for federal
income tax purposes. A purchaser or other transferee of common units who does
not execute and deliver a Transfer Application may not receive federal income
tax information or reports furnished to record holders of common units unless
the common units are held in a nominee or street name account and the nominee or
broker has executed and delivered a Transfer Application with respect to the
common units.
A beneficial owner of common units whose common units have been transferred
to a short seller to complete a short sale would appear to lose his status as a
partner for federal income tax purposes with respect to the common units sold
short. See "-- Tax Treatment of Our Operations -- Treatment of Short Sales."
TAX CONSEQUENCES OF COMMON UNIT OWNERSHIP
Flow-Through Of Taxable Income
We will pay no federal income tax. Instead, each of our unitholders will be
required to report on his income tax return his allocable share of our income,
gains, losses and deductions without regard to whether corresponding cash
distributions are received by him. Consequently, we may allocate income to our
unitholders although they have not received a cash distribution in respect of
that income.
Treatment Of Partnership Distributions
Our distributions to any of our unitholders will not be taxable for federal
income tax purposes to the extent of his basis in his common units immediately
before the distribution. Cash distributions in excess of
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a common unitholder's basis generally will be considered to be gain from the
sale or exchange of the common units, taxable in accordance with the rules
described under "-- Tax Consequences of Common Unit Ownership -- Disposition of
Common Units." Any reduction in a common unitholder's share of our liabilities
for which no partner, including our general partner, bears the economic risk of
loss ("nonrecourse liabilities") will be treated as a distribution of cash to
that unitholder.
Basis Of Common Units
A unitholder's initial tax basis for his common units will be the amount
paid for the common unit plus his share of our nonrecourse liabilities. The
initial tax basis for a common unit will be increased by the unitholder's share
of our income and by any increase in the unitholder's share of our nonrecourse
liabilities. The basis for a common unit will be decreased (but not below zero)
by our distributions, including any decrease in the unitholder's share of our
nonrecourse liabilities, by the unitholder's share of our losses and by the
unitholder's share of our expenditures that are not deductible in computing his
taxable income and are not required to be capitalized. A unitholder's share of
our nonrecourse liabilities will be generally based on the unitholder's share of
our profits.
Limitations On Deductibility Of Our Losses
To the extent we incur losses, a unitholder's share of deductions for the
losses will be limited to the tax basis of the unitholder's common units or, in
the case of an individual unitholder or a corporate unitholder if more than 50%
of the value of his stock is owned directly or indirectly by five or fewer
individuals or some tax-exempt organizations, to the amount that the unitholder
is considered to be "at risk" with respect to our activities, if that is less
than the unitholder's basis. A unitholder must recapture losses deducted in
previous years to the extent that our distributions cause the unitholder's at
risk amount to be less than zero at the end of any taxable year. Losses
disallowed to a unitholder or recaptured as a result of these limitations will
carry forward and will be allowable to the extent that the unitholder's basis or
at risk amount (whichever is the limiting factor) is increased.
In general, a unitholder will be at risk to the extent of the purchase
price of his common units, but this will be less than the unitholder's basis for
his common units by the amount of the unitholder's share of any of our
nonrecourse liabilities. A unitholder's at risk amount will increase or decrease
as the basis of the unitholder's common units increases or decreases except that
changes in our nonrecourse liabilities will not increase or decrease the at risk
amount.
The passive loss limitations generally provide that individuals, estates,
trusts and some closely held corporations and personal service corporations can
only deduct losses from passive activities (generally, activities in which the
taxpayer does not materially participate) that are not in excess of the
taxpayer's income from passive activities or investments. The passive loss
limitations are applied separately with respect to each publicly-traded
partnership. Consequently, any losses generated by us will only be available to
offset future income that we generate and will not be available to offset income
from other passive activities or investments (including other publicly-traded
partnerships) or salary or active business income. Passive losses that are not
deductible because they exceed the unitholder's income that we generate may be
deducted in full when the unitholder disposes of his entire investment in us in
a fully taxable transaction to an unrelated party. The passive activity loss
rules are applied after other applicable limitations on deductions such as the
at risk rules and the basis limitation.
A unitholder's share of our net income may be offset by any of our
suspended passive losses, but it may not be offset by any other current or
carryover losses from other passive activities, including those attributable to
other publicly-traded partnerships. The IRS has announced that Treasury
Regulations will be issued that characterize net passive income from a
publicly-traded partnership as investment income for purposes of the limitations
on the deductibility of investment interest.
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Limitations On Interest Deductions
The deductibility of a non-corporate taxpayer's "investment interest
expense" is generally limited to the amount of the taxpayer's "net investment
income." As noted, a unitholder's share of our net passive income will be
treated as investment income for this purpose. In addition, the unitholder's
share of our portfolio income will be treated as investment income. Investment
interest expense includes:
- interest on indebtedness properly allocable to property held for
investment;
- our interest expense attributed to portfolio income; and
- the portion of interest expense incurred to purchase or carry an interest
in a passive activity to the extent attributable to portfolio income.
The computation of a unitholder's investment interest expense will take
into account interest on any margin account borrowing or other loan incurred to
purchase or carry a common unit to the extent attributable to his portfolio
income. Net investment income includes gross income from property held for
investment, gain attributable to the disposition of property held for investment
and amounts treated as portfolio income pursuant to the passive loss rules less
deductible expenses (other than interest) directly connected with the production
of investment income.
Allocation Of Our Income, Gain, Loss And Deduction
Our partnership agreement provides that a capital account be maintained for
each partner, that the capital accounts generally be maintained in accordance
with the applicable tax accounting principles set forth in applicable Treasury
Regulations and that all allocations to a partner be reflected by an appropriate
increase or decrease in his capital account. Distributions upon our liquidation
are generally to be made in accordance with positive capital account balances.
In general, if we have a net profit, items of income, gain, loss and
deduction will be allocated among our general partner and our unitholders in
accordance with their respective percentage interests in us. A class of our
unitholders that receives more cash than another class, on a per unit basis,
with respect to a year, will be allocated additional income equal to that
excess. If we have a net loss, items of income, gain, loss and deduction will
generally be allocated for both book and tax purposes (1) first, to our general
partner and our unitholders in accordance with their respective percentage
interests to the extent of their positive capital accounts and (2) second, to
our general partner.
Notwithstanding the above, as required by Section 704(c) of the Code, some
items of our income, deduction, gain and loss will be specially allocated to
account for the difference between the tax basis and fair market value of
property contributed to us ("Contributed Property") or owned by us at the time
new units are sold by us ("Adjusted Property"). In addition, some items of
recapture income will be allocated to the extent possible to the partner
allocated the deduction giving rise to the treatment of the gain as recapture
income in order to minimize the recognition of ordinary income by some of our
unitholders. Although we believe that these allocations will be respected under
recently adopted Treasury Regulation, if they are not respected, the amount of
the income or gain allocated to a unitholder will not change, but instead a
change in the character of the income allocated to a unitholder would result.
Finally, although we do not expect that our operations will result in the
creation of negative capital accounts, if negative capital accounts nevertheless
result, items of our income and gain will be allocated in an amount and manner
sufficient to eliminate the negative balance as quickly as possible.
Regulations provide that an allocation of items of our income, gain, loss,
deduction or credit, other than an allocation required by Section 704(c) of the
Code to eliminate the disparity between a partner's "book" capital account
(credited with the fair market value of Contributed Property and credited or
debited with any gain or loss attributable to an Adjusted Property) and "tax"
capital account (credited with the tax basis of Contributed Property) (the
"Book-Tax Disparity"), will generally be given effect for federal income tax
purposes in determining a partner's distributive share of an item of income,
gain, loss or deduction only if the allocation has substantial economic effect.
In any other case, a partner's distributive
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share of an item will be determined on the basis of the partner's interest in
us, which will be determined by taking into account all the facts and
circumstances, including the partner's relative contributions to us, the
interests of the partners in economic profits and losses, the interests of the
partners in cash flow and other non-liquidating distributions and rights of the
partners to distributions of capital upon liquidation.
Under the Code, the partners in a partnership cannot be allocated more
depreciation, gain or loss than the total amount of the item recognized by that
partnership in a particular taxable period. This rule, often referred to as the
"ceiling limitation," is not expected to have significant application to
allocations with respect to Contributed Properties or Adjusted Properties and
thus, is not expected to prevent our unitholders from receiving allocations of
depreciation, gain or loss from our properties equal to that which they would
have received had our properties actually had a basis equal to fair market value
at the outset or at the time new units are issued by us. However, to the extent
the ceiling limitation is or becomes applicable, our partnership agreement
requires that some items of income and deduction be allocated in a way designed
to effectively "cure" this problem and eliminate the impact of the ceiling
limitations. These allocations will not have substantial economic effect because
they will not be reflected in the capital accounts of our unitholders.
The legislative history of Section 704(c) states that Congress anticipated
that Treasury Regulations would permit partners to agree to a more rapid
elimination of Book-Tax Disparities than required provided there is no tax
avoidance potential. Further, under Treasury Regulations under Section 704(c),
allocations similar to the curative allocations would be allowed. However, since
the final Treasury Regulations are not applicable to us, Counsel is unable to
opine on the validity of the curative allocations.
Counsel is of the opinion that, with the exception of curative allocations
and the allocation of recapture income discussed above and the deduction for
amortizable goodwill discussed below (see "-- Tax Treatment of Our
Operations -- Initial Tax Basis, Depreciation and Amortization"), allocations
under our partnership agreement will be given effect for federal income tax
purposes in determining a partner's distributive share of an item of income,
gain, loss or deduction. There are, however, uncertainties in the Treasury
Regulations relating to allocations of partnership income, and investors should
be aware that some of the allocations in our partnership agreement may be
successfully challenged by the IRS.
Tax Treatment Of Our Operations
Accounting Method and Taxable Year
We use the calendar year as our taxable year and adopt the accrual method
of accounting for federal income tax purposes.
Initial Tax Basis, Depreciation and Amortization
The tax basis established for our various assets will be used for purposes
of computing depreciation and cost recovery deductions and, ultimately, gain or
loss on the disposition of those assets. Our assets initially had an aggregate
tax basis equal to the sum of each unitholder's tax basis in his common units or
subordinated units and the tax basis of our general partner in its general
partner interest.
The IRS may challenge the method adopted by us to allocate this aggregate
tax basis among our assets and our treatment of certain amortizable intangible
assets. The IRS may (i) challenge either the fair market values or the useful
lives assigned to our assets or (ii) seek to characterize intangible assets as
non-amortizable goodwill. If the challenge or characterization were successful,
the deductions allocated to a common unitholder in respect of our assets would
be reduced, and a unitholder's share of taxable income received from us would be
increased accordingly. Any increase could be material.
To the extent allowable, our general partner may elect to use the
depreciation and cost recovery methods that will result in the largest
depreciation deductions in our early years. Property that we subsequently
acquire or construct may be depreciated using accelerated methods permitted by
the Code.
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If we dispose of depreciable property by sale, foreclosure or otherwise,
all or a portion of any gain (determined by reference to the amount of
depreciation previously deducted and the nature of the property) may be subject
to the recapture rules and taxed as ordinary income rather than capital gain.
Similarly, a partner who has taken cost recovery or depreciation deductions with
respect to property owned by us may be required to recapture deductions upon a
sale of his interest. See "-- Tax Consequences of Common Unit
Ownership -- Allocation of Our Income, Gain, Loss and Deduction" and "-- Tax
Consequences of Common Unit Ownership -- Disposition of Common
Units -- Recognition of Gain or Loss."
Costs we incurred in organizing may be amortized over any period we select
not shorter than 60 months. The costs incurred in promoting the issuance of
units must be capitalized and cannot be deducted currently, ratably or upon our
termination. There are uncertainties regarding the classification of costs as
organization expenses, that may be amortized, and as syndication expenses which
may not be amortized.
Section 754 Election
We previously made the election permitted by Section 754 of the Code. This
election is irrevocable without the consent of the IRS. The election generally
permits a purchaser of common units to adjust his share of the basis in our
properties ("inside basis") pursuant to Section 743(b) of the Code to fair
market value (as reflected by his common unit price). See "Tax
Considerations -- Allocation of Our Income, Gain, Loss and Deduction." The
Section 743(b) adjustment is attributed solely to a purchaser of units and is
not added to the basis of our assets associated with all of our unitholders.
(For purposes of this discussion, a partner's inside basis in our assets will be
considered to have two components: (1) his share of our actual basis in our
assets (the "Common Basis"); and (2) his Section 743(b) adjustment allocated to
each of our assets.)
Proposed Treasury Regulation Section 1.197-2(g)(3) generally requires that
the 743(b) adjustment attributable to amortizable intangible assets under
Section 197 should be treated as a newly-acquired asset placed in service on the
date when the transfer occurs. Under Treasury Regulation Section 1.167(c)-
1(a)(6), a Section 743(b) adjustment attributable to property subject to
depreciation under Section 167 of the Code rather than cost recovery deductions
under Section 168 is generally required to be depreciated using either the
straight-line method or the 150% declining balance method. We intend to utilize
the 150% declining balance method on our property subject to depreciation under
Section 167. Although the proposed regulations under Section 743 will likely
eliminate many of the problems if finalized in their current form, the
depreciation method and useful lives associated with the Section 743(b)
adjustment may differ from the method and useful lives generally used to
depreciate the Common Basis in our properties. Pursuant to our partnership
agreement, our general partner is authorized to adopt a convention to preserve
the uniformity of common units even if that convention is not consistent with
Treasury Regulation Section 1.167(c)-1(a)(6) or 1.197-2(g)(3). See "-- Tax
Consequences of Common Unit Ownership -- Uniformity of Common Units."
Although Counsel is unable to opine as to the validity of this approach, we
intend to depreciate the portion of a Section 743(b) adjustment attributable to
unrealized appreciation in the value of Contributed Property or Adjusted
Property (to the extent of any unamortized Book-Tax Disparity) using a rate of
depreciation or amortization derived from the depreciation or amortization
method and useful life applied to the Common Basis of our property. This method
is consistent with the proposed regulations under Section 743 but is arguably
inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6) or Proposed
Treasury Regulation Section 1.197-2(g)(3). To the extent that the Section 743(b)
adjustment is attributable to appreciation in value in excess of the unamortized
Book-Tax Disparity, we will apply the rules described in the Treasury
Regulations and legislative history. If we determine that this position cannot
reasonably be taken, we may adopt a depreciation or amortization convention
under which all purchasers acquiring common units in the same month would
receive depreciation or amortization, whether attributable to the Common Basis
or the Section 743(b) basis, based upon the same applicable rate as if they had
purchased a direct interest in our property. This aggregate approach may result
in lower
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annual depreciation or amortization deductions than would otherwise be allowable
to some of our unitholders. See "-- Tax Consequences of Common Unit
Ownership -- Uniformity of Common Units."
The allocation of the Section 743(b) adjustment must be made in accordance
with the principles of Section 1060 of the Code. Based on these principles, the
IRS may seek to reallocate some or all of any Section 743(b) adjustment not so
allocated by us to goodwill. Alternatively, it is possible that the IRS may seek
to treat the portion of the Section 743(b) adjustment attributable to the
Underwriter's discount as if allocable to a non-deductible syndication cost.
A Section 754 election is advantageous if the transferee's basis in his
common units is higher than his common units' share of the aggregate basis of
our assets immediately prior to the transfer. In that case, pursuant to the
election, the transferee would take a new and higher basis in his share of our
assets for purposes of calculating, among other items, his depreciation
deductions and his share of any gain or loss on a sale of our assets.
Conversely, a Section 754 election is disadvantageous if the transferee's basis
in his common units is lower than his common units' share of the aggregate basis
of our assets immediately prior to the transfer. Thus, the amount that a
unitholder will be able to obtain upon the sale of his common units may be
affected either favorably or adversely by the election.
The calculations involved in the Section 754 election are complex and we
will make them on the basis of some assumptions as to the value of our assets
and other matters. There is no assurance that the determinations we make will
not be successfully challenged by the IRS and that the deductions attributable
to them will not be disallowed or reduced. Should the IRS require a different
basis adjustment to be made, and should, in our general partner's opinion, the
expense of compliance exceed the benefit of the election, our general partner
may seek permission from the IRS to revoke our Section 754 election. If
permission is granted, a purchaser of common units subsequent to the revocation
probably will incur increased tax liability.
Alternative Minimum Tax
Each unitholder will be required to take into account his distributive
share of any items of our income, gain or loss for purposes of the alternative
minimum tax. A portion of our depreciation deductions may be treated as an item
of tax preference for this purpose.
A unitholder's alternative minimum taxable income derived from us may be
higher than his share of our net income because we may use more accelerated
methods of depreciation for purposes of computing federal taxable income or
loss. The minimum tax rate for individuals is 26% on the first $175,000 of
alternative minimum taxable income in excess of the exemption amount and to 28%
on any additional alternative minimum taxable income. You should consult with
your tax advisors as to the impact of an investment in common units on your
liability under the alternative minimum tax.
Valuation of Our Property
The federal income tax consequences of the ownership and disposition of
common units will depend in part on our estimates of the relative fair market
values, and determinations of the initial tax basis, of our assets. Although we
may from time to time consult with professional appraisers with respect to
valuation matters, many of the relative fair market value estimates will be made
solely by us. These estimates are subject to challenge and will not be binding
on the IRS or the courts. In the event the determinations of fair market value
are subsequently found to be incorrect, the character and amount of items of
income, gain, loss, deductions or credits previously reported by our unitholders
might change, and our unitholders might be required to amend their previously
filed tax returns or to file claims for refunds.
Treatment of Short Sales
A unitholder who engages in a short sale (or a transaction having the same
effect) with respect to common units will be required to recognize the gain (but
not the loss) inherent in the common units that are sold short. See "-- Tax
Consequences of Common Unit Ownership -- Disposition of Common Units."
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In addition, it would appear that a unitholder whose common units are loaned to
a "short seller" to cover a short sale of common units would be considered as
having transferred beneficial ownership of those common units and would, thus,
no longer be a partner with respect to those common units during the period of
the loan. As a result, during this period, any of our income, gain, deduction,
loss or credit with respect to those common units would appear not to be
reportable by the unitholder, any cash distributions received by the unitholder
with respect to those common units would be fully taxable and all of those
distributions would appear to be treated as ordinary income. The IRS may also
contend that a loan of common units to a "short seller" constitutes a taxable
exchange. If the IRS successfully made this contention, the lending unitholder
may be required to recognize gain or loss. Unitholders desiring to assure their
status as partners should modify any of their brokerage account agreements to
prohibit their brokers from borrowing their common units.
Disposition Of Common Units
Recognition of Gain or Loss
Gain or loss will be recognized on a sale of common units equal to the
difference between the amount realized and the unitholder's tax basis for the
common units sold. A unitholder's amount realized will be measured by the sum of
the cash or the fair market value of other property received plus his share of
our nonrecourse liabilities. Since the amount realized includes a unitholder's
share of our nonrecourse liabilities, the gain recognized on the sale of common
units may result in a tax liability in excess of any cash received from the
sale.
Gain or loss recognized by a unitholder (other than a "dealer" in common
units) on the sale or exchange of a common unit held for more than twelve months
will generally be taxable as long-term capital gain or loss. A substantial
portion of this gain or loss, however, will be separately computed and taxed as
ordinary income or loss under section 751 of the Code to the extent attributable
to assets giving rise to depreciation recapture or other "unrealized
receivables" or to inventory we own. The term "unrealized receivables" includes
potential recapture items, including depreciation recapture. Ordinary income
attributable to unrealized receivables, inventory and deprecation recapture may
exceed net taxable gain realized upon the sale of the common unit and may be
recognized even if there is a net taxable loss realized upon the sale of the
common unit. Any loss recognized on the sale of common units will generally be a
capital loss. Thus, a unitholder may recognize both ordinary income and a
capital loss upon a disposition of common units. Net capital loss may offset no
more than $3,000 of ordinary income in the case of individuals and may only be
used to offset capital gain in the case of a corporation.
The IRS has ruled that a partner acquiring interests in a partnership in
separate transactions at different prices must maintain an aggregate adjusted
tax basis in a single partnership interest and that, upon sale or other
disposition of some of the interests, a portion of the aggregate tax basis must
be allocated to the interests sold on the basis of some equitable apportionment
method. This ruling is unclear as to how the holding period is affected by this
aggregation concept. If this ruling is applicable to you, the aggregation of
your tax basis effectively prohibits you from choosing among common units with
varying amounts of unrealized gain or loss as would be possible in a stock
transaction. Thus, the ruling may result in an acceleration of gain or deferral
of loss on a sale of a portion of your common units. It is not clear whether the
ruling applies to publicly-traded partnerships, such as us, the interests in
which are evidenced by separate interests, and accordingly Counsel is unable to
opine as to the effect this ruling will have on you. If you are considering the
purchase of additional common units or a sale of common units purchased at
differing prices, you should consult your tax advisor as to the possible
consequences of this ruling.
Allocations Between Transferors and Transferees
In general, our taxable income and losses will be determined annually and
will be prorated on a monthly basis and subsequently apportioned among our
unitholders in proportion to the number of common units they owned as of the
close of business on the last day of the preceding month. However, gain or loss
realized on a sale or other disposition of our assets other than in the ordinary
course of
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business will be allocated among our unitholders of record as of the opening of
the New York Stock Exchange on the first business day of the month in which the
gain or loss is recognized. As a result of this allocation procedure, a
unitholder transferring common units in the open market may be allocated income,
gain, loss, deduction, and credit accrued after the transfer.
The use of the allocation procedure discussed above may not be permitted by
existing Treasury Regulations and, accordingly, Counsel is unable to opine on
the validity of the method of allocating income and deductions between the
transferors and the transferees of common units. If an allocation procedure is
not allowed by the Treasury Regulations (or only applies to transfers of less
than all of a unitholder's interest), our taxable income or losses might be
reallocated among our unitholders. We are authorized to revise our method of
allocation between transferors and transferees (as well as among partners whose
interests otherwise vary during a taxable period) to conform to a method
permitted by future Treasury Regulations.
A unitholder who owns common units at any time during a quarter and who
disposes of his common units prior to the record date set for a distribution
with respect to that quarter will be allocated items of our income and gain
attributable to the quarter during which his common units were owned but will
not be entitled to receive cash distributions with respect to that quarter.
Notification Requirements
A unitholder who sells or exchanges common units is required to notify us
in writing of the sale or exchange within 30 days of the sale or exchange and,
in any event, no later than January 15 of the year following the calendar year
that the sale or exchange occurred. We are required to notify the IRS of the
transaction and to furnish specific information to the transferor and
transferee. However, these reporting requirements do not apply with respect to a
sale by an individual who is a citizen of the United States and who effects the
sale through a broker. Additionally, a transferor and a transferee of a common
unit will be required to furnish statements to the IRS, filed with their income
tax returns for the taxable year in which the sale or exchange occurred, that
set forth the amount of the consideration received for the common unit that is
allocated to our goodwill or going concern value. Failure to satisfy these
reporting obligations may lead to the imposition of substantial penalties.
Constructive Termination
We will be considered to be terminated if there is a sale or exchange of
50% or more of the total interests in partnership capital and profits within a
12-month period. A constructive termination results in the closing of a
partnership's taxable year for all partners. A termination could result in the
non-uniformity of common units for federal income tax purposes. Our constructive
termination will cause a termination of our operating limited partnerships. A
termination could also result in penalties or loss of basis adjustments under
the Code if we were unable to determine that the termination had occurred.
In the case of a unitholder reporting on a fiscal year other than a
calendar year, the closing of our tax year may result in more than 12 months of
our taxable income or loss being includable in our taxable income for the year
of termination. In addition, each unitholder will realize taxable gain to the
extent that any money constructively distributed to him (including any net
reduction in his share of partnership nonrecourse liabilities) exceeds the
adjusted basis on his common units. New tax elections we are required to make,
including a new election under Section 754 of the Code, must be made subsequent
to the constructive termination. A constructive termination would also result in
a deferral of our deductions for depreciation. In addition, a termination might
either accelerate the application of or subject us to any tax legislation
enacted with effective dates after the closing of the offering made hereby.
Entity Level Collections
If we are required under applicable law to pay any federal, state or local
income tax on behalf of any unitholder, our general partner or any former
unitholder, we are authorized to pay those taxes from our funds. The payments,
if made, will be deemed current distributions of cash to our unitholders and our
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general partner. Our general partner is authorized to amend our partnership
agreement in the manner necessary to maintain uniformity of intrinsic tax
characteristics of common units and to adjust subsequent distributions so that
after giving effect to the deemed distributions, the priority and
characterization of distributions otherwise applicable under our partnership
agreement is maintained as nearly as is practicable. These payments could give
rise to an overpayment of tax on behalf of an individual partner in which event
the partner could file a claim for credit or refund.
Uniformity Of Common Units
Since we cannot match transferors and transferees of common units,
uniformity of the economic and tax characteristics of the common units to a
purchaser of common units must be maintained. In the absence of uniformity,
compliance with a number of federal income tax requirements, both statutory and
regulatory, could be substantially diminished. A lack of uniformity can result
from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6) or
Proposed Treasury Regulation Section 1.197-2(g)(3) and from the application of
the "ceiling limitation" on our ability to make allocations to eliminate Book-
Tax Disparities attributable to Contributed Properties and Adjusted Properties.
Any non-uniformity could have a negative impact on the value of a unitholder's
interest in us.
We intend to depreciate the portion of a Section 743(b) adjustment
attributable to unrealized appreciation in the value of Contributed Property or
Adjusted Property (to the extent of any unamortized Book-Tax Disparity) using
the rate of depreciation derived from the depreciation method and useful life
applied to the Common Basis of our property, consistent with the proposed
regulations under Section 743, but despite its inconsistency with Treasury
Regulation Section 1.167(c)-1(a)(6) or Proposed Treasury Regulation Section
1.197-2(g)(3). See "-- Tax Consequences of Common Stock Ownership -- Tax
Treatment of Operations -- Section 754 Election." To the extent that the Section
743(b) adjustment is attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules described in the
Treasury Regulation and legislative history. If we determine that this position
cannot reasonably be taken, we may adopt depreciation and amortization
conventions under which all purchasers acquiring common units in the same month
would receive depreciation and amortization deductions, whether attributable to
the Common Basis or the Section 743(b) basis, based upon the same applicable
rate as if they had purchased a direct interest in our property. If this
aggregate approach is adopted, it may result in lower annual depreciation and
amortization deductions than would otherwise be allowable to some of our
unitholders and risk the loss of depreciation and amortization deductions not
taken in the year that the deductions are otherwise allowable. We will not adopt
this convention if we determine that the loss of depreciation and amortization
deductions will have a material adverse effect on our unitholders. If we choose
not to utilize this aggregate method, we may use any other reasonable
depreciation and amortization convention to preserve the uniformity of the
intrinsic tax characteristics of any common units that would not have a material
adverse effect on our unitholders. The IRS may challenge any method of
depreciating or amortizing the Section 743(b) adjustment described in this
paragraph. If this challenge were sustained, the uniformity of common units
might be affected.
Items of income and deduction will be specially allocated in a manner that
is intended to preserve the uniformity of intrinsic tax characteristics among
all common units, despite the application of the "ceiling limitation" to
Contributed Properties and Adjusted Properties. These special allocations will
be made solely for federal income tax purposes. See "-- Tax Consequences of
Common Unit Ownership" and "-- Tax Consequences of Common Unit
Ownership -- Allocation of Our Income, Gain, Loss and Deduction."
Tax-Exempt Organizations And Some Other Investors
Ownership of common units by employee benefit plans, other tax-exempt
organizations, non-resident aliens, foreign corporations, other foreign persons
and regulated investment companies raises issues unique to these persons and, as
described below, may have substantially adverse tax consequences.
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Employee benefit plans and most other organizations exempt from federal
income tax (including individual retirement accounts and other retirement plans)
are subject to federal income tax on unrelated business taxable income.
Virtually all of the taxable income derived by these organizations from the
ownership of common units will be unrelated business taxable income, and thus
will be taxable to these unitholders.
Regulated investment companies are required to derive 90% or more of their
gross income from interest, dividends, gains from the sale of stocks or
securities or foreign currency or some related sources. It is not anticipated
that any significant amount of our gross income will qualify as income from
these sources.
Non-resident aliens and foreign corporations, trusts or estates that
acquire common units will be considered to be engaged in business in the United
States on account of their ownership of common units, and as a consequence they
will be required to file federal tax returns in respect of their distributive
shares of our income, gain, loss deduction or credit and pay federal income tax
at regular rates on our income. Generally, a partnership is required to pay a
withholding tax on the portion of the Partnership's income that is effectively
connected with the conduct of a United States trade or business and which is
allocable to the foreign partners, regardless of whether any actual
distributions have been made to our partners. However, under rules applicable to
publicly-traded partnerships, we will withhold at the rate of 39.6% on actual
cash distributions made quarterly to foreign unitholders. Each foreign
unitholder must obtain a taxpayer identification number from the IRS and submit
that number to our Transfer Agent on a Form W-8 in order to obtain credit for
the taxes withheld. Subsequent adoption of Treasury Regulations or the issuance
of other administrative pronouncements may require us to change these
procedures.
Because a foreign corporation that owns common units will be treated as
engaged in a United States trade or business, it may be subject to United States
branch profits tax at a rate of 30%, in addition to regular federal income tax,
on its allocable share of our earnings and profits (as adjusted for changes in
the foreign corporation's "U.S. net equity") that are effectively connected with
the conduct of a United States trade or business. This tax may be reduced or
eliminated by an income tax treaty between the United States and the country
with respect to which the foreign corporate unitholder is a "qualified
resident."
Under a ruling of the IRS, a foreign unitholder who sells or otherwise
disposes of a common unit will be subject to federal income tax on any gain
realized on the disposition of his common unit to the extent that the gain is
effectively connected with a United States trade or business of the foreign
unitholder. Apart from the ruling, a foreign unitholder will not be taxed upon
the disposition of a common unit if that foreign unitholder has held less than
5% in value of the common units during the five-year period ending on the date
of the disposition and if the common units are regularly traded on an
established securities market at the time of the disposition.
Administrative Matters
Our Information Returns and Audit Procedures
We intend to furnish to each of our unitholders, within 90 days after the
close of each taxable year, tax information, including a Schedule K-1, that sets
forth each of our unitholders' allocable shares of our income, gain, loss,
deduction and credit. In preparing this information that will generally not be
reviewed by Counsel, we will use various accounting and reporting conventions,
some of which have been mentioned in the previous discussion, to determine the
respective unitholders' allocable share of income, gain, loss, deduction and
credits. There is no assurance that any of these conventions will yield a result
that conforms to the requirements of the Code, regulations or administrative
interpretations of the IRS. We cannot assure prospective unitholders that the
IRS will not successfully contend in court that these accounting and reporting
conventions are impermissible.
The federal income tax information returns we filed may be audited by the
IRS. Adjustments resulting from any IRS audit may require some or all of our
unitholders to file amended tax returns, and
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possibly may result in an audit of unitholders' own returns. Any audit of a
unitholder's return could result in adjustments of non-partnership as well as
partnership items.
Partnerships generally are treated as separate entities for purposes of
federal tax audits, judicial review of administrative adjustments by the IRS and
tax settlement proceedings. The tax treatment of partnership items of income,
gain, loss, deduction and credit are determined at the partnership level in a
unified partnership proceeding rather than in separate proceedings with the
partners. The Code provides for one partner to be designated as the "Tax Matters
Partner" for these purposes. Our partnership agreement appoints our general
partner as the Tax Matters Partner.
The Tax Matters Partner will make elections on our behalf and our
unitholders' behalf and can extend the statute of limitations for assessment of
tax deficiencies against our unitholders with respect to our items. The Tax
Matters Partner may bind a unitholder with less than a 1% profits interest in us
to a settlement with the IRS unless the unitholder elects, by filing a statement
with the IRS, not to give that authority to the Tax Matters Partner. The Tax
Matters Partner may seek judicial review (to which all of our unitholders are
bound) of a final partnership administrative adjustment and, if the Tax Matters
Partner fails to seek judicial review, the review may be sought by any of our
unitholders having at least 1% interest in our profits and by our unitholders
having in the aggregate at least a 5% profits interest. However, only one action
for judicial review will go forward, and each unitholder with an interest in the
outcome may participate.
A unitholder must file a statement with the IRS identifying the treatment
of any item on his federal income tax return that is not consistent with the
treatment of the item on our return to avoid the requirement that all items be
treated consistently on both returns. Intentional or negligent disregard of the
consistency requirement may subject a unitholder to substantial penalties.
Nominee Reporting
- Persons who hold an interest in us as a nominee for another person are
required to furnish to us:
- the name, address and taxpayer identification number of the beneficial
owners and the nominee;
- whether the beneficial owner is (i) a person that is not a United States
person, (ii) a foreign government, an international organization or any
wholly-owned agency or instrumentality of either of the foregoing or
(iii) a tax-exempt entity;
- the amount and description of common units held, acquired or transferred
for the beneficial owner; and
other information including the dates of acquisitions and transfers, means
of acquisitions and transfers and acquisition cost for purchases, as well
as the amount of net proceeds from sales.
Brokers and financial institutions are required to furnish additional
information, including whether they are United States persons and information on
common units they acquire, hold or transfer for their own account. A penalty of
$50 per failure (up to a maximum of $100,000 per calendar year) is imposed by
the Code for failure to report this information to us. The nominee is required
to supply the beneficial owner of the common units with the information
furnished to us.
Registration as a Tax Shelter
The Code requires that "tax shelters" be registered with the Secretary of
the Treasury. The temporary Treasury Regulations interpreting the tax shelter
registration provisions of the Code are extremely broad. It is arguable that we
are not subject to the registration requirement on the basis that (i) we do not
constitute a tax shelter or (ii) we constitute a projected income investment
exempt from registration. However, we have registered as a tax shelter with the
IRS because of the absence of assurance that we will not be subject to tax
shelter registration and in light of the substantial penalties that might be
imposed if registration is required and not undertaken. ISSUANCE OF THE
REGISTRATION NUMBER
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DOES NOT INDICATE THAT AN INVESTMENT IN US OR THE CLAIMED TAX BENEFITS HAVE BEEN
REVIEWED, EXAMINED OR APPROVED BY THE IRS. Our tax shelter registration number
is 94130000154. A unitholder who sells or otherwise transfers a common unit in a
subsequent transaction must furnish the registration number to the transferee.
The penalty for failure of the transferor of a common unit to furnish the
registration number to the transferee is $100 for each failure. The unitholders
must disclose our tax shelter registration number on Form 8271 to be attached to
the tax return on which any deduction, loss, credit or other benefit we generate
is claimed or income received from us is included. A unitholder who fails to
disclose the tax shelter registration number on his return, without reasonable
cause for the failure, will be subject to a $50 penalty for each failure. Any
penalties discussed herein are not deductible for federal income tax purposes.
Accuracy-Related Penalties
An additional tax equal to 20% of the amount of any portion of an
underpayment of tax that is attributable to one or more of the listed causes,
including substantial understatements of income tax and substantial valuation
misstatements, is imposed by the Code. No penalty will be imposed, however, with
respect to any portion of an underpayment if it is shown that there was a
reasonable cause for that portion and that the taxpayer acted in good faith with
respect to that portion.
A substantial understatement of income tax in any taxable year exists if
the amount of the understatement exceeds the greater of 10% of the tax required
to be shown on the return for the taxable year or $5,000 ($10,000 for most
corporations). The amount of any understatement subject to penalty generally is
reduced if any portion is attributable to a position adopted on the return (i)
with respect to which there is or was, "substantial authority" or (ii) as to
which there is a reasonable basis and the pertinent facts of the position are
disclosed on the return. More stringent rules apply to "tax shelters," a term
that does not appear to include us. If any item of our income, gain, loss,
deduction or credit included in the distributive shares of our unitholders might
result in an "understatement" of income for which no substantial authority
exists, we must disclose the pertinent facts on our return. In addition, we will
make a reasonable effort to furnish sufficient information for our unitholders
to make adequate disclosure on their returns to avoid liability for this
penalty.
A substantial valuation misstatement exists if the value of any property
(or the adjusted basis of any property) claimed on a tax return is 200% or more
of the amount determined to be the correct amount of the valuation or adjusted
basis. No penalty is imposed unless the portion of the underpayment attributable
to a substantial valuation misstatement exceeds $5,000 ($10,000 for most
corporations). If the valuation claimed on a return is 400% or more than the
correct valuation, the penalty imposed increases to 40%.
Other Tax Considerations
In addition to federal income taxes, you may be subject to other taxes,
such as state and local and Canadian federal and provincial taxes,
unincorporated business taxes, and estate, inheritance or intangible taxes that
may be imposed by the various jurisdictions in which the we do business or own
property. Although an analysis of those various taxes is not presented here,
each prospective unitholder should consider their potential impact on his
investment in us. We will own property or conduct business in Canada and in most
states of the United States. A unitholder may be required to file Canadian
federal income tax returns and to pay Canadian federal and provincial income
taxes and to file state income tax returns and to pay taxes in various states
and may be subject to penalties for failure to comply with such requirements. We
anticipate that most of our U.S. income will be generated in approximately
thirteen (13) states: Alabama, California, Illinois, Indiana, Kansas, Louisiana,
Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas and Wyoming.
Based on EOTT's income apportionment for 1998 state income tax purposes, our
general partner estimates that no other state will account for more than 1% of
our income. Of the thirteen states in which our general partner anticipates that
most of our U.S. income will be generated, Texas and Wyoming do not currently
impose personal income tax. In certain states, tax losses may not produce a tax
benefit in the year incurred (if, for example, we have no income from sources
within that state) and also may not be available to offset income in subsequent
taxable years.
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Some of the states may require us to withhold a percentage of income from
amounts to be distributed to a unitholder who is not a resident of the state.
Withholding, the amount which may be greater or less than a particular
unitholder's income tax liability to the state, generally does not relieve the
non-resident unitholder from the obligation to file an income tax return.
Amounts withheld will be treated as if distributed to unitholders for purposes
of determining the amount distributed by us. Based on current law and our
estimate of future operations, the general partner anticipates that any amounts
required to be withheld will not be material. We may also own property or do
business in other states in the future.
It is your responsibility to investigate the legal and tax consequences,
under the laws of pertinent states, localities, Canadian provinces and Canada,
of your investment in us. Accordingly, you should consult, and must depend upon,
your own tax counsel or other advisor with regard to those matters. Further, it
is your responsibility to file all Canadian, Canadian province, state and local,
as well as federal, tax returns that may be required of you. Counsel has not
rendered an opinion on the Canadian federal, Canadian provincial, state or local
tax consequences of an investment in us.
PLAN OF DISTRIBUTION
The selling shareholder may sell its common units from time to time through
underwriters or to brokers or dealers, or directly to investors, (a) at a fixed
price or prices, which may be changed from time to time, (b) at market prices
prevailing at the time of such sale, (c) at prices related to such market
prices, or (d) at negotiated prices. In connection with any sales, underwriting
discounts and commissions and distributors' or sellers' commissions may be paid
or allowed.
Underwriters may offer shares for the selling shareholder pursuant to firm
commitments or on a best efforts basis and may offer such shares on prices and
terms described in the applicable prospectus supplement. Brokers or dealers may
act as agents for the selling shareholder, or may purchase shares from the
selling shareholder as principal and thereafter resell those shares from time to
time in or through transactions or distributions (which may involve crosses and
block transactions) on the New York Stock Exchange, the London Stock Exchange or
other United States or foreign stock exchanges where trading privileges are
available, in the over-the-counter market, in private transactions or in some
combination of the foregoing.
We have agreed to pay all registration expenses related to the sale of
shares by the selling shareholder, except underwriting discounts and
commissions, which will be paid by the selling shareholder. We have agreed to
indemnify the selling shareholder against certain liabilities relating to the
resale of the shares under the Securities Act of 1933.
Dealers and agents that participate in the distribution of the common stock
may be underwriters as defined in the Securities Act of 1933, and any discounts
or commissions received by them from the selling shareholder and any profit on
the resale of the offered securities by them may be treated as underwriting
discounts and commissions under the Securities Act.
The selling shareholder may enter agreements with underwriters, dealers and
agents to indemnify them against certain civil liabilities, including
liabilities under the Securities Act of 1933, or to contribute with respect to
payments which the underwriters, dealers or agents may be required to make.
In connection with offerings under this shelf registration and in
compliance with applicable law, underwriters, brokers or dealers may engage in
transactions that stabilize or maintain the market price of the common units at
levels above those which might otherwise prevail in the open market.
Specifically, underwriters, brokers or dealers may over-allot in connection with
offerings, creating short positions in the common units for their own accounts.
For the purposes of covering a syndicate short position or stabilizing the price
of the common units, the underwriters, brokers or dealers may place bids for the
common units or effect purchases of the common units in the open market.
Finally, the underwriters may impose a penalty bid whereby selling concessions
allowed to syndicate members or other brokers or dealers for distribution the
common units in offerings may be reclaimed by the syndicate if the syndicate
repurchases previously distributed common units in transactions to cover short
positions, in stabilization transactions or
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otherwise. These activities may stabilize, maintain or otherwise affect the
market price of the common units, which may be higher than the price that might
otherwise prevail in the open market, and, if commenced, may be discontinued at
any time.
LEGAL MATTERS
Vinson & Elkins L.L.P., will pass upon the validity of the common units
offered in this prospectus. The underwriters' own legal counsel will advise them
about other issues relating to any offering.
EXPERTS
The audited consolidated financial statements and schedule included in this
prospectus and elsewhere in the registration statement have been audited by
Arthur Andersen LLP, independent public accountants, as indicated in their
report with respect thereto, and are included herein in reliance upon the
authority of said firm as experts in accounting and auditing in giving said
report.
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INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Unaudited Financial Statements
Condensed Consolidated Statements of Operations
(unaudited) -- Six Months Ended June 30, 2000 and
1999................................................... F-2
Condensed Consolidated Balance Sheets (unaudited) -- June
30, 2000 and December 31, 1999......................... F-3
Condensed Consolidated Statements of Cash Flows
(unaudited) -- Six Months Ended June 30, 2000 and
1999................................................... F-4
Condensed Consolidated Statement of Partners' Capital
(unaudited) -- Six Months Ended June 30, 2000.......... F-5
Notes to Condensed Consolidated Financial Statements...... F-6
Audited Financial Statements
Report of Independent Public Accountants.................. F-10
Consolidated Statements of Operations -- Years Ended
December 31, 1999, 1998 and 1997....................... F-11
Consolidated Balance Sheets -- December 31, 1999 and
1998................................................... F-12
Consolidated Statements of Cash Flows -- Years Ended
December 31, 1999, 1998 and 1997....................... F-13
Consolidated Statements of Partners' Capital -- Years
Ended December 31, 1999, 1998 and 1997................. F-14
Notes to Consolidated Financial Statements................ F-15
Supplemental Schedule
Schedule II -- Valuation and Qualifying Accounts and
Reserves............................................... S-1
</TABLE>
F-1
<PAGE> 74
EOTT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
-----------------------
2000 1999
---------- ----------
<S> <C> <C>
Revenue..................................................... $5,196,630 $3,692,460
Cost of Sales............................................... 5,077,567 3,583,967
---------- ----------
Gross Margin................................................ 119,063 108,493
Expenses
Operating expenses........................................ 78,667 74,815
Depreciation and amortization............................. 16,859 16,490
---------- ----------
Total............................................. 95,526 91,305
---------- ----------
Operating Income............................................ 23,537 17,188
Other Income (Expense)
Interest income........................................... 622 320
Interest and related charges.............................. (15,342) (13,820)
Other, net................................................ (1,708) 1,028
---------- ----------
Total............................................. (16,428) (12,472)
---------- ----------
Net Income Before Cumulative Effect of Accounting Change.... 7,109 4,716
Cumulative Effect of Accounting Change...................... -- 1,747
---------- ----------
Net Income.................................................. $ 7,109 $ 6,463
========== ==========
Basic Net Income Per Unit
Common.................................................... $ 0.25 $ 0.24
========== ==========
Subordinated.............................................. $ 0.25 $ 0.31
========== ==========
Diluted Net Income Per Unit................................. $ 0.25 $ 0.26
========== ==========
Number of Units Outstanding for Diluted Computation......... 27,476 23,976
========== ==========
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
F-2
<PAGE> 75
EOTT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
2000 1999
----------- ------------
(UNAUDITED)
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents................................. $ 8,786 $ 17,525
Trade and other receivables, net of allowance for doubtful
accounts of $1,732 and $1,732 respectively............. 909,184 966,422
Inventories............................................... 83,615 120,306
Other..................................................... 16,812 29,191
---------- ----------
Total current assets.............................. 1,018,397 1,133,444
---------- ----------
Property, Plant & Equipment, at cost........................ 547,474 544,723
Less: Accumulated depreciation............................ 154,012 140,228
---------- ----------
Net property, plant & equipment................... 393,462 404,495
---------- ----------
Other Assets, net of amortization........................... 17,045 20,722
---------- ----------
Total Assets................................................ $1,428,904 $1,558,661
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Trade accounts payable.................................... $1,006,756 $1,103,187
Accrued taxes payable..................................... 11,373 11,947
Repurchase agreements..................................... 52,704 74,055
Other..................................................... 4,236 8,333
---------- ----------
Total current liabilities......................... 1,075,069 1,197,522
---------- ----------
Long-Term Liabilities
11% Senior notes.......................................... 235,000 235,000
Other..................................................... 132 3,475
---------- ----------
Total long-term liabilities....................... 235,132 238,475
---------- ----------
Commitments and Contingencies (Note 3)
Additional Partnership Interests............................ 9,318 2,547
---------- ----------
Partners' Capital
Common Unitholders........................................ 60,702 73,570
Subordinated Unitholders.................................. 41,137 38,855
General Partner........................................... 7,546 7,692
---------- ----------
Total Partners' Capital........................... 109,385 120,117
---------- ----------
Total Liabilities and Partners' Capital........... $1,428,904 $1,558,661
========== ==========
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
F-3
<PAGE> 76
EOTT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
--------------------
2000 1999
-------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of net income to net cash provided by
operating activities --
Net income................................................ $ 7,109 $ 6,463
Depreciation.............................................. 16,331 15,456
Amortization of intangible assets......................... 528 1,034
Gains on disposal of assets............................... (207) (436)
Changes in components of working capital --
Receivables............................................ 57,238 (246,489)
Inventories............................................ 36,691 34,965
Other current assets................................... 12,379 (32,509)
Trade accounts payable................................. (96,431) 243,520
Accrued taxes payable.................................. (574) 3,569
Other current liabilities.............................. (4,097) 527
Other assets and liabilities.............................. 718 52
-------- ---------
Net Cash Provided By Operating Activities......... 29,685 26,152
-------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of property, plant and equipment....... 527 548
Acquisitions.............................................. -- (33,000)
Additions to property, plant and equipment................ (6,559) (10,064)
Other, net................................................ 29 --
-------- ---------
Net Cash Used In Investing Activities............. (6,003) (42,516)
-------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in short-term borrowings -- affiliate............ -- 21,903
Increase (decrease) in repurchase agreements.............. (21,351) 6,982
Distributions to Unitholders.............................. (17,841) (14,168)
Issuance of Additional Partnership Interests.............. 6,771 2,547
Other, net................................................ -- (281)
-------- ---------
Net Cash Provided By (Used In) Financing
Activities...................................... (32,421) 16,983
-------- ---------
Increase (Decrease) In Cash and Cash
Equivalents..................................... (8,739) 619
Cash and Cash Equivalents, Beginning of Period.... 17,525 3,033
-------- ---------
Cash and Cash Equivalents, End of Period.......... $ 8,786 $ 3,652
======== =========
Supplemental Cash Flow Information:
Interest paid................................... $ 14,977 $ 13,464
======== =========
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
F-4
<PAGE> 77
EOTT ENERGY PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
COMMON SUBORDINATED GENERAL
UNITHOLDERS UNITHOLDERS PARTNER
----------- ------------ -------
<S> <C> <C> <C>
Partners' Capital at December 31, 1999...................... $ 73,570 $38,855 $7,692
Net income................................................ 4,685 2,282 142
Cash distributions........................................ (17,553) -- (288)
-------- ------- ------
Partners' Capital at June 30, 2000.......................... $ 60,702 $41,137 $7,546
======== ======= ======
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
F-5
<PAGE> 78
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
In connection with a reorganization of the business conducted by EOTT
Energy Corp., an indirect wholly-owned subsidiary of Enron Corp. ("Enron"), into
limited partnership form and a concurrent initial public offering of Common
Units of EOTT Energy Partners, L.P. ("EOTT" or the "Partnership") effective
March 24, 1994, the net assets of EOTT Energy Corp., its wholly-owned foreign
subsidiary, EOTT Energy Ltd., and Enron Products Marketing Company ("EPMC") were
acquired by three operating limited partnerships in which the Partnership is
directly or indirectly the 99% limited partner. EOTT Energy Corp., a Delaware
corporation, serves as the General Partner of the Partnership and its related
operating limited partnerships. The accompanying condensed consolidated
financial statements and related notes present the financial position as of June
30, 2000 and December 31, 1999 for the Partnership, the results of operations
for the three and six months ended June 30, 2000 and 1999, cash flows for the
six months ended June 30, 2000 and 1999, and changes in partners' capital for
the six months ended June 30, 2000. For the three and six months ended June 30,
2000 and 1999, traditional net income (loss) and comprehensive income (loss) are
the same.
On March 24, 1994, the General Partner completed an initial public offering
of 10 million Common Units at $20.00 per unit, representing limited partner
interests in the Partnership. In addition to its aggregate approximate 2%
general partner interest in the Partnership, the General Partner owns an
approximate 25% subordinated limited partner interest. Enron, through its
ownership of EOTT Common Units, directly holds an approximate 12% interest in
the Partnership.
The financial statements included herein have been prepared by the
Partnership without audit pursuant to the rules and regulations of the
Securities and Exchange Commission ("SEC"). Accordingly, they reflect all
adjustments (which consist solely of normal recurring adjustments) which are, in
the opinion of management, necessary for a fair presentation of the financial
results for interim periods. Certain information and notes normally included in
financial statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted pursuant to such rules and
regulations. However, the Partnership believes that the disclosures are adequate
to make the information presented not misleading. These financial statements
should be read in conjunction with the audited financial statements and notes
thereto included elsewhere herein.
During the first quarter of 2000, the Partnership identified certain
systems integration issues relating to its new computerized marketing and
accounting system and the Partnership immediately commenced an extensive review
and analysis of the implementation of the new system. As a result of these
efforts, the Partnership identified and quantified the impacts of the systems
integration issues relating to its new computerized marketing and accounting
system and recorded appropriate financial statement adjustments in the first
quarter of 2000. The Partnership has implemented and continues to implement
additional control processes and procedures that it believes are sufficient to
permit the preparation of timely and accurate financial information, including
additional preventative and monitoring controls to ensure the integrity and
reliability of financial information generated by the system as well as
additional system training for users.
Certain reclassifications have been made to prior period amounts to conform
with the current period presentation.
F-6
<PAGE> 79
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2. EARNINGS PER UNIT
Net income shown in the tables below excludes the approximate two percent
interest of the General Partner. Earnings per unit are calculated as follows (in
millions, except per unit amounts):
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
---------------------------------------------------
2000 1999
------------------------ ------------------------
WTD. WTD.
NET AVERAGE PER NET AVERAGE PER
INCOME UNITS UNIT INCOME UNITS UNIT
------ ------- ----- ------ ------- -----
<S> <C> <C> <C> <C> <C> <C>
Basic(1)
Common............................ $4,685 18,476 $0.25 $3,565 14,976 $0.24
Subordinated...................... $2,282 9,000 $0.25 $2,749 9,000 $0.31
Diluted(2).......................... $6,967 27,476 $0.25 $6,314 23,976 $0.26
</TABLE>
---------------
(1) Net income, excluding the two percent General Partner interest, has been
apportioned to each class of Unitholder based on the ownership of total
Units outstanding which is also reflected on the Statement of Partners'
Capital, and Special Units are considered Common Units during the periods in
which they were outstanding. Due to a negative capital account balance for
the Common Unitholders during the second and third quarters of 1998, the
loss allocated to the Common Unitholders attributable to these periods was
reallocated to the remaining Unitholders based on their ownership
percentage. The allocated loss was fully recouped by the Unitholders
allocated the additional losses in the first quarter of 1999.
(2) The diluted income (loss) per unit calculation assumes the conversion of
Subordinated Units into Common Units. The disproportionate income (loss)
allocation between the Unitholders has no effect on the diluted computation.
EOTT issued 3,500,000 Common Units to the public on September 29, 1999.
3. LITIGATION AND OTHER CONTINGENCIES
EOTT is, in the ordinary course of business, a defendant in various
lawsuits, some of which are covered in whole or in part by insurance. The
Partnership is responsible for all litigation and other claims relating to the
business acquired from EOTT Energy Corp., although the Partnership will be
entitled to the benefit of certain insurance maintained by Enron covering
occurrences prior to the closing of the offering in 1994. The Partnership
believes that the ultimate resolution of litigation, individually and in the
aggregate, will not have a materially adverse impact on the Partnership's
financial position or results of operations. Various legal actions have arisen
in the ordinary course of business, the most significant of which are discussed
in "Business -- Legal Proceedings" included elsewhere in this prospectus.
The Partnership believes that it has obtained or has applied for all of the
necessary permits required by federal, state, and local environmental agencies
for the operation of its business. Further, the Partnership believes that there
are no outstanding liabilities or claims relating to environmental matters
individually, and in the aggregate, which would have a material adverse impact
on the Partnership's financial position or results of operations.
4. NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Statement establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as
F-7
<PAGE> 80
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
either an asset or liability measured at its fair value. The Statement requires
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement and requires that a company
must formally document, designate, and assess the effectiveness of transactions
that receive hedge accounting. SFAS No. 133, as amended, is effective for fiscal
years beginning after June 15, 2000. The standard cannot be applied
retroactively, but early adoption is permitted. EOTT has not yet determined the
impact of adopting SFAS No. 133; however, this standard could increase
volatility in earnings and partners' capital, through other comprehensive
income.
5. BUSINESS SEGMENT INFORMATION
EOTT has three reportable segments, which management believes are necessary
to make decisions about resources to be allocated and assess its performance:
North American Crude Oil -- East of Rockies, Pipeline Operations and West Coast
Operations. The North American Crude Oil -- East of Rockies segment primarily
purchases, gathers, transports and markets crude oil. The Pipeline Operations
segment operates approximately 7,400 active miles of common carrier pipelines in
12 states. The West Coast Operations include crude oil gathering and marketing,
refined products marketing and a natural gas liquids business.
The accounting policies of the segments are the same as those described in
the summary of significant accounting policies as discussed in Note 2 included
in the Partnership's Annual Report on Form 10-K for the year ended December 31,
1999. EOTT evaluates performance based on operating income (loss). EOTT accounts
for intersegment revenue and transfers between North American Crude Oil -- East
of Rockies and West Coast Operations as if the sales or transfers were to third
parties, that is, at current market prices. Intersegment revenues for Pipeline
Operations are based on published pipeline tariffs.
F-8
<PAGE> 81
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FINANCIAL INFORMATION BY BUSINESS SEGMENT
<TABLE>
<CAPTION>
NORTH
AMERICAN WEST CORPORATE
CRUDE OIL PIPELINE COAST AND
-EOR OPERATIONS OPERATIONS OTHER(b) CONSOLIDATED
---------- ---------- ---------- --------- ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
SIX MONTHS ENDED JUNE 30, 2000
Revenue from external customers...... $4,821,498 $ 14,917 $360,215 $ -- $5,196,630
Intersegment revenue(a).............. 5,671 53,194 -- (58,865) --
---------- -------- -------- -------- ----------
Total revenue.............. 4,827,169 68,111 360,215 (58,865) 5,196,630
---------- -------- -------- -------- ----------
Gross margin......................... 40,292 69,073 9,698 -- 119,063
---------- -------- -------- -------- ----------
Operating income (loss).............. 1,334 34,627 (1,488) (10,936) 23,537
Other expense........................ -- -- -- (16,428) (16,428)
---------- -------- -------- -------- ----------
Net income (loss).................... 1,334 34,627 (1,488) (27,364) 7,109
---------- -------- -------- -------- ----------
Depreciation and amortization........ 3,828 10,540 1,332 1,159 16,859
---------- -------- -------- -------- ----------
SIX MONTHS ENDED JUNE 30, 1999
Revenue from external customers...... $3,422,926 $ 10,070 $259,478 $ (14) $3,692,460
Intersegment revenue(a).............. 31,395 42,472 14,333 (88,200) --
---------- -------- -------- -------- ----------
Total revenue.............. 3,454,321 52,542 273,811 (88,214) 3,692,460
---------- -------- -------- -------- ----------
Gross margin......................... 41,978 52,007 14,556 (48) 108,493
---------- -------- -------- -------- ----------
Operating income (loss).............. 932 24,325 4,402 (12,471) 17,188
Other expense........................ -- -- -- (12,472) (12,472)
---------- -------- -------- -------- ----------
Net income (loss) before cumulative
effect of accounting change........ 932 24,325 4,402 (24,943) 4,716
---------- -------- -------- -------- ----------
Depreciation and amortization........ 4,746 9,884 991 869 16,490
---------- -------- -------- -------- ----------
TOTAL ASSETS AT JUNE 30, 2000........ $1,006,525 $302,300 $ 87,826 $ 32,253 $1,428,904
---------- -------- -------- -------- ----------
TOTAL ASSETS AT DECEMBER 31, 1999.... 1,084,613 306,321 129,461 38,266 1,558,661
---------- -------- -------- -------- ----------
</TABLE>
---------------
(a) Intersegment revenue for North American Crude Oil -- EOR and West Coast
Operations is made at prices comparable to those received from external
customers. Intersegment revenue for Pipeline Operations is transportation
costs charged to North American Crude Oil -- EOR for the transport of crude
oil at published pipeline tariffs.
(b) Corporate and Other also includes intersegment eliminations.
F-9
<PAGE> 82
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. NONRECURRING ITEMS
In the fourth quarter of 1999, EOTT recorded a $7.8 million charge for the
theft of NGL product, concealment of commercial activities and other
unauthorized actions by a former employee. EOTT filed an insurance claim to
recover the losses related to the theft of NGL product and received $2.5 million
in the second quarter of 2000. EOTT is continuing to pursue legal action against
the former employee.
7. SUBSEQUENT EVENTS
On July 20, 2000, the Board of Directors of EOTT Energy Corp., as General
Partner, declared the Partnership's regular quarterly cash distribution of
$0.475 for all Common Units for the period April 1, 2000 through June 30, 2000.
The second quarter distribution of $9.0 million was paid on August 14, 2000 to
the General Partner and all Common Unitholders of record as of July 31, 2000.
The distribution was paid utilizing Available Cash from the Partnership.
F-10
<PAGE> 83
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To EOTT Energy Partners, L.P.:
We have audited the accompanying consolidated balance sheets of EOTT Energy
Partners, L.P. (a Delaware limited partnership) as of December 31, 1999 and
1998, and the related consolidated statements of operations, cash flows and
partners' capital for each of the three years in the period ended December 31,
1999. These financial statements and the schedule referred to below are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of EOTT Energy Partners, L.P.
as of December 31, 1999 and 1998, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1999, in
conformity with accounting principles generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedule listed
in the index to financial statements is presented for purposes of complying with
the Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
ARTHUR ANDERSEN LLP
Houston, Texas
March 3, 2000
F-11
<PAGE> 84
EOTT ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Revenue.................................................. $8,664,401 $5,294,697 $7,646,099
Cost of Sales............................................ 8,452,086 5,162,092 7,533,054
---------- ---------- ----------
Gross Margin............................................. 212,315 132,605 113,045
Expenses
Operating expenses..................................... 153,194 104,425 96,158
Depreciation and amortization.......................... 33,136 20,951 16,518
Impairment of assets................................... -- -- 7,961
---------- ---------- ----------
Total.......................................... 186,330 125,376 120,637
---------- ---------- ----------
Operating Income (Loss).................................. 25,985 7,229 (7,592)
Other Income (Expense)
Interest income........................................ 875 674 620
Interest and related charges........................... (29,817) (10,165) (6,661)
Other, net............................................. 742 (1,805) (766)
---------- ---------- ----------
Total.......................................... (28,200) (11,296) (6,807)
---------- ---------- ----------
Net Loss Before Cumulative Effect of Accounting Change... (2,215) (4,067) (14,399)
Cumulative Effect of Accounting Change (Note 3).......... 1,747 -- --
---------- ---------- ----------
Net Loss................................................. $ (468) $ (4,067) $ (14,399)
========== ========== ==========
Basic Net Income (Loss) Per Unit (Note 5)
Common................................................. $ (0.06) $ (0.17) $ (0.75)
========== ========== ==========
Subordinated........................................... $ 0.06 $ (0.26) $ (0.75)
========== ========== ==========
Diluted Net Income (Loss) Per Unit (Note 5).............. $ (0.02) $ (0.21) $ (0.75)
========== ========== ==========
Distributions Per Common Unit............................ $ 1.90 $ 1.90 $ 1.90
========== ========== ==========
Average Units Outstanding for Diluted Computation........ 24,877 19,267 18,830
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-12
<PAGE> 85
EOTT ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1999 1998
------------ ------------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents................................. $ 17,525 $ 3,033
Trade and other receivables, net of allowance for doubtful
accounts of $1,732 and $1,860, respectively............ 966,422 403,335
Inventories............................................... 120,306 137,545
Other..................................................... 29,191 30,328
---------- --------
Total current assets.............................. 1,133,444 574,241
---------- --------
Property, Plant and Equipment, at cost...................... 544,723 497,807
Less: Accumulated depreciation............................ 140,228 112,568
---------- --------
Net property, plant and equipment................. 404,495 385,239
---------- --------
Other Assets, net of amortization................. 20,722 6,340
---------- --------
Total Assets...................................... $1,558,661 $965,820
========== ========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Trade accounts payable.................................... $1,103,187 $524,822
Accrued taxes payable..................................... 11,947 5,192
Short-term borrowings -- affiliate........................ -- 28,297
Bridge loan -- affiliate.................................. -- 42,000
Term loan -- affiliate.................................... -- 175,000
Repurchase agreements..................................... 74,055 83,016
Other..................................................... 8,333 9,983
---------- --------
Total current liabilities......................... 1,197,522 868,310
---------- --------
Long-Term Liabilities
11% senior notes.......................................... 235,000 --
Other..................................................... 3,475 --
---------- --------
Total long-term liabilities....................... 238,475 --
---------- --------
Commitments and Contingencies (Notes 15 and 16)
Additional Partnership Interests (Note 13).................. 2,547 21,928
Partners' Capital
Common Unitholders........................................ 73,570 14,472
Special Unitholders....................................... -- 21,092
Subordinated Unitholders.................................. 38,855 38,315
General Partner........................................... 7,692 1,703
---------- --------
Total Partners' Capital........................... 120,117 75,582
---------- --------
Total Liabilities and Partners' Capital........... $1,558,661 $965,820
========== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-13
<PAGE> 86
EOTT ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of net loss to net cash provided by (used
in) operating activities
Net loss............................................. $ (468) $ (4,067) $ (14,399)
Depreciation......................................... 31,164 18,806 14,487
Impairment of assets................................. -- -- 7,961
Amortization of intangible assets.................... 1,972 2,145 2,031
(Gains) losses on disposal of assets................. (636) 66 (503)
Changes in components of working capital --
Receivables........................................ (563,087) 60,648 240,801
Inventories........................................ 17,239 1,720 (4,339)
Other current assets............................... 1,137 (3,737) 1,893
Trade accounts payable............................. 578,365 (61,578) (231,776)
Accrued taxes payable.............................. 6,755 (270) (3,003)
Other current liabilities.......................... (5,369) 4,238 (14,057)
Other assets and liabilities......................... 2,216 616 886
--------- --------- ---------
Net Cash Provided by (Used In) Operating
Activities.................................... 69,288 18,587 (18)
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of property, plant and equipment..... 1,407 7,330 1,243
Acquisitions............................................ (33,000) (224,397) (12,000)
Additions to property, plant and equipment.............. (21,728) (8,492) (10,837)
Other, net.............................................. -- 866 129
--------- --------- ---------
Net Cash Used In Investing Activities........... (53,321) (224,693) (21,465)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase (decrease) in note payable -- affiliate........ -- (39,300) 15,072
Increase (decrease) in short-term
borrowings -- affiliate.............................. (28,297) (41,703) 31,500
Increase (decrease) in bridge loan -- affiliate......... (42,000) 42,000 --
Increase (decrease) in term loan -- affiliate........... (175,000) 175,000 --
Increase (decrease) in repurchase agreements............ (8,961) 83,016 --
Acquisition of treasury units........................... -- (66) --
Issuance of 11% senior notes............................ 235,000 -- --
Payment of financing issue expenses..................... (7,558) -- --
Net proceeds from Issuance of Common Units.............. 52,920 -- --
Contribution from General Partner....................... 535 793 --
Distributions to Unitholders............................ (30,380) (22,842) (29,681)
Issuance of Additional Partnership Interests............ 2,547 9,153 3,684
Other, net.............................................. (281) (649) (616)
--------- --------- ---------
Net Cash Provided by (Used in) Financing
Activities.................................... (1,475) 205,402 19,959
--------- --------- ---------
Increase (Decrease) in Cash and Cash
Equivalents................................... 14,492 (704) (1,524)
Cash and Cash Equivalents Beginning of Period... 3,033 3,737 5,261
--------- --------- ---------
Cash and Cash Equivalents End of Period......... $ 17,525 $ 3,033 $ 3,737
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-14
<PAGE> 87
EOTT ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMMON SPECIAL SUBORDINATED GENERAL
UNITHOLDERS UNITHOLDERS UNITHOLDERS PARTNER
----------- ----------- ------------ -------
<S> <C> <C> <C> <C>
Partners' Capital at December 31, 1996............ $ 33,984 $29,908 $40,065 $2,216
Net loss........................................ (7,494) (1,371) (5,246) (288)
Cash distributions.............................. (19,000) (3,477) (6,650) (554)
-------- ------- ------- ------
Partners' Capital at December 31, 1997............ $ 7,490 $25,060 $28,169 $1,374
-------- ------- ------- ------
Net loss........................................ (1,623) (490) (1,854) (100)
Cash distributions.............................. (19,000) (3,478) -- (364)
Acquisition of Common Units for Treasury........ (66) -- -- --
Issuance of Common Units........................ 27,671 -- -- --
Issuance of Special Units....................... -- 15,905 -- --
Contribution receivable from Enron.............. -- (15,905) -- --
Issuance of Subordinated Units.................. -- -- 12,000 --
Contribution from General Partner............... -- -- -- 793
-------- ------- ------- ------
Partners' Capital at December 31, 1998............ $ 14,472 $21,092 $38,315 $1,703
-------- ------- ------- ------
Net income (loss)............................... (1,636) 618 540 10
Cash distributions.............................. (28,385) (1,416) -- (579)
Issuance of Common Units........................ 52,920 -- -- 535
Contribution of Additional Partnership
Interests.................................... 15,905 -- -- 6,023
Conversion of Special Units..................... 20,294 (20,294) -- --
-------- ------- ------- ------
Partners' Capital at December 31, 1999............ $ 73,570 $ -- $38,855 $7,692
======== ======= ======= ======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-15
<PAGE> 88
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
EOTT Energy Partners, L.P. is a Delaware limited partnership which operates
through its affiliated limited partnerships, EOTT Energy Operating Limited
Partnership, EOTT Energy Canada Limited Partnership and EOTT Energy Pipeline
Limited Partnership. The terms "EOTT" and the "Partnership" herein refer to EOTT
Energy Partners, L.P. and its affiliated limited partnerships. EOTT Energy Corp.
serves as the General Partner of the Partnership and its related operating
limited partnerships. At December 31, 1999 the General Partner owned an
approximate 2% general partner interest in the Partnership and an approximate
25% subordinated limited partner interest. Enron, through its ownership of EOTT
Common Units, holds an approximate 12% interest in the Partnership.
In 1999, EOTT Energy Partners, L.P. formed EOTT Energy Finance Corp. as a
direct wholly-owned subsidiary. This entity was set up for the debt offering to
facilitate certain investors' ability to purchase EOTT's senior notes, more
fully described in Note 8.
The accompanying consolidated financial statements and related notes
present the financial position as of December 31, 1999 and 1998 for the
Partnership, and the results of its operations, cash flows and changes in
partners' capital for the years ended December 31, 1999, 1998 and 1997.
Certain reclassifications have been made to prior period amounts to conform
with the current period presentation.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation. The Partnership owns and operates its assets
through operating limited partnerships. The accompanying financial statements
reflect the combined accounts of the Partnership and the operating partnerships
after elimination of intercompany transactions.
Nature of Operations. Through its affiliated limited partnerships, EOTT
Energy Operating Limited Partnership, EOTT Energy Canada Limited Partnership,
and EOTT Energy Pipeline Limited Partnership, EOTT is engaged in the purchasing,
gathering, transporting, trading, storage and resale of crude oil and refined
petroleum products and related activities. EOTT's principal business segments
are its North American Crude Oil -- East of Rockies gathering and marketing
operations, Pipeline Operations and West Coast Operations. In late 1997, EOTT
exited the East of Rockies refined products business which is discussed further
in Note 6.
Cash Equivalents. EOTT records as cash equivalents all highly liquid
short-term investments having original maturities of three months or less.
Inventories. The Partnership accounts for its inventories using the average
cost method.
Depreciation and Amortization. Depreciation is provided by applying the
straight-line method to the cost basis of property, plant and equipment, less
estimated salvage value, over the estimated useful lives of the assets. Asset
lives are 15 to 20 years for pipeline and gathering facilities, 5 to 10 years
for transportation equipment, 15 to 20 years for barge and terminalling
facilities and 3 to 20 years for other facilities and equipment.
Goodwill is amortized over a period of 10 to 15 years, and is recorded net
of its accumulated amortization in Other Assets. Accumulated amortization of
goodwill at December 31, 1999 and 1998 was $29.8 million and $27.9 million,
respectively.
Foreign Currency Transactions. Canadian operations represent all of the
foreign activities of EOTT. The U.S. dollar is the functional currency. Foreign
currency transactions are initially translated into U.S. dollars. Gains and
losses resulting therefrom are included in the determination of net income
(loss) in the period in which the exchange rate changes.
F-16
<PAGE> 89
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Hedging Activities/Revenue Recognition. EOTT enters primarily into futures
and over-the-counter transactions in an effort to minimize the impact of market
fluctuations on inventories and other contractual commitments. Realized and
unrealized changes in the market value of these transactions, which are entered
into and accordingly designated as hedges, are deferred until the gain or loss
on the hedged transaction is recognized in accordance with Statement of
Financial Accounting Standards ("SFAS") No. 80. Any cash flow recognition
resulting from hedging activities is treated in the same manner as the
underlying transaction. Based on the historical correlations between the New
York Mercantile Exchange ("NYMEX") price for West Texas Intermediate crude at
Cushing, Oklahoma and the various marketing hubs at which EOTT markets crude
oil, EOTT management believes the hedging program has been effective in
minimizing the overall price risk. EOTT continuously monitors the basis
differentials between its various trading hubs and Cushing, Oklahoma to further
manage its basis exposure.
It is EOTT's policy to seek to maintain at all times purchase and sale
positions that are substantially balanced in order to minimize exposure to price
fluctuations; however certain risks cannot be completely hedged such as basis
risks (the risk that price relationships between delivery points, classes of
products or delivery periods will change) and the risk that transportation costs
will change.
Periodically, EOTT enters into agreements to sell United States dollars for
Canadian dollars to hedge commitments to sell petroleum in the United States
that is purchased in Canada. Any gains or losses resulting from these
commitments are recorded with the purchase and sale of crude oil and are
included in the determination of net income (loss).
EOTT recognizes revenue on the accrual method based on the right to receive
payment for goods and services delivered to third parties.
Use of Estimates. The preparation of these financial statements required
the use of certain estimates by management in determining the entity's assets,
liabilities, revenue and expenses. Actual results may differ from these
estimates.
3. CHANGE IN ACCOUNTING PRINCIPLE
In December 1998, the Emerging Issues Task Force ("EITF") reached a
consensus on Issue 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities." The Issue 98-10 is effective for fiscal years
beginning after December 15, 1998, and requires energy trading contracts (as
defined) to be recorded at fair value on the balance sheet, with the change in
fair value included in earnings. The consensus requires the effect of initial
application of Issue 98-10 to be recorded as a cumulative effect of a change in
accounting principle effective January 1, 1999, for calendar year companies. The
cumulative effect of adopting Issue 98-10 effective January 1, 1999 was $1.7
million and is reflected as an increase in net income in the Consolidated
Statement of Operations. For the year ended December 31, 1999, EOTT had a net
mark-to-market loss of $5.6 million (which includes a $6.2 million charge
related to the unauthorized NGL activities).
4. ACQUISITION OF ASSETS
On July 1, 1998, the Partnership acquired crude oil gathering and
transportation assets in West Texas and New Mexico from Koch Pipeline Company,
L.P., a subsidiary of Koch Industries, Inc., and Koch Oil Company, a division of
Koch Industries, Inc. (collectively "Koch"). The asset purchase included
approximately 300 miles of common carrier pipelines, associated storage
facilities for approximately 500,000 barrels and lease purchase contracts for up
to 40,000 barrels of lease crude oil per day. The purchase price was
approximately $28.5 million and was financed with short-term borrowings from
Enron.
On December 1, 1998, the Partnership acquired certain additional crude oil
gathering and transportation assets in key oil producing regions from Koch. The
asset purchase included approximately
F-17
<PAGE> 90
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3,900 miles of active crude oil pipelines, crude oil transport trucks, meter
stations, vehicles, storage tanks and lease purchase contracts for approximately
180,000 lease barrels of crude oil per day from production in 11 central and
western states including Texas, Oklahoma, Kansas and California (the "Assets").
The transaction almost tripled EOTT's pipeline mileage and almost doubled crude
oil lease barrels under contract. The total purchase price of the Assets was
$235.6 million, which includes consideration of $184.5 million in cash,
2,000,000 Common Units, 2,000,000 Subordinated Units and $11.4 million in
transaction costs. EOTT financed the majority of the purchase price through
borrowings from Enron, consisting of a $42 million bridge loan, $135.7 million
of term debt, and $6.8 million from the Partnership's existing credit facility
with Enron. EOTT also increased its existing credit facility with Enron to $1
billion in order to provide increased credit support for the Partnership because
of its increased size following the Koch acquisitions. See additional discussion
regarding Enron financing in Note 8.
Since the Assets were historically used to support Koch's integrated
revenue producing activities, EOTT does not believe that the historical
operational results of the Assets provide a meaningful basis for evaluating the
results of operations that the Assets acquired would have realized had they been
part of EOTT. Therefore, summarized pro forma results of the Partnership as
though the acquisition of Assets had occurred at January 1, 1998 have not been
provided.
On May 1, 1999, EOTT acquired crude oil transportation and storage assets
in West Texas and New Mexico from Texas-New Mexico Pipeline Company, which
included approximately 1,800 miles of common carrier crude oil pipelines. EOTT
paid $33 million in cash and recorded a $4 million liability related to future
environmental costs and financed the total acquisition cost using short-term
borrowings from Enron.
5. EARNINGS PER UNIT
Basic earnings per unit includes the weighted average impact of outstanding
units of EOTT (i.e., it excludes unit equivalents). Diluted earnings per unit
considers the impact of all potentially dilutive securities. Net income (loss)
shown in the table below excludes the approximate two percent interest of the
General Partner. Earnings (loss) per unit are calculated as follows (in
millions, except per unit amounts):
<TABLE>
<CAPTION>
1999 1998 1997
--------------------------- --------------------------- ----------------------------
NET WEIGHTED WEIGHTED WEIGHTED
INCOME AVERAGE PER NET AVERAGE PER AVERAGE PER
(LOSS) UNITS UNIT LOSS UNITS UNIT NET LOSS UNITS UNIT
------- -------- ------ ------- -------- ------ -------- -------- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Basic:(1)
Common............. $(1,018) 15,877 $(0.06) $(2,113) 12,097 $(0.17) $ (8,865) 11,830 $(0.75)
Subordinated....... $ 540 9,000 $ 0.06 $(1,854) 7,170 $(0.26) $ (5,246) 7,000 $(0.75)
Diluted(2)........... $ (478) 24,877 $(0.02) $(3,967) 19,267 $(0.21) $(14,111) 18,830 $(0.75)
</TABLE>
---------------
(1) Net income (loss), excluding the two percent General Partner interest, has
been apportioned to each class of Unitholder based on the ownership of total
Units outstanding in accordance with the Partnership Agreement, which is
also reflected on the Statement of Partners' Capital, and Special Units are
considered Common Units. Due to a negative capital account balance for the
Common Unitholders during the second and third quarters of 1998, the loss
allocated to the Common Unitholders attributable to these periods was
reallocated to the remaining Unitholders based on their ownership
percentage. The allocated loss was recouped by the Unitholders allocated the
additional losses in the first quarter of 1999.
(2) The diluted earnings (loss) per unit calculation assumes the conversion of
Subordinated Units into Common Units. The disproportionate income (loss)
allocation between the Unitholders has no effect on the diluted computation.
F-18
<PAGE> 91
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Per unit information related to the net income before cumulative effect of
accounting change and cumulative effect of the change in accounting principle
for the year ended December 31, 1999 is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1999
-------------------------------
BASIC
---------------------
COMMON SUBORDINATED DILUTED
------ ------------ -------
<S> <C> <C> <C>
Net Loss Before Cumulative Effect of Accounting
Change............................................... $(0.13) $(0.01) $(0.09)
Cumulative Effect of Accounting Change................. 0.07 0.07 0.07
------ ------ ------
Net Income (Loss)...................................... $(0.06) $ 0.06 $(0.02)
====== ====== ======
</TABLE>
As further discussed in Note 8, EOTT issued 3,500,000 Common Units to the
public on September 29, 1999.
6. NONRECURRING ITEMS
In the fourth quarter of 1999, EOTT recorded $9.8 million of nonrecurring
items which include $7.8 million related to mid-continent NGL activities and a
$2.0 million severance charge. The $7.8 million charge related to mid-continent
NGL activities includes a $6.2 million charge for the apparent theft of NGL
product, concealment of commercial activities and other unauthorized actions by
a former employee. EOTT is pursuing legal action against the former employee and
has filed an insurance claim to recover any losses related to the apparent theft
of NGL product which may be covered by insurance. The remaining charges relate
to incremental costs to liquidate contracts prior to their maturity in order to
wind down the mid-continent NGL activities.
In addition, in a continual effort to reduce the Partnership's cost
structure, the Partnership increased the utilization of technology and
implemented a new marketing and accounting system during 1999. As a result,
marketing, field and administrative personnel were reduced and a severance
charge of $2.0 million was recorded pursuant to the existing EOTT Energy Corp.
Severance Plan.
In late 1997, EOTT decided to refocus on the core crude business, which
provides substantially all of the gross margin for the Partnership, as well as
improve overall operating efficiencies. As a result, EOTT announced the
following two initiatives. The decision was made to exit the marginal East of
Rockies refined products business and sell its three products terminals in Ohio.
In connection with this decision, nonrecurring charges were recorded at December
31, 1997, which included severance costs of $0.9 million and a $1.5 million
impairment of the Ohio products terminals. In addition, EOTT streamlined
business processes throughout the organization and realigned reporting
responsibilities to improve the Partnership's overall cost structure. As a
result, marketing and administrative personnel were reduced by approximately 20
percent and a nonrecurring severance charge of $1.1 million was recorded at
December 31, 1997 pursuant to the existing EOTT Energy Corp. Severance Plan. The
realignment initiatives have been completed and the reserves were adequate to
complete the initiatives.
7. IMPAIRMENT OF ASSETS
As a result of the decision to exit the East of Rockies refined products
business discussed in Note 6, the Partnership's three Ohio products terminals
are being held for sale. At December 31, 1997, a $1.5 million impairment charge
was recorded.
During the fourth quarter of 1997, EOTT terminated an information system
development project due to the lack of third party vendor support and
foreseeable operating platform obsolescence. As a result, the Partnership
recorded a $6.5 million impairment charge.
F-19
<PAGE> 92
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. CREDIT RESOURCES AND LIQUIDITY
On December 1, 1998, Enron increased its existing credit facility with the
Partnership to provide additional credit support in the form of guarantees,
letters of credit and working capital loans through December 31, 2001. The total
amount of the Enron facility is $1.0 billion, and it contains sublimits of $100
million for working capital loans and $900 million for guarantees and letters of
credit. Letter of credit fees are based on actual charges by the banks which
range from .20% -- .375% per annum. Interest on outstanding loans is charged at
LIBOR plus 250 basis points per annum.
The Enron facility is subject to defined borrowing base limitations
relating to the Partnership's activities and to the maintenance and protection
of the collateral. The Enron facility permits distributions to Unitholders
subject to certain limitations based on the Partnership's earnings and other
factors. These covenants and restrictions are not expected to materially affect
the Partnership's ability to operate its ongoing business. The Enron facility is
secured by a first priority lien on and security interest in all receivables and
inventory of the Partnership. The borrowing base is the sum of cash and cash
equivalents, specified percentages of eligible receivables, inventory, and
products contracted for or delivered but not billed. The Enron facility is
non-recourse to the General Partner and the General Partner's assets. The
Partnership is restricted from entering into additional financing arrangements
without the prior approval of Enron.
At December 31, 1998, EOTT had a term loan of $175 million outstanding with
Enron under a financing arrangement to fund a portion of the cash consideration
paid to Koch for the assets purchased in 1998 and to refinance indebtedness
incurred in prior acquisitions. The term loan had a scheduled maturity of
December 31, 1999. The interest rate on the term loan was LIBOR plus 300 basis
points. As discussed further below, the term loan was repaid in the fourth
quarter of 1999 utilizing a portion of the net proceeds from the issuance of the
11% senior notes.
In addition, at December 31, 1998, EOTT had $42 million of debt outstanding
with Enron under a $100 million bridge loan to finance a portion of the cash
consideration for the acquisition of assets from Koch. The interest rate on the
bridge loan was initially LIBOR plus 400 basis points. At the end of each
three-month period, the spread on the bridge loan increased by 25 basis points.
The bridge loan was unsecured, and its maturity date was December 31, 1999. As
discussed below, the bridge loan was repaid utilizing a portion of the net
proceeds from the issuance of 3,500,000 Common Units.
On September 29, 1999, EOTT issued 3,500,000 Common Units to the public,
with net proceeds to EOTT of $52.9 million. On October 1, 1999, EOTT issued to
the public $235 million of 11% senior notes. The senior notes are due October 1,
2009, and interest is paid semiannually on April 1 and October 1. The senior
notes are fully and unconditionally guaranteed by all of EOTT's operating
limited partnerships. On or after October 1, 2004, EOTT may redeem the notes,
and prior to October 1, 2002, EOTT may redeem up to 35% of the notes with
proceeds of public or private sales of equity at specified redemption prices.
Provisions of the senior notes could limit additional borrowings, sale and lease
back transactions, affiliate transactions, distributions to unitholders or
merger, consolidation or sale of assets if certain financial performance ratios
are not met. The net proceeds from the issuance of the 11% senior notes and the
issuance of the Common Units were used to repay the $175 million term loan from
Enron, the $42 million bridge loan from Enron and $57.3 million of short-term
borrowings outstanding under the working capital facility from Enron.
At December 31, 1999, EOTT had $143.5 million in letters of credit
outstanding under the Enron facility. In addition, guarantees outstanding
totaled $427.0 million of which $378.5 million were used.
At December 31, 1998, EOTT had $44.4 million in letters of credit and $28.3
million in loans outstanding under the Enron facility at an average annual
interest rate of approximately 6.1%. The amount outstanding at December 31, 1998
under the Term Loan was $175.0 million with an average annual
F-20
<PAGE> 93
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
interest rate of 8.5% and under the Bridge Loan was $42.0 million with an
average annual interest rate of 9.5%. In addition, guarantees outstanding
totaled $366.4 million of which $290.9 million were used.
The General Partner believes that the Enron facility and commodity
repurchase agreements discussed below will be sufficient to support the
Partnership's crude oil purchasing activities and working capital and liquidity
requirements. No assurance, however, can be given that the General Partner will
not be required to reduce or restrict the Partnership's gathering and marketing
activities because of limitations on its ability to obtain credit support and
financing for its working capital needs.
The Partnership's ability to obtain letters of credit to support its
purchases of crude oil or other petroleum products is fundamental to the
Partnership's gathering and marketing activities. Additionally, EOTT has a
significant need for working capital due to the large dollar volume of marketing
transactions in which it engages. Any significant decrease in the Partnership's
financial strength, regardless of the reason for such decrease, may increase the
number of transactions requiring letters of credit or other financial support,
may make it more difficult for the Partnership to obtain such letters of credit,
and/or may increase the cost of obtaining them. This could in turn adversely
affect the Partnership's ability to maintain or increase the level of its
purchasing and marketing activities or otherwise adversely affect the
Partnership's profitability and Available Cash as defined in EOTT's Partnership
Agreement and amendments thereto.
The Partnership Agreement authorizes EOTT to cause the Partnership to issue
additional limited partner interests, the proceeds from which could be used to
provide additional funds for acquisitions or other Partnership needs.
At December 31, 1999, EOTT has outstanding forward commodity repurchase
agreements of approximately $74.1 million. Pursuant to the agreements, which had
terms of thirty days, EOTT repurchased the crude oil inventory on January 21,
2000 for approximately $74.5 million. At December 31, 1998, EOTT had outstanding
forward commodity repurchase agreements of approximately $83.0 million. Pursuant
to the agreements, which had terms of thirty days, EOTT repurchased the crude
oil inventory on January 20, 1999 for approximately $83.4 million.
EOTT has entered into an agreement with a third party which provides for
the sale of up to an aggregate amount of $100 million of certain trade
receivables outstanding at any one time. As of December 31, 1999, $50 million of
receivables had been sold under this agreement. Discount fees related to the
sales are reflected in other, net expenses. EOTT has accounted for these
transactions as a sale under the provisions of Statement of Financial Accounting
Standards No. 125, "Accounting for Transfers and Servicing of Financial Assets
and Extinguishment of Liabilities," and the related cash received is reflected
as cash provided by operating activities in the Consolidated Statements of Cash
Flows.
Generally, the Partnership will distribute 100% of its Available Cash
within 45 days after the end of each quarter to Unitholders of record and to the
General Partner. Available Cash consists generally of all of the cash receipts
of the Partnership adjusted for its cash distributions and net changes to
reserves. The full definition of Available Cash is set forth in the Partnership
Agreement and amendments thereto, forms of which have been filed as exhibits to
this Annual Report on Form 10-K. Distributions of Available Cash to the
Subordinated Unitholders are subject to the prior rights of the Common
Unitholders to receive the Minimum Quarterly Distribution ("MQD") for each
quarter during the Subordination Period, and to receive any arrearages in the
distribution of the MQD on the Common Units for prior quarters during the
Subordination Period.
MQD is $0.475 per Unit. Enron has committed to provide total cash
distribution support in an amount necessary to pay MQDs, with respect to
quarters ending on or before December 31, 2001, in an amount up to an aggregate
of $29 million ($19.7 million of which remains available as of February 14,
F-21
<PAGE> 94
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2000) in exchange for Additional Partnership Interests ("APIs"). See further
discussion in Note 13 regarding Enron's distribution support.
9. INVENTORIES
Inventories are summarized as follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1999 1998
-------- --------
<S> <C> <C>
Crude oil................................................... $115,746 $135,872
Refined products............................................ 4,560 1,673
-------- --------
Total............................................. $120,306 $137,545
======== ========
</TABLE>
10. PROPERTY, PLANT AND EQUIPMENT
Property, Plant and Equipment ("PP&E"), at cost
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1999 1998
-------- --------
<S> <C> <C>
Land........................................................ $ 3,515 $ 3,278
Buildings................................................... 8,045 7,505
Tractors and trailers....................................... 16,053 20,492
Office PP&E, including furniture and fixtures............... 38,672 34,023
Operating PP&E, including pipelines, storage tanks, etc. ... 478,438 432,509
-------- --------
Total PP&E, at cost............................... $544,723 $497,807
======== ========
</TABLE>
Certain assets included in PP&E, primarily pipelines, are affected by
factors, which could affect future cash flows, such as competition,
consolidation in the industry, refinery demand for specific grades of crude oil,
area market price structures and continued development drilling in certain areas
of the United States. EOTT continuously monitors these factors and pursues
alternative strategies to maintain or enhance cash flows associated with these
assets; however, no assurances can be given that EOTT can mitigate the effects,
if any, on future cash flows related to any changes in these factors.
11. SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest was $24.7 million, $8.9 million and $6.2 million for
the years ended December 31, 1999, 1998 and 1997, respectively.
On December 1, 1998, EOTT issued 2,000,000 Common Units and 2,000,000
Subordinated Units to Koch as a portion of the consideration paid for the
Assets. See further discussion of the acquisition of Assets in Note 4.
F-22
<PAGE> 95
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. PARTNERS' CAPITAL
The following is a reconciliation of Units outstanding for the years ended
December 31, 1999, 1998 and 1997:
<TABLE>
<CAPTION>
COMMON SPECIAL SUBORDINATED
UNITS UNITS UNITS
---------- ---------- ------------
<S> <C> <C> <C>
Units Outstanding at December 31, 1996........... 10,000,000 1,830,011 7,000,000
========== ========== =========
Units Outstanding at December 31, 1997........... 10,000,000 1,830,011 7,000,000
========== ========== =========
Acquisition of Common Units for Treasury......... (4,000) -- --
Issuance of Common Units to Koch................. 2,000,000 -- --
Issuance of Special Units to Enron............... -- 1,150,000 --
Issuance of Subordinated Units to Koch........... -- -- 2,000,000
---------- ---------- ---------
Units Outstanding at December 31, 1998........... 11,996,000 2,980,011 9,000,000
========== ========== =========
Conversion of Special Units into Common Units.... 2,980,011 (2,980,011) --
Issuance of Common Units......................... 3,500,000 -- --
---------- ---------- ---------
Units Outstanding at December 31, 1999........... 18,476,011 -- 9,000,000
========== ========== =========
</TABLE>
As discussed further in Note 4, the Partnership issued 2,000,000 Common
Units and 2,000,000 Subordinated Units to Koch in connection with the
acquisition of Assets. In addition, pursuant to a Support Agreement discussed in
Note 13, the Partnership issued 1,150,000 Special Units to Enron in exchange for
Enron's commitment to contribute $21.9 million in APIs outstanding at December
31, 1998.
On February 12, 1999, the Partnership obtained approval of proposals
presented at a Special Meeting of Unitholders. Approval of these proposals,
among other things, (a) authorized the Partnership to issue an additional 10
million Common Units to raise cash to reduce indebtedness, for acquisitions and
other Partnership purposes, (b) changed the terms of the Special Units so that
they became convertible into Common Units and (c) resulted in an increase in
Enron's distribution support to $29 million and an extension of the support
through the fourth quarter of 2001. As a result of the approval of the
proposals, Enron contributed the $21.9 million in APIs outstanding at December
31, 1998.
On September 29, 1999, EOTT issued 3,500,000 Common Units to the public for
net proceeds of $52.9 million. The net proceeds were used to repay loans to
Enron. See further discussion in Note 8.
13. TRANSACTIONS WITH ENRON AND RELATED PARTIES
Revenue and Cost of Sales. A summary of revenue and cost of sales with
Enron and its affiliates follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1999 1998 1997
-------- -------- -------
<S> <C> <C> <C>
Sales to affiliates................................... $ 18,859 $ 10,648 $44,025
Purchases from affiliates............................. $279,167 $232,486 $71,895
</TABLE>
Revenue in 1999, 1998 and 1997 consists primarily of sales of crude oil to
Enron Reserve Acquisition Corp. and natural gas liquids to Enron Gas Liquids,
Inc. Cost of sales consists primarily of crude oil and condensate purchases from
Enron North America Corp. and Enron Reserve Acquisition Corp. These transactions
in the opinion of management are no more or less favorable than can be obtained
from unaffiliated third parties.
F-23
<PAGE> 96
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Other related party balances related to purchases and sales of goods and
services have been classified as trade and other receivables or trade accounts
payable. Related party receivables at December 31, 1999 and 1998 were $2.3
million and $0.2 million, respectively. Related party payables at December 31,
1999 and 1998 were $0.8 million and $1.6 million, respectively. The payables
primarily represent amounts owed by EOTT on the purchase of crude oil and other
products from Enron affiliates.
General and Administrative. As is commonly the case with publicly traded
partnerships, EOTT does not directly employ any persons responsible for managing
or operating the Partnership or for providing services relating to day-to-day
business affairs. The General Partner, under a corporate services agreement,
provides services to the Partnership including liability and casualty insurance
and certain data processing services. The General Partner is reimbursed by the
Partnership for these direct and indirect costs. Those costs were $3.8 million,
$3.3 million and $3.6 million for the years ended December 31, 1999, 1998 and
1997, respectively and are included in operating expenses. Management believes
that the charges were reasonable.
Financing of Acquisitions. As discussed further in Note 4, on July 1, 1998
and December 1, 1998, the Partnership acquired crude oil gathering and
transportation assets from Koch which was financed primarily with borrowings
from Enron. In addition, the Partnership acquired crude oil transportation and
storage assets from Texas-New Mexico Pipeline Company which was financed using
short-term borrowings from Enron. See further discussion in Note 8 regarding the
repayment of borrowings from Enron.
Support Agreement. Pursuant to a Support Agreement dated September 21, 1998
(a) Enron agreed to make loans to the Partnership to fund the cash portion of
the consideration paid to Koch for the Assets at closing as discussed in Note 4
and to refinance indebtedness incurred in the prior acquisition of assets from
Koch on July 1, 1998, (b) Enron agreed to increase and extend the Partnership's
credit facility with Enron to $1 billion through December 31, 2001, (c) the
Partnership agreed to issue 1,150,000 Special Units to Enron, (d) Enron agreed
to contribute $21.9 million in APIs to the Partnership on the earlier of the
date of Unitholder approval of certain proposals, discussed further in Note 12,
or May 17, 1999, (e) Enron agreed that if certain proposals were approved by the
Unitholders it would extend its cash distribution support through the fourth
quarter of 2001, and (f) the Partnership agreed that, if any additional APIs
were issued prior to approval of certain proposals by the Unitholders, it would
issue additional Common Units at $19.00 per share in exchange for such
additional APIs. The Partnership obtained Unitholder approval of these proposals
on February 12, 1999. Pursuant to the Support Agreement, in December 1998 EOTT
borrowed from Enron a $42 million bridge loan and a $175 million term loan,
which were repaid in October 1999, and entered into a $1 billion credit facility
with Enron, to replace its existing $600 million credit facility.
Special Units. Effective July 16, 1996, EOTT created a new class of limited
partner interest designated as Special Units. The Special Units ranked pari
passu with the Common Units in all distributions and upon liquidation and were
voted as a class with the Common Units. In connection with the Support
Agreement, the Partnership issued 1,150,000 Special Units to Enron in December
1998 and, as discussed further below, Enron contributed $21.9 million in APIs to
the Partnership in February 1999. The Special Units were converted into Common
Units in March 1999 on a one-for-one basis pursuant to the Support Agreement
following the favorable vote of Unitholders in February 1999.
Additional Partnership Interests. As of December 31, 1998, Enron had paid
$21.9 million in distribution support. In exchange for the distribution support,
Enron received APIs in the Partnership. APIs have no voting rights and are
non-distribution bearing; however, APIs will be entitled to be redeemed if, with
respect to any quarter, the MQD and any Common Unit Arrearages have been paid,
but only to the extent that Available Cash with respect to such quarter exceeds
the amount necessary to pay the MQD on all Units and any Common Unit Arrearages.
As discussed in Note 12, certain Unitholder approvals were obtained on February
12, 1999 and as a result, Enron increased its cash distribution support
F-24
<PAGE> 97
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to $29 million and extended it through the fourth quarter of 2001 and
contributed the $21.9 million in APIs outstanding at December 31, 1998 pursuant
to its commitment made in connection with the Support Agreement. On May 14, 1999
and February 14, 2000, Enron paid $2.5 million and $6.8 million, respectively,
in support of EOTT's first and fourth quarter 1999 distributions to its Common
Unitholders and received APIs.
14. EMPLOYEE BENEFIT AND RETIREMENT PLANS
Employees of the General Partner are covered by various retirement, stock
purchase and other benefit plans of Enron. In April 1993, the General Partner
adopted non-qualified benefit plans providing medical, dental, life, accidental
death and dismemberment and long-term disability coverage to employees, with all
related premiums and costs being incurred by the General Partner. Total benefit
costs for 1999 were $9.4 million, including $5.7 million in costs attributable
to health and welfare benefit plans. Total benefit costs for 1998 were $6.4
million, including $3.9 million in costs attributable to health and welfare
benefit plans. Total benefit costs for 1997 were $4.2 million including $3.3
million in costs attributable to health and welfare benefit plans.
Additionally, the General Partner maintains a variable pay plan based on
earnings before interest, income taxes, depreciation and amortization of which
$3.0 million was recorded in 1999 and none was recognized in 1998 and 1997.
The General Partner's employees continue benefit accrual under the Enron
Cash Balance Pension Plan ("Cash Balance Plan"). All accrued benefits under the
Cash Balance Plan will be preserved in the Cash Balance Plan until the General
Partner adopts separate plans or participating employees are eligible for
distribution under the plan. The General Partner's employees continue to
participate in the Enron Employee Stock Ownership Plan and continue to be
eligible for participation in the Enron Corp. Savings Plan.
As of September 30, 1999, the most recent valuation date, the plan net
assets, including contributions to the trust during the fourth quarter of 1999,
of the Enron noncontributory defined benefit plan, in which the employees of the
General Partner participate, were less than the actuarial present value of
projected plan benefit obligations by approximately $25.0 million. As of
September 30, 1998, the plan assets, including contributions to the trust during
the fourth quarter of 1998, of the Enron noncontributory defined benefit plan,
in which the employees of the General Partner participate, were less than the
actuarial present value of projected plan benefit obligations by approximately
$25.0 million. The assumed discount rate, rate of return on plan assets and rate
of increases in wages used in determining the actuarial present value of
projected benefits were 7.75%, 10.5%, and 4.0% in 1999, respectively, and 6.75%,
10.5%, and 4.0% in 1998, respectively.
The General Partner provides certain postretirement medical, life insurance
and dental benefits to eligible employees who retire after January 1, 1994.
Benefits are provided under the provisions of contributory defined dollar
benefit plans for eligible employees and their dependents. EOTT accrues these
postretirement benefit costs over the service lives of employees expected to be
eligible to receive such benefits. Enron retains liability for former employees
of the General Partner who retired prior to January 1, 1994. The accumulated
postretirement benefit obligation ("APBO") existing at December 31, 1999 and
1998 totaled $1.1 million and $1.1 million, respectively. The measurement of the
APBO assumes a 7.75% and 6.75% discount rate in 1999 and 1998, respectively.
EOTT does not currently intend to prefund its obligations under the Enron
postretirement benefit plan.
F-25
<PAGE> 98
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth information related to changes in the
benefit obligations, changes in plan assets, a reconciliation of the funded
status of the plans and components of the expense recognized related to
postretirement benefits provided by EOTT (in thousands):
<TABLE>
<CAPTION>
1999 1998
------- -------
<S> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at January 1........................... $ 1,109 $ 745
Service cost.............................................. 178 114
Interest cost............................................. 82 73
Plan amendments........................................... -- 147
Actuarial loss (gain)..................................... (236) 83
Benefits paid............................................. (63) (53)
------- -------
Benefit obligation at December 31................. $ 1,070 $ 1,109
======= =======
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1.................... $ -- $ --
Company contributions..................................... 63 53
Plan participants' contributions.......................... -- --
Benefits paid............................................. (63) (53)
------- -------
Fair value of plan assets at December 31.......... $ -- $ --
======= =======
RECONCILIATION OF FUNDED STATUS TO BALANCE SHEET
Funded status at December 31.............................. $(1,070) $(1,109)
Unrecognized prior service cost........................... 433 469
Unrecognized actuarial gain............................... (581) (364)
------- -------
Accrued benefit cost at December 31............... $(1,218) $(1,004)
======= =======
</TABLE>
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost.............................................. $178 $114 $ 76
Interest cost............................................. 82 73 51
Amortization of prior service cost........................ 36 36 27
Recognized net actuarial gain............................. (19) (22) (14)
---- ---- ----
Total net periodic postretirement benefit cost.... $277 $201 $140
==== ==== ====
</TABLE>
The General Partner provides unemployment, severance and disability-related
benefits or continuation of benefits such as health care and life insurance and
other postemployment benefits. SFAS No. 112 requires the cost of those benefits
to be accrued over the service lives of the employees expected to receive such
benefits. At December 31, 1999 and 1998, the liability accrued was $1.1 million
and $0.7 million, respectively.
EOTT Energy Corp. Unit Option Plan. In February 1994, the Board of
Directors of the General Partner adopted the 1994 EOTT Energy Corp. Unit Option
Plan (the "Unit Option Plan"), which is a variable compensatory plan. To date,
no compensation expense has been recognized under the Unit Option Plan. Under
the Unit Option Plan, selected employees of the General Partner were granted
options to purchase Subordinated Units at a price of $15.00 per Unit as
determined by the Compensation Committee of the Board of Directors of the
General Partner. Options granted under the Unit Option Plan vest to the
employees over a five-year service period and will expire on the tenth
anniversary of the date of grant. No options are vested or exercisable prior to
the third anniversary of the grant.
F-26
<PAGE> 99
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth the Unit Option Plan activity for the years
ended December 31, 1999, 1998 and 1997:
<TABLE>
<CAPTION>
NUMBER OF UNIT OPTIONS
---------------------------------
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
Outstanding at January 1............................ 1,030,000 1,155,000 1,155,000
Granted........................................... -- 400,000 --
Exercised......................................... -- -- --
Forfeited......................................... 105,000 525,000 --
--------- --------- ---------
Outstanding at December 31.......................... 925,000 1,030,000 1,155,000
========= ========= =========
Available for grant at December 31.................. -- -- --
========= ========= =========
</TABLE>
In February 1997, the Board of Directors of the General Partner decided
that it would not grant any additional options under the Unit Option Plan. In
May 1998, options forfeited by a former officer were approved for reissuance by
the Board of Directors to the current President and Chief Executive Officer. In
addition, in February 1997, the Unit Option Plan was amended to provide that, if
the General Partner and the option holder agree, any option may be exercised on
a "net" basis with no cash payment (other than for withholding taxes), so that
upon exercise the holder will receive a number of Units with a fair market value
equal to the difference between the fair market value of the Units covered by
the option and the exercise price of the option. As a result, the General
Partner anticipates that the actual number of Units to be issued on exercise of
options will be substantially less than the number of Units covered by
outstanding options.
In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based
Compensation." This standard establishes a fair value based method of accounting
for stock based compensation plans awarded after December 31, 1995 and
encourages companies to adopt the fair value based method in SFAS No. 123 in
place of the existing accounting method which requires expense recognition only
in situations where stock based compensation plans award intrinsic value to
recipients at the date of grant. Companies that do not follow SFAS No. 123 for
accounting purposes must make annual pro forma disclosure of its effects. EOTT
elected not to adopt the fair value method for accounting purposes. If EOTT had
elected to recognize compensation cost based on the fair value of the options
granted at grant date as prescribed by SFAS No. 123, net income (loss) and net
income (loss) per diluted Unit would have been reduced to the following pro
forma amounts (in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
------ ------- --------
<S> <C> <C> <C>
Net Income (Loss) -- as reported........................ $ (468) $(4,067) $(14,399)
Net Income (Loss) -- pro forma.......................... $ (650) $(4,140) $(14,491)
Diluted Net Income (Loss) per Unit -- as reported....... $(0.02) $ (0.21) $ (0.75)
Diluted Net Income (Loss) per Unit -- pro forma......... $(0.03) $ (0.21) $ (0.75)
</TABLE>
The fair value of each option grant for 1998 is estimated on the date of
grant using the Cox-Ross-Rubenstein binomial method with the following
assumptions: (1) distribution of $1.90 per Common Unit, (2) expected unit price
volatility of 21.86%, (3) risk-free interest rate of 5.97% and (4) expected life
of option of 2 years. The weighted average fair value of options granted during
1998 was $2.119 per unit. No options were granted in 1999.
EOTT Energy Corp. Long-Term Incentive Plan. In October 1997, the Board of
Directors adopted the EOTT Energy Corp. Long Term Incentive Plan ("Plan"), which
is a variable compensatory plan. Under the Plan, selected key employees are
awarded Phantom Appreciation Rights ("PAR"). Each PAR is a
F-27
<PAGE> 100
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
right to receive cash based on the performance of the Partnership prior to the
time the PAR is redeemed. Performance of the Partnership is measured primarily
by calculating the change in the average of Earnings Before Interest on Debt
related to acquisitions, Depreciation and Amortization ("EBIDA"), for each of
the three consecutive fiscal years immediately preceding the grant date of the
PAR and the exercise date of the PAR. The Plan has a five-year term beginning
January 1, 1997, and PAR awards vest in 25% increments in the four-year period
following the grant year.
The following table sets forth the Long-Term Incentive Plan activity for
the years ended December 31, 1999, 1998 and 1997:
<TABLE>
<CAPTION>
NUMBER OF PAR
---------------------------------
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
Outstanding at January 1............................ 637,928 358,600 --
Granted........................................... 967,375 467,828 376,600
Exercised......................................... -- -- --
Forfeited......................................... 128,900 188,500 18,000
--------- --------- ---------
Outstanding at December 31.......................... 1,476,403 637,928 358,600
========= ========= =========
Available for grant at December 31.................. 1,271,198 1,245,072 1,524,400
========= ========= =========
</TABLE>
---------------
Note: Available for grant based on 10% of total MLP units is 2,747,601 as of
December 31, 1999.
15. LITIGATION AND OTHER CONTINGENCIES
EOTT is, in the ordinary course of business, a defendant in various
lawsuits, some of which are covered in whole or in part by insurance. The
Partnership is responsible for all litigation and other claims relating to the
business acquired from the Predecessor, although the Partnership will be
entitled to the benefit of certain insurance maintained by Enron covering
occurrences prior to the closing of the initial public offering. The Partnership
believes that the ultimate resolution of litigation, individually and in the
aggregate, will not have a materially adverse impact on the Partnership's
financial position or results of operations. Various legal actions have arisen
in the ordinary course of business, the most significant of which are discussed
below.
State of Texas Royalty Suit. EOTT was served on November 9, 1995 with a
petition styled The State of Texas, et al. vs. Amerada Hess Corporation, et al.
The matter was filed in District Court in Lee County, Texas and involves several
major and independent oil companies and marketers as defendants. The plaintiffs
are attempting to put together a class action lawsuit alleging that the
defendants acted in concert to buy oil owned by members of the plaintiff class
in Lee County, Texas, and elsewhere in Texas, at "posted" prices, which the
plaintiffs allege were lower than true market prices. There is not sufficient
information in the petition to fully quantify the allegations set forth in the
petition, but the General Partner believes that any such claims against the
Partnership will prove to be without merit.
The State of Texas, et al. vs. Amerada Hess Corporation, et al., Cause No.
97-12040; In the 53rd Judicial District Court of Travis County, Texas (Common
Purchaser Act Suit). This case was filed on October 23, 1997 in Austin by the
Texas Attorney General's office and involves several major and independent oil
companies and marketers as defendants. EOTT was served on November 18, 1997. The
petition states that the State of Texas brought this action in its sovereign
capacity to collect statutory penalties recoverable under the Texas Common
Purchaser Act, arising from defendants' alleged willful breach of statutory
duties owed to royalty, overriding royalty and working interest owners of crude
oil sold to defendants, as well as alleged breach of defendants' common law and
contractual duties. The plaintiffs also allege that the defendants have engaged
in discriminatory pricing of crude oil. This case appears to be
F-28
<PAGE> 101
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
similar to the State of Texas Royalty Suit filed by the State of Texas on
November 9, 1995. EOTT and several of the defendants reached a settlement with
the State in the Common Purchaser Act Suit in a Settlement Agreement dated
August 5, 1999. Settlement amounts for each defendant were confidential. This
settlement disposed of any claims the State may have in the State of Texas
Royalty Suit, discussed above, but did not dismiss that case. Also, any
severance tax claims the State may have were specifically excluded from this
settlement. However, no severance tax claims were asserted in the petition filed
by the plaintiffs.
McMahon Foundation and J. Tom Poyner vs. Amerada Hess Corporation, et al.
(Including EOTT Energy Operating Limited Partnership), Civil Action No.
H-96-1155; United States District Court, Southern District of Texas, Houston
Division (Texas Federal Anti-Trust Suit). This suit was filed on April 10, 1996
as a class action complaint for violation of the federal antitrust laws and
involves several major and independent oil companies and marketers as
defendants. The relevant area is the entire continental United States, except
for Alaska, New York, Ohio, Pennsylvania, West Virginia and the Wilmington Field
at Long Beach, California. The plaintiffs claim that there is a combination and
conspiracy among the defendant oil companies to fix, depress, stabilize and
maintain at artificially low levels the price paid for the first purchase of
lease production oil sold from leases in which the class members own interests.
This was allegedly accomplished by agreement of the defendants to routinely pay
for first purchases at posted prices rather than competitive market prices and
maintain them in a range below competitive market prices through an undisclosed
scheme of using posted prices in buy/sell transactions among themselves to
create the illusion that posted prices are genuine market prices. The plaintiffs
allege violations from October of 1986 forward. No money amounts were claimed,
and it is not possible to determine any potential exposure until further
discovery is done.
Randolph Energy, Inc., et al. vs. Amerada Hess Corporation, et al., Civil
Action No. 2:97CV273PG; In the United States District Court for the Southern
District of Mississippi, Jackson Division (Mississippi Federal Anti-Trust
Suit). EOTT received the summons in this matter on August 18, 1997. The case was
filed on August 5, 1997 and is a class action complaint for alleged violation of
the federal antitrust laws which involves several major and independent oil
companies and marketers as defendants. The plaintiffs claim that this litigation
arises out of a combination and conspiracy of the defendant oil companies to
fix, depress, stabilize and maintain at artificially low levels the prices paid
for the first purchase of lease production oil sold from leases in which the
class members own interests. The issues appear to be a duplication of the issues
in the Texas Federal Anti-Trust Suit previously discussed. No money amounts were
claimed, and it is not possible to determine any potential exposure until
further discovery is done.
Cameron Parish School Board, et al. vs. Texaco, Inc., et al.; Civil Action
No. C-98-111; In the United States District Court for the Western District of
Louisiana, Lake Charles Division (Louisiana Federal Anti-Trust Suit). This case
was originally filed as a state law claim in Louisiana. When the case was
removed to federal court, the anti-trust claims were added, similar to the
claims made in the Texas Federal Anti-Trust Suit and the Mississippi Federal
Anti-Trust Suit. The plaintiffs claim that this litigation arises out of a
combination and conspiracy of the defendant oil companies to fix, depress,
stabilize and maintain at artificially low levels the prices paid for the first
purchase of lease production oil sold from leases in which the class members own
interests. The issues appear to be a duplication of the issues in the Texas
Federal Anti-Trust Suit and the Mississippi Federal Anti-Trust Suit, both
previously discussed. On October 22, 1998, the judge granted the Plaintiffs'
motion to amend the petition and add additional defendants. The Partnership and
the General Partner were added to the case as defendants at that time. No money
amounts were claimed and it is not possible to determine any potential exposure
until further discovery is done.
The Texas Federal Anti-Trust Suit, the Mississippi Federal Anti-Trust Suit
and the Louisiana Federal Anti-Trust Suit, along with several other suits to
which EOTT is not a party, were consolidated and
F-29
<PAGE> 102
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
transferred to the Southern District of Texas by Transfer Order dated January
14, 1998. The Judicial Panel on Multidistrict Litigation made this
recommendation due to similarity of issues in the cases. EOTT and the General
Partner, along with a number of other defendants, have entered into a class-wide
settlement with the defendants which was approved by the Court on April 7, 1999,
with a Final Judgment entered on August 11, 1999. Several appeals have been
filed concerning the settlement. Consequently, the settlement has not been
funded, nor has the case been dismissed.
Assessment for Crude Oil Production Tax from the Comptroller of Public
Accounts, State of Texas. The Partnership received a letter from the
Comptroller's Office dated October 9, 1998 assessing the Partnership for
severance taxes the Comptroller's Office alleges are due on a difference the
Comptroller's Office believes exists between the market value of crude oil and
the value reported on the Partnership's crude oil tax report for the period of
September 1, 1994 through December 31, 1997. The letter states that the action,
based on a desk audit of the Partnership's crude oil production reports, is
partly to preserve the statute of limitations where crude oil severance tax may
not have been paid on the true market price of the crude oil. The letter further
states that the Comptroller's position is similar to claims made in several
lawsuits, including the Texas Federal Anti-Trust Suit, in which the Partnership
is a defendant. The amount of the assessment, including penalty and interest, is
approximately $1.1 million. While the claim is still being reviewed, the General
Partner believes the Partnership should be without liability in this or related
matters.
General Matters. EOTT believes that it has obtained or has applied for all
of the necessary permits required by federal, state, and local environmental
agencies for the operation of its business. Further, the Partnership believes
that there are no outstanding liabilities or claims relating to environmental
matters, individually and in the aggregate, which would have a material adverse
impact on the Partnership's financial position or results of operations.
16. COMMITMENTS
Operating Leases. EOTT leases certain real property, equipment, and
operating facilities under various operating leases. Future non-cancelable
commitments related to these items at December 31, 1999, are summarized below
(in thousands):
<TABLE>
<S> <C>
2000....................................................... $5,245
2001....................................................... 4,748
2002....................................................... 3,459
2003....................................................... 3,001
2004....................................................... 2,121
Later years................................................ 3,991
</TABLE>
Total lease expense incurred was $10.4 million, $10.9 million and $10.3
million for the years ended December 31, 1999, 1998 and 1997, respectively.
F-30
<PAGE> 103
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
17. OTHER INCOME (EXPENSE), NET
The components of other income (expense), net, are as follows (in
thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
1999 1998 1997
----- ------- -------
<S> <C> <C> <C>
Gain (loss) on foreign currency transactions.............. $ 485 $(1,055) $(1,488)
Gain (loss) on disposal of fixed assets................... 636 (66) 503
Rental income............................................. 36 60 90
Litigation settlements and provisions..................... 256 (969) 130
Discount fees on sale of receivables...................... (732) -- --
Other..................................................... 61 225 (1)
----- ------- -------
Total........................................... $ 742 $(1,805) $ (766)
===== ======= =======
</TABLE>
18. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following disclosures on the estimated fair value of financial
instruments are presented in accordance with the requirements of SFAS No. 107,
"Disclosures About Fair Value of Financial Instruments" and SFAS No. 119,
"Disclosures About Derivative Financial Instruments and Fair Value of Financial
Instruments." Fair value as defined in SFAS No. 107 represents the amount at
which the instrument could be exchanged in a current transaction between willing
parties. The estimated fair value amounts have been determined by EOTT using
available market data and valuation methodologies. Judgment is required in
interpreting market data and the use of different market assumptions or
estimation methodologies may affect the estimated fair value amounts.
Credit Risk. In the normal course of business, EOTT extends credit to
various companies in the energy industry. Within this industry, certain elements
of credit risk exist and may, to varying degrees, exceed amounts recognized in
the accompanying consolidated financial statements, which may be affected by
changes in economic or other external conditions and may accordingly impact
EOTT's overall exposure to credit risk. EOTT's exposure to credit loss in the
event of nonperformance is limited to the book value of the trade commitments
included in the accompanying Consolidated Balance Sheets. EOTT manages its
exposure to credit risk through credit analysis, credit approvals, credit limits
and monitoring procedures. Further, the General Partner believes that its
portfolio of receivables is well diversified and that the allowance for doubtful
accounts is adequate to absorb any potential losses. EOTT requires collateral in
the form of letters of credit for certain of its receivables.
Market Risk. EOTT trading and non-trading transactions give rise to market
risk, which represents the potential loss that can be caused by a change in the
market value of a particular commitment. EOTT closely monitors and manages its
exposure to market risk to ensure compliance with EOTT's stated risk management
policies which are regularly assessed to ensure their appropriateness given
EOTT's objectives, strategies and current market conditions.
F-31
<PAGE> 104
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table presents the carrying amounts and estimated fair values
of the Partnership's financial instruments at December 31, 1999 and 1998 (in
millions):
<TABLE>
<CAPTION>
1999 1998
----------------- -----------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ------ -------- ------
<S> <C> <C> <C> <C>
Financial assets
Cash and cash equivalents....................... $ 17.5 $ 17.5 $ 3.0 $ 3.0
Foreign currency contracts...................... -- 22.6 -- 12.2
Financial liabilities
Short-term borrowings........................... $ -- $ -- $ 28.3 $ 28.3
Bridge loan..................................... -- -- 42.0 42.0
Term loan....................................... -- -- 175.0 175.0
Repurchase agreements........................... 74.1 74.1 83.0 83.0
Foreign currency contracts...................... -- 22.6 -- 12.2
Senior notes.................................... 235.0 235.0 -- --
</TABLE>
The following methods and assumptions were used to estimate the fair value
of financial instruments:
Cash and cash equivalents, short-term borrowings, bridge loan, term loan
and repurchase agreements. Fair value for these current assets and liabilities
was considered to be the same as the carrying amounts because of their liquidity
and market-based interest where applicable.
Foreign currency contracts. Quoted market prices are used in determining
the fair value of financial instruments held or issued. If quoted prices are not
available, fair values are estimated on the basis of pricing models or quoted
prices for financial instruments with similar characteristics.
Senior notes. These notes represent long-term borrowings on which the
carrying amounts approximate fair value because the effective annual interest
rates of these instruments reflect interest rates at December 31, 1999.
Other Than Trading Activities
EOTT enters into forward, futures and other contracts to hedge the impact
of market fluctuations on assets, lease crude oil purchases or other contractual
commitments. However, EOTT does not consider its commodity futures and forward
contracts to be financial instruments since these contracts require or permit
settlement by the delivery of the underlying commodity, and thus are not subject
to the provisions of SFAS No. 119. Changes in the market value of these
transactions are deferred until the gain or loss is recognized on the hedged
transaction at which time such gains and losses are recognized through cost of
sales.
EOTT routinely enters into foreign currency futures contracts to hedge
foreign currency exposure from commercial transactions relating to current month
crude purchases and sales as well as fixed price swaps. These contracts
generally mature in one year or less. At December 31, 1999 and 1998, foreign
currency contracts with a notional principal amount of $22.6 million and $11.7
million, respectively, were outstanding, having exchange rates which
approximated current market exchange rates.
Trading Activities
Prior to 1998, EOTT offered limited price risk management products to the
energy sector which were not material to EOTT's financial position or results of
operations. These products included swap agreements which required payments to
(or receipt of payments from) counterparties based on the differential between a
fixed and variable price for the commodities specified, options and other
contractual
F-32
<PAGE> 105
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
arrangements. EOTT accounted for these activities using the mark-to-market
method of accounting and recorded the gain or loss as a cost of sales in the
period of the change in the market with an offsetting entry to trade accounts
receivable or payable as appropriate. In connection with the realignment
initiatives discussed in Note 6, EOTT ceased providing price risk management
products to its customers. See discussion regarding adoption of Emerging Issues
Task Force Issue 98-10 in Note 3.
19. NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities". The Statement
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. The Statement requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that a company must formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting. SFAS No. 133, as amended, is effective for fiscal years
beginning after June 15, 2000. The standard cannot be applied retroactively but
early adoption is permitted. EOTT has not yet determined the impact of adopting
SFAS No. 133; however, this standard could increase volatility in earnings and
partners' capital, through other comprehensive income.
20. BUSINESS SEGMENT INFORMATION
EOTT has three reportable segments, which management reviews in order to
make decisions about resources to be allocated and assess its performance: North
American Crude Oil -- East of Rockies, Pipeline Operations and West Coast
Operations. The North American Crude Oil -- East of Rockies segment primarily
purchases, gathers, transports and markets crude oil. The Pipeline Operations
segment operates approximately 8,300 active miles of common carrier pipelines
operated in 13 states. The West Coast Operations include crude oil gathering and
marketing, refined products marketing and a natural gas liquids business.
The accounting policies of the segments are the same as those described in
the summary of significant accounting policies as discussed in Note 2. EOTT
evaluates performance based on operating income (loss).
EOTT accounts for intersegment revenue and transfers between North American
Crude Oil -- East of Rockies and West Coast Operations as if the sales or
transfers were to third parties, that is, at current market prices. Intersegment
revenues for Pipeline Operations are based on published pipeline tariffs.
F-33
<PAGE> 106
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FINANCIAL INFORMATION BY BUSINESS SEGMENT
<TABLE>
<CAPTION>
NORTH
AMERICAN CORPORATE
CRUDE OIL PIPELINE WEST COAST AND
-EOR(a)(b) OPERATIONS(a) OPERATIONS(a)(c) OTHER(b)(d) CONSOLIDATED
---------- ------------- ---------------- ----------- ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1999
Revenue from external
customers............... $7,999,092 $ 28,647 $636,676 $ (14) $8,664,401
---------- -------- -------- --------- ----------
Intersegment revenue(e).... 43,653 89,890 17,360 (150,903) --
---------- -------- -------- --------- ----------
Total revenue........... 8,042,745 118,537 654,036 (150,917) 8,664,401
---------- -------- -------- --------- ----------
Gross margin............... 78,195 115,650 18,518 (48) 212,315
---------- -------- -------- --------- ----------
Operating income (loss).... (2,499) 50,963 (2,197) (20,282) 25,985
Other expense.............. -- -- -- (28,200) (28,200)
---------- -------- -------- --------- ----------
Net income (loss) before
cumulative effect of
accounting change....... (2,499) 50,963 (2,197) (48,482) (2,215)
---------- -------- -------- --------- ----------
Long-lived assets.......... 77,247 285,180 32,605 9,463 404,495
---------- -------- -------- --------- ----------
Total assets............ 1,084,613 306,321 129,461 38,266 1,558,661
---------- -------- -------- --------- ----------
Additions to long-lived
assets.................. 1,194 49,544 1,353 6,638 58,729
---------- -------- -------- --------- ----------
Depreciation and
amortization............ 8,704 20,012 2,669 1,751 33,136
---------- -------- -------- --------- ----------
YEAR ENDED DECEMBER 31, 1998
Revenue from external
customers............... $4,590,810 $ 7,036 $586,169 $ 110,682 $5,294,697
Intersegment revenue(e).... 47,008 24,516 3,900 (75,424) --
---------- -------- -------- --------- ----------
Total revenue........... 4,637,818 31,552 590,069 35,258 5,294,697
---------- -------- -------- --------- ----------
Gross margin............... 92,071 30,856 9,698 (20) 132,605
---------- -------- -------- --------- ----------
Operating income (loss).... 28,050 4,285 199 (25,305) 7,229
Other expense.............. -- -- -- (11,296) (11,296)
---------- -------- -------- --------- ----------
Net income (loss).......... 28,050 4,285 199 (36,601) (4,067)
---------- -------- -------- --------- ----------
Long-lived assets.......... 83,866 270,739 25,335 5,299 385,239
---------- -------- -------- --------- ----------
Total assets............ 608,655 279,315 60,677 17,173 965,820
---------- -------- -------- --------- ----------
Additions to long-lived
assets.................. 18,398 222,121 23,275 2,775 266,569
---------- -------- -------- --------- ----------
Depreciation and
amortization............ 9,263 9,287 470 1,931 20,951
---------- -------- -------- --------- ----------
</TABLE>
F-34
<PAGE> 107
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
NORTH
AMERICAN CORPORATE
CRUDE OIL PIPELINE WEST COAST AND
-EOR(a)(b) OPERATIONS(a) OPERATIONS(a)(c) OTHER(b)(d) CONSOLIDATED
---------- ------------- ---------------- ----------- ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1997
Revenue from external
customers............... $6,070,799 $ 5,687 $809,466 $ 760,147 $7,646,099
Intersegment revenue(e).... 1,795 13,717 1,783 (17,295) --
---------- -------- -------- --------- ----------
Total revenue........... 6,072,594 19,404 811,249 742,852 7,646,099
---------- -------- -------- --------- ----------
Gross margin............... 82,562 19,539 9,342 1,602 113,045
---------- -------- -------- --------- ----------
Operating income (loss).... 19,506 1,821 58 (28,977) (7,592)
Other expense.............. -- -- -- (6,807) (6,807)
---------- -------- -------- --------- ----------
Net income (loss).......... 19,506 1,821 58 (35,784) (14,399)
---------- -------- -------- --------- ----------
Long-lived assets.......... 61,032 76,276 2,486 6,426 146,220
---------- -------- -------- --------- ----------
Total assets............ 604,663 80,528 63,279 34,451 782,921
---------- -------- -------- --------- ----------
Additions to long-lived
assets.................. 4,923 13,349 234 4,331 22,837
---------- -------- -------- --------- ----------
Depreciation and
amortization............ 7,807 6,030 500 2,181 16,518
---------- -------- -------- --------- ----------
</TABLE>
---------------
(a) 1999 includes twelve months of results of operations associated with the
assets acquired from Koch and eight months of results of operations
associated with the assets acquired from Texas-New Mexico Pipeline.
(b) 1999 includes nonrecurring severance charges of $2.0 million of which $1.8
million is recorded in North American Crude Oil -- EOR and $0.2 million is
recorded in Corporate.
(c) 1999 includes nonrecurring charges of $7.8 million of costs related to
mid-continent NGL activities.
(d) Corporate and Other also includes intersegment eliminations and the East of
Rockies products business in 1998 and 1997.
(e) Intersegment sales for North American Crude Oil -- EOR and West Coast
Operations are made at prices comparable to those received from external
customers. Intersegment sales for Pipeline Operations are based on
published pipeline tariffs.
21. SUBSEQUENT EVENTS
On January 21, 2000, the Board of Directors of EOTT Energy Corp., as
General Partner, declared the Partnership's regular quarterly cash distribution
of $0.475 per Unit for the period October 1, 1999 through December 31, 1999. The
total distribution of approximately $8.9 million was paid on February 14, 2000
to the General Partner and all Common Unitholders of record as of the close of
business on January 31, 2000. The fourth quarter distribution was paid utilizing
$2.1 million of Available Cash from the Partnership and $6.8 million of cash
provided by Enron pursuant to Enron's distribution support obligation. After
payment of the fourth quarter distribution in February 2000, the remaining
distribution support available from Enron is $19.7 million.
F-35
<PAGE> 108
EOTT ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
22. QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER(1)(2) TOTAL
---------- ---------- ---------- ------------- ----------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
1999
Revenues...................... $1,433,157 $2,259,303 $2,315,464 $2,656,477 $8,664,401
Gross margin.................. 52,796 55,697 57,060 46,762 212,315
Operating income.............. 8,473 8,715 8,110 687 25,985
Net income (loss) before
cumulative effect of
accounting change.......... 2,534 2,182 550 (7,481) (2,215)
Basic net income (loss) before
cumulative effect of
accounting change per Unit
Common..................... 0.08 0.09 0.02 (0.27) (0.13)
Subordinated............... 0.15 0.09 0.02 (0.27) (0.01)
Diluted net income (loss)
before cumulative effect of
accounting change per
Unit....................... 0.10 0.09 0.02 (0.27) (0.09)
Cash distributions per Common
Unit(3).................... 0.475 0.475 0.475 0.475 1.900
1998
Revenues...................... $1,339,404 $1,231,875 $1,295,652 $1,427,766 $5,294,697
Gross margin.................. 27,547 29,156 33,736 42,166 132,605
Operating income (loss)....... (357) 1,157 1,153 5,276 7,229
Net income (loss)............. (1,723) (1,274) (1,806) 736 (4,067)
Basic net income (loss) per
Unit
Common..................... (0.09) (0.06) (0.03) 0.01 (0.17)
Subordinated............... (0.09) (0.07) (0.20) 0.08 (0.26)
Diluted net income (loss) per
Unit....................... (0.09) (0.07) (0.09) 0.03 (0.21)
Cash distributions per Common
Unit(3).................... 0.475 0.475 0.475 0.475 1.90
</TABLE>
---------------
(1) Fourth quarter 1999 amounts include nonrecurring items of $9.8 million
related to the mid-continent NGL activities and severance costs associated
with the reduction of work force. See Note 6 to the Consolidated Financial
Statements.
(2) Fourth quarter 1998 amounts include the acquisition of the Assets from Koch
on December 1, 1998. See Note 4 to the Consolidated Financial Statements.
(3) Cash distributions are shown in the quarter paid and are based on the prior
quarter's earnings.
F-36
<PAGE> 109
SCHEDULE II
EOTT ENERGY PARTNERS, L.P.
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
BALANCE AT CHARGED TO BALANCE
BEGINNING COSTS AND DEDUCTIONS AT END
OF PERIOD EXPENSES AND OTHER OF PERIOD
---------- ---------- ---------- ---------
<S> <C> <C> <C> <C>
Year Ended December 31, 1997
Allowance for Doubtful Accounts................... $2,266 $ -- $ (606) $1,660
Year Ended December 31, 1998
Allowance for Doubtful Accounts................... $1,660 $ 700 $ (500) $1,860
Litigation Provisions............................. $ -- $1,400 $ -- $1,400
Safety and Environmental.......................... $ -- $ -- $1,000 $1,000
Year Ended December 31, 1999
Allowance for Doubtful Accounts................... $1,860 $ -- $ (128) $1,732
Litigation Provisions............................. $1,400 $ -- $ (400) $1,000
Safety and Environmental.......................... $1,000 $ -- $1,998 $2,998
</TABLE>
S-1
<PAGE> 110
APPENDIX I
FORM OF TRANSFER APPLICATION
No transfer of the Common Units evidence hereby will be registered on the
books of the Partnership, unless the Certificate evidencing the Common Units to
be transferred is surrendered for registration or transfer and an Application
for Transfer of Common Units has been executed by a transferee either (a) on the
form set forth below or (b) on a separate application that the Partnership will
furnish on request without charge. A transferor of the Common Units shall have
no duty to the transferee with respect to execution of the transfer application
in order for such transferee to obtain registration of the transfer of the
Common Units.
APPLICATION FOR TRANSFER OF COMMON UNITS
The undersigned ("Assignee") hereby applies for transfer to the name of the
Assignee of the Common Units evidenced hereby.
The Assignee (a) requests admission as a Substituted Limited Partner and
agrees to comply with and be bound by, and hereby executes, the Amended and
Restated Agreement of Limited Partnership of EOTT Energy Partners, L.P. (the
"Partnership"), as amended, supplemented or restated to the date hereof (the
"Partnership Agreement"), (b) represents and warrants that the Assignee has all
right, power and authority and, if an individual, the capacity necessary to
enter into the Partnership Agreement, (c) appoints the General Partner and, if a
Liquidator shall be appointed, the Liquidator of the Partnership as the
Assignee's attorney-in-fact to execute, swear to, acknowledge and file any
documents, including, without limitation, the Partnership Agreement and any
amendment thereto and the Certificate of Limited Partnership of the Partnership
and any amendment thereto, necessary or appropriate for the Assignee's admission
as a Substituted Limited Partner and as a party to the Partnership Agreement,
(d) gives the powers of attorney provided for in the Partnership Agreement and
(e) makes the waivers and gives the consents and approvals contained in the
Partnership Agreement. Capitalized terms not defined herein have the meanings
assigned to such terms in the Partnership Agreement.
<TABLE>
<S> <C>
Date: ---------------------------------------------------------------- --------------------------------------------
Signature of Assignee
-------------------------------------------- --------------------------------------------
Social Security or other identifying number Name and Address of Assignee
of Assignee
--------------------------------------------
Purchase Price including commissions, if any
</TABLE>
Type of entity (check one)
------------------------ Individual
------------------------ Partnership
------------------------ Corporation
------------------------ Trust
------------------------ Other (specify)
-------------------------------------
Nationality (Check One):
--------------------- U.S. Citizen, Resident or Domestic Entity
--------------------- Foreign Corporation, or
--------------------- Non-resident alien
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<PAGE> 111
If the U.S. citizen, Resident or Domestic Entity box is checked, the
following certification must be completed.
Under Section 1445(e) of the Internal Revenue Code of 1986, as amended (the
"Code"), the Partnership must withhold tax with respect to certain transfers of
property if a holder of an interest in the Partnership is a foreign person. To
inform the Partnership that no withholding is required with respect to the
undersigned interest-holder's interest in it, the undersigned hereby certifies
the following (or, if applicable, certifies the following the behalf of the
interest-holder).
Complete Either A or B:
A. Individual Interest-Holder
1. I am not a non-resident alien for purposes of U.S. income taxation.
2. My U.S. taxpayer identifying number (Social Security Number) is
-----------------------------------.
3. My home address is
-------------------------------------------------------------------------.
B. Partnership, Corporate or Other Interest-Holder
1.
-------------------------------------------------------------------------------
is not a foreign corporation,
(Name of Interest-Holder)
foreign partnership, foreign trust or foreign estate (as those terms
are defined in the Code and Treasury Regulations).
2. The interest-holder's U.S. employer identification number is
-----------------------------.
3. The interest-holder's office address and place of incorporation (if
applicable is)
---------------
-----------------------------------------------.
The interest-holder agrees to notify the Partnership within sixty (60) days
of the date the interest-holder becomes a foreign person.
The interest-holder understands that this certificate may be disclosed to
the Internal Revenue Service by the Partnership and that any false statement
contained herein could be punishable by fine, imprisonment or both.
Under penalties of perjury, I declare that I have examined this
certification and to the best of my knowledge and belief it is true, correct and
complete and, if applicable, I further declare that I have authority to sign
this documents on behalf of
------------------------------------------------------
(Name of Interest-Holder)
------------------------------------------------------
(Signature and Date)
------------------------------------------------------
Title (if applicable)
Note: If the Assignee is a broker, dealer, bank, trust company, clearing
corporation, other nominee holder or an agent of any of the foregoing, and is
holding for the account of any other person, this application should be
completed by an officer thereof or, in the case of a broker or dealer, by a
registered representative who is a member of a registered national securities
exchange or a member of the National Association of Securities Dealers Inc., or,
in the case of any other nominee holder, a person performing a similar function.
If the Assignee is a broker, dealer, bank trust company, clearing corporation,
other nominee owner or a agent of any of the forging, the above certification as
to any Person for whom the Assignee will hold the Common Units shall be made to
the best of the Assignee's knowledge.
I-2
<PAGE> 112
EOTT ENERGY PARTNERS, L.P.
<PAGE> 113
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
The following table sets forth the costs and expenses, other than
underwriting discounts and commissions, payable by EOTT Energy Partners, L.P. in
connection with the sale of common stock being registered. All amounts are
estimates except the SEC registration fee and the Nasdaq listing fee.
<TABLE>
<S> <C>
SEC Registration fee..................................... $ 6,831
Legal fees and expenses.................................. 50,000
Accounting fees and expenses............................. 55,000
Miscellaneous expenses................................... 75,000
--------
Total.......................................... $186,831
========
</TABLE>
---------------
* To be provided by amendment.
ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
The partnership agreement provides that EOTT Energy Partners, L.P. (the
"Partnership") will indemnify our general partner, any Departing Partner and any
Person who is or was an officer or director of our general partner or any
Departing Partner, any person who is or was an affiliate of our general partner
or any Departing Partner, any Person who is or was an employee, partner, agent
or trustee of our general partner or any Departing Partner or any affiliate of
our general partner or any Departing Partner or any Person who is or was serving
at the request of our general partner or any affiliate of our general partner or
any Departing Partner as an officer, director, employee, partner, agent or
trustee of another person ("Indemnitees"), to the fullest extent permitted by
law, from and against any and all losses, claims, damages, liabilities (joint or
several) expenses (including, without limitation, legal fees and expenses),
judgments, fines, penalties, interest, settlements and other amounts arising
from any and all claims, demands, actions, suits or proceedings, whether civil,
criminal, administrative or investigative, in which any Indemnitee may be
involved or is threatened to be involved, as a party or otherwise, by reason of
its status as (i) our general partner, Departing Partner or affiliate of either,
(ii) an officer, director, employee, partner, agent or trustee of our general
partner, Departing Partner or affiliate of either or (iii) a person serving at
the request of the Partnership in another entity in a similar capacity, provided
that in each case the Indemnitee acted in good faith and in a manner which such
Indemnitee believed to be in or not opposed to the best interest of the
Partnership and, with respect to any criminal proceeding, had no reasonable
cause to believe its conduct was unlawful. Any indemnification under these
provisions will be only out of the assets of the Partnership and our general
partner shall not be personally liable for or have any obligation to contribute
or loan funds or assets to the Partnership to enable it to effectuate, such
indemnification. The Partnership is authorized to purchase (or to reimburse our
general partner or its affiliates for the cost of) insurance against liabilities
asserted against and expenses incurred by such person in connection with the
Partnership's activities, whether or not the Partnership would have the power to
indemnify such person against such liabilities under the provisions described
above.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.
During the past three years, we have issued unregistered securities to a
limited number of persons, as described below. None of these transactions
involved any underwriters, underwriting discounts or commissions, or any public
offering, and we believe that each transaction was exempt from the registration
II-1
<PAGE> 114
requirements of the Securities Act by virtue of Section 4(2) thereof or
Regulation D promulgated thereunder.
(a) We issued 3,684,135 additional partnership interests to Enron Corp. on
November 14, 1997 in consideration for $3,684,135.
(b) We issued 3,837,585 additional partnership interests to Enron Corp. on
February 14, 1998 in consideration for $3,837,585.
(c) We issued 2,839,665 additional partnership interests to Enron Corp. on
May 14, 1998 in consideration for $2,839,665.
(d) We issued 2,475,345 additional partnership interests to Enron Corp. on
August 14, 1998 in consideration for $2,475,345.
(e) We issued 1,150,000 special units to Enron Corp. on December 1, 1998 in
consideration for $15,904,500.
(f) We issued 1,996,000 common units to Koch Pipeline Co. on December 1,
1998 as part of the consideration for the purchase of crude oil gathering and
transportation assets.
(g) We issued 2,000,000 subordinated units to Koch Pipeline Co. on December
1, 1998 as part of the consideration for the purchase of crude oil gathering and
transportation assets.
(h) We issued 2,547,310 additional partnership interests to Enron Corp. on
November 14, 1997 in consideration for $2,547,310.
(i) We issued 3,770,901 additional partnership interests to Enron Corp. on
November 14, 1997 in consideration for $3,770,901.
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Exhibits
<TABLE>
<C> <S>
3.1 -- Form of Partnership Agreement of EOTT Energy Partners,
L.P. (incorporated by reference to Exhibit 3.1 to
Registration Statement, File No. 33-73984)
3.2 -- Amendment No. 1 dated as of August 8, 1995, to the
Amended and Restated Agreement of Limited Partnership of
EOTT Energy Partners, L.P. (incorporated by reference to
Exhibit 3.2 to Annual Report on Form 10-K for the Year
Ended December 31, 1995)
3.3 -- Amendment No. 2 dated as of July 16, 1996, to the Amended
and Restated Agreement of Limited Partnership of EOTT
Energy Partners, L.P. (incorporated by reference to
Exhibit 3.3 to Quarterly Report on Form 10-Q for the
Quarter Ended June 30, 1996)
3.4 -- Amendment No. 3 dated as of February 13, 1997, to the
Amended and Restated Agreement of Limited Partnership of
EOTT Energy Partners, L.P. (incorporated by reference to
Exhibit 3.4 to Annual Report on Form 10-K for the Year
Ended December 31, 1998)
3.5 -- Amendment No. 4 dated as of November 30, 1998, to the
Amended and Restated Agreement of Limited Partnership of
EOTT Energy Partners, L.P. (incorporated by reference to
Exhibit 3.5 to Annual Report on Form 10-K for the Year
Ended December 31, 1998)
3.6 -- Amendment No. 5 dated as of December 7, 1998, to the
Amended and Restated Agreement of Limited Partnership of
EOTT Energy Partners, L.P. (incorporated by reference to
Exhibit 3.6 to Annual Report on Form 10-K for the Year
Ended December 31, 1998)
</TABLE>
II-2
<PAGE> 115
<TABLE>
<S> <C>
3.7 -- Amendment No. 6 dated as of September 16, 1999 to the Amended and Restated Agreement of
Limited Partnership of EOTT Energy Partners, L.P. (incorporated by reference to Exhibit
3.1 to Current Report on Form 8-K dated September 29, 1999)
4.1 -- Form of Indenture for Senior Debt Securities and Subordinated Debt Securities
(incorporated by reference to Exhibit 4.1 to Registration Statement, File No.
333-82269)
*5.1 -- Opinion of Vinson & Elkins L.L.P. as to legality of securities
*8.1 -- Tax opinion of Vinson & Elkins L.L.P.
10.04 -- Form of Corporate Services Agreement between Enron Corp. and EOTT Energy Corp.
(incorporated by reference to Exhibit 10.08 to Registration Statement, File No.
33-73984)
10.05 -- Form of Contribution and Closing Agreement between EOTT Energy Corp. and EOTT Energy
Partners, L.P. (incorporated by reference to Exhibit 10.09 to Registration Statement,
File No. 33-73984)
10.06 -- Form of Ancillary Agreement by and among Enron Corp., EOTT Energy Partners, L.P., EOTT
Energy Operating Limited Partnership, EOTT Energy Pipeline Limited Partnership, EOTT
Energy Canada Limited Partnership, and EOTT Energy Corp. (incorporated by reference to
Exhibit 10.10 to Registration Statement, File No. 33-73984)
10.07 -- Agreement to Increase and Extend Distribution Support dated August 8, 1995, amending
the Ancillary Agreement referenced in 10.06 (incorporated by reference to Exhibit 10.07
to Annual Report on Form 10-K for the Year Ended December 31, 1995)
10.08 -- Form of Amended and Restated Agreement of Limited Partnership of EOTT Energy Operating
Limited Partnership (incorporated by reference to Exhibit 10.11 to Registration
Statement, File No. 33-73984)
10.09 -- EOTT Energy Corp. Annual Incentive Plan (incorporated by reference to Exhibit 10.14 to
Registration Statement, File No. 33-73984)
10.10 -- EOTT Energy Corp. 1994 Unit Option Plan and the related Option Agreement (incorporated
by reference to Exhibit 10.15 to Registration Statement, File No. 33-73984)
10.11 -- EOTT Energy Corp. Severance Pay Plan (incorporated by reference to Exhibit 10.16 to
Registration Statement, File No. 33-73984)
10.12 -- Executive Employment Agreement effective March 24, 1994 between EOTT Energy Corp. and
executive officers with employment agreements. (incorporated by reference to Exhibit
10.05 to Registration Statement, File No. 33-73984)
10.13 -- Credit Agreement dated as of June 30, 1995 between EOTT Energy Operating Limited
Partnership, as Borrower, and Enron Corp., as Lender (incorporated by reference to
Exhibit 10.13 to Annual Report on Form 10-K for the Year Ended December 31, 1995)
10.14 -- Credit Agreement dated as of January 3, 1996 between EOTT Energy Operating Limited
Partnership, as Borrower, and Enron Corp., as Lender (incorporated by reference to
Exhibit 10.14 to Annual Report on Form 10-K for the Year Ended December 31, 1995)
</TABLE>
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<PAGE> 116
<TABLE>
<C> <S>
10.15 -- Amendment dated December 19, 1996 to the Credit Agreement
dated as of June 30, 1995 between EOTT Energy Operating
Limited Partnership as Borrower, and Enron Corp., as
Lender (incorporated by reference to Exhibit 10.15 to
Annual Report on Form 10-K for the Year Ended December
31, 1998)
10.16 -- Amendment dated February 25, 1997 to the Credit Agreement
dated as of June 30, 1995 between EOTT Energy Operating
Limited Partnership as Borrower, and Enron Corp., as
Lender (incorporated by reference to Exhibit 10.16 to
Annual Report on Form 10-K for the Year Ended December
31, 1998)
10.17 -- Amendment dated February 25, 1997 to the Credit Agreement
dated as of January 3, 1996 between EOTT Energy Operating
Limited Partnership as Borrower, and Enron Corp., as
Lender (incorporated by reference to Exhibit 10.17 to
Annual Report on Form 10-K for the Year Ended December
31, 1998)
10.18 -- Amendment dated as of February 13, 1997, to the EOTT
Energy Corp. 1994 Unit Option Plan (incorporated by
reference to Exhibit 10.18 to Annual Report on Form 10-K
for the Year Ended December 31, 1998)
10.19 -- EOTT Energy Corp. Long Term Incentive Plan (incorporated
by reference to Exhibit 10.19 to Quarterly Report on Form
10-Q for the Quarter Ended September 30, 1997)
10.20 -- Agreement to Extend Distribution Support dated November
5, 1997, amending the Agreement referenced in 10.07
(incorporated by reference to Exhibit 10.20 to Annual
Report on Form 10-K for the Year Ended December 31, 1998)
10.21 -- Form of Executive Employment Agreement between EOTT
Energy Corp. and Michael D. Burke (incorporated by
reference to Exhibit 10.21 to Annual Report on Form 10-K
for the Year Ended December 31, 1998)
10.22 -- Support Agreement dated September 21, 1998 between EOTT
Energy Partners, L.P., EOTT Energy Operating Limited
Partnership and Enron Corp. (incorporated by reference to
Exhibit 10.22 to Annual Report on Form 10-K for the Year
Ended December 31, 1998)
**10.23 -- Crude Oil Supply and Terminalling Agreement dated as of
December 1, 1998 between Koch Oil Company and EOTT Energy
Operating Limited Partnership (incorporated by reference
to Exhibit 10.23 to Annual Report on Form 10-K for the
Year Ended December 31, 1998)
10.24 -- Amended and Restated Credit Agreement as of December 1,
1998 between EOTT Energy Operating Limited Partnership,
as Borrower, and Enron Corp., as Lender (incorporated by
reference to Exhibit 10.24 to Annual Report on Form 10-K
for the Year Ended December 31, 1998)
10.25 -- Amended and Restated Term Credit Agreement as of December
1, 1998 between EOTT Energy Operating Limited
Partnership, as Borrower, and Enron Corp., as Lender
(incorporated by reference to Exhibit 10.25 to Annual
Report on Form 10-K for the Year Ended December 31, 1998)
10.26 -- Amendment dated March 17, 1999 to the Amended and
Restated Credit Agreement as of December 1, 1998 between
EOTT Energy Operating Limited Partnership, as Borrower,
and Enron Corp., as Lender (incorporated by reference to
Exhibit 10.26 to Annual Report on Form 10-K for the Year
Ended December 31, 1998)
</TABLE>
II-4
<PAGE> 117
<TABLE>
<S> <C>
10.27 -- Amendment dated March 17, 1999 to the Amended and Restated Term Credit Agreement as of
December 1, 1998 between EOTT Energy Operating Limited Partnership, as Borrower, and
Enron Corp., as Lender (incorporated by reference to Exhibit 10.27 to Annual Report on
Form 10-K for the Year Ended December 31, 1998)
**10.28 -- Amendment dated December 1, 1998 to the Crude Oil Supply and Terminalling Agreement
dated as of December 1, 1998 between Koch Oil Company and EOTT Energy Operating Limited
Partnership (incorporated by reference to Exhibit 10.28 to Annual Report on Form 10-K
for the Year Ended December 31, 1998)
10.29 -- Form of Executive Employment Agreement between EOTT Energy Corp. and Dana R. Gibbs
(incorporated by reference to Exhibit 10.29 to Quarterly Report on Form 10-Q for the
Period Ended March 31, 1999)
10.30 -- Amendment dated August 11, 1999 to the Amended and Restated Credit Agreement as of
December 1, 1998 between EOTT Energy Operating Limited Partnership, as Borrower, and
Enron Corp., as Lender (incorporated by reference to Exhibit 10.30 to Quarterly Report
on Form 10-Q for the Period Ended June 30, 1999)
10.31 -- Amendment dated August 11, 1999 to the Amended and Restated Term Credit Agreement as of
December 1, 1998 between EOTT Energy Operating Limited Partnership, as Borrower, and
Enron Corp., as Lender (incorporated by reference to Exhibit 10.31 to Quarterly Report
on Form 10-Q for the Period Ended June 30, 1999)
21.1 -- Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.2 to Annual
Report on Form 10-K for the Year Ended December 31, 1999)
*23.1 -- Consent of Arthur Andersen LLP
*23.2 -- Consent of Vinson & Elkins L.L.P. (included in Exhibits 5.1 and 8.1)
***24.1 -- Power of Attorney
***27.1 -- Financial Data Schedule (incorporated by reference to Exhibit 27 to Quarterly Report on
Form 10-Q for the Period Ended June 30, 2000)
</TABLE>
---------------
* Filed herewith.
** Confidential treatment has been granted with respect to portions of this
exhibit.
*** Previously filed.
(b) Financial Statement Schedule
The following Financial Statement Schedule is included in Part II of this
Registration Statement:
Schedule II -- Valuation And Qualifying Accounts And Reserves, For the
Years ended December 31, 1997, 1998 and 1999.
All other schedules are omitted because the required information is
inapplicable or the information is presented in the Consolidated Financial
Statements or related notes.
II-5
<PAGE> 118
ITEM 17. UNDERTAKINGS.
The registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being
made, a post-effective amendment to this Registration Statement:
(i) To include any prospectus required in Section 10(a)(3) of the
Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events arising after
the effective date of the Registration Statement (or the most recent
post-effective amendment thereof) which, individually or in the
aggregate, represent a fundamental change in the information set forth
in the Registration Statement;
(iii) To include any material information with respect to the "Plan
of Distribution" not previously disclosed in the Registration Statement
or any material change to such information in the Registration
Statement;
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed
to be a new Registration Statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed
to be the initial bona fide offering thereof;
(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the
termination of the offering; and
(4) For purpose of determining any liability under the Securities Act
of 1933, the information omitted from the form of prospectus filed as part
of this Registration Statement in reliance upon Rule 430A and contained in
the form of prospectus filed by the registrant pursuant to Rule 424(b)(1)
or (4) or 497(h) under the Securities Act shall be deemed to be part of
this Registration Statement as of the time it was declared effective.
(5) For the purpose of determining any liability under the Securities
Act of 1933, each post-effective amendment that contains a form of
prospectus shall be deemed to be a new registration statement relating to
the securities offered therein, and the offering of such securities at that
time shall be deemed to be the initial bona fide offering thereof.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
registrant pursuant to the provisions described under Item 15 above or
otherwise, the registrant has been advised that in the opinion of the SEC such
indemnification is against public policy as expressed in the Act and is,
therefore, unenforceable. In the event that a claim for indemnification against
such liabilities (other than the payment by the registrant of expenses incurred
or paid by a director, officer or controlling person of the registrant in the
successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Act and will be governed by the final adjudication of
such issue.
II-6
<PAGE> 119
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in Houston, Texas, on the
27th day of September, 2000.
EOTT ENERGY PARTNERS, L.P.
(A Delaware Limited Partnership)
By: EOTT Energy Corp.
Its: General Partner
By: /s/ Dana R. Gibbs
------------------------------------
Name: Dana R. Gibbs
------------------------------------
Title: President and Chief
Operating Officer
------------------------------------
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Dana R. Gibbs and Lori L. Maddox, or either of
them, his true and lawful attorney-in-fact and agent, with full power of
substitution, for him and in his name, place and stead, in any and all
capacities, to sign this registration statement and any and all amendments
(including post-effective amendments) to this registration statement, and to
file the same with all exhibits thereto, and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto said
attorney-in-fact and agent full power and authority to do and perform each and
every act and thing requisite and ratifying and confirming all that said
attorney-in-fact and agent or his substitute or substitutes may lawfully do or
cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement or amendment has been signed by the following persons in
the capacities indicated on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ STANLEY C. HORTON* Chairman of the Board and Chief September 27, 2000
----------------------------------------------------- Executive Officer
Stanley C. Horton
/s/ DANA R. GIBBS President, Chief Operating Officer September 27, 2000
----------------------------------------------------- and Director
Dana R. Gibbs
/s/ LAWRENCE CLAYTON, JR. Senior Vice President and Chief September 27, 2000
----------------------------------------------------- Financial Officer)
Lawrence Clayton, Jr.
/s/ LORI L. MADDOX Controller (Chief Accounting September 27, 2000
----------------------------------------------------- Officer)
Lori L. Maddox
/s/ DEE S. OSBORNE* Director September 27, 2000
-----------------------------------------------------
Dee S. Osborne
/s/ DANIEL P. WHITTY* Director September 27, 2000
-----------------------------------------------------
Daniel P. Whitty
/s/ JOHN H. DUNCAN* Director September 27, 2000
-----------------------------------------------------
John H. Duncan
</TABLE>
II-7
<PAGE> 120
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ EDWARD O. GAYLORD* Director September 27, 2000
-----------------------------------------------------
Edward O. Gaylord
/s/ KENNETH L. LAY* Director September 27, 2000
-----------------------------------------------------
Kenneth L. Lay
*By: /s/ LORI L. MADDOX
-------------------------------------------------
Lori L. Maddox
(Attorney-in-fact for
the persons indicated)
</TABLE>
II-8
<PAGE> 121
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
3.1 -- Form of Partnership Agreement of EOTT Energy Partners,
L.P. (incorporated by reference to Exhibit 3.1 to
Registration Statement, File No. 33-73984)
3.2 -- Amendment No. 1 dated as of August 8, 1995, to the
Amended and Restated Agreement of Limited Partnership of
EOTT Energy Partners, L.P. (incorporated by reference to
Exhibit 3.2 to Annual Report on Form 10-K for the Year
Ended December 31, 1995)
3.3 -- Amendment No. 2 dated as of July 16, 1996, to the Amended
and Restated Agreement of Limited Partnership of EOTT
Energy Partners, L.P. (incorporated by reference to
Exhibit 3.3 to Quarterly Report on Form 10-Q for the
Quarter Ended June 30, 1996)
3.4 -- Amendment No. 3 dated as of February 13, 1997, to the
Amended and Restated Agreement of Limited Partnership of
EOTT Energy Partners, L.P. (incorporated by reference to
Exhibit 3.4 to Annual Report on Form 10-K for the Year
Ended December 31, 1998)
3.5 -- Amendment No. 4 dated as of November 30, 1998, to the
Amended and Restated Agreement of Limited Partnership of
EOTT Energy Partners, L.P. (incorporated by reference to
Exhibit 3.5 to Annual Report on Form 10-K for the Year
Ended December 31, 1998)
3.6 -- Amendment No. 5 dated as of December 7, 1998, to the
Amended and Restated Agreement of Limited Partnership of
EOTT Energy Partners, L.P. (incorporated by reference to
Exhibit 3.6 to Annual Report on Form 10-K for the Year
Ended December 31, 1998)
3.7 -- Amendment No. 6 dated as of September 16, 1999 to the
Amended and Restated Agreement of Limited Partnership of
EOTT Energy Partners, L.P. (incorporated by reference to
Exhibit 3.1 to Current Report on Form 8-K dated September
29, 1999)
4.1 -- Form of Indenture for Senior Debt Securities and
Subordinated Debt Securities (incorporated by reference
to Exhibit 4.1 to Registration Statement, File No.
333-82269)
*5.1 -- Opinion of Vinson & Elkins L.L.P. as to legality of
securities
*8.1 -- Tax opinion of Vinson & Elkins L.L.P.
10.04 -- Form of Corporate Services Agreement between Enron Corp.
and EOTT Energy Corp. (incorporated by reference to
Exhibit 10.08 to Registration Statement, File No.
33-73984)
10.05 -- Form of Contribution and Closing Agreement between EOTT
Energy Corp. and EOTT Energy Partners, L.P. (incorporated
by reference to Exhibit 10.09 to Registration Statement,
File No. 33-73984)
10.06 -- Form of Ancillary Agreement by and among Enron Corp.,
EOTT Energy Partners, L.P., EOTT Energy Operating Limited
Partnership, EOTT Energy Pipeline Limited Partnership,
EOTT Energy Canada Limited Partnership, and EOTT Energy
Corp. (incorporated by reference to Exhibit 10.10 to
Registration Statement, File No. 33-73984)
10.07 -- Agreement to Increase and Extend Distribution Support
dated August 8, 1995, amending the Ancillary Agreement
referenced in 10.06 (incorporated by reference to Exhibit
10.07 to Annual Report on Form 10-K for the Year Ended
December 31, 1995)
</TABLE>
<PAGE> 122
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
10.08 -- Form of Amended and Restated Agreement of Limited
Partnership of EOTT Energy Operating Limited Partnership
(incorporated by reference to Exhibit 10.11 to
Registration Statement, File No. 33-73984)
10.09 -- EOTT Energy Corp. Annual Incentive Plan (incorporated by
reference to Exhibit 10.14 to Registration Statement,
File No. 33-73984)
10.10 -- EOTT Energy Corp. 1994 Unit Option Plan and the related
Option Agreement (incorporated by reference to Exhibit
10.15 to Registration Statement, File No. 33-73984)
10.11 -- EOTT Energy Corp. Severance Pay Plan (incorporated by
reference to Exhibit 10.16 to Registration Statement,
File No. 33-73984)
10.12 -- Executive Employment Agreement effective March 24, 1994
between EOTT Energy Corp. and executive officers with
employment agreements. (incorporated by reference to
Exhibit 10.05 to Registration Statement, File No.
33-73984)
10.13 -- Credit Agreement dated as of June 30, 1995 between EOTT
Energy Operating Limited Partnership, as Borrower, and
Enron Corp., as Lender (incorporated by reference to
Exhibit 10.13 to Annual Report on Form 10-K for the Year
Ended December 31, 1995)
10.14 -- Credit Agreement dated as of January 3, 1996 between EOTT
Energy Operating Limited Partnership, as Borrower, and
Enron Corp., as Lender (incorporated by reference to
Exhibit 10.14 to Annual Report on Form 10-K for the Year
Ended December 31, 1995)
10.15 -- Amendment dated December 19, 1996 to the Credit Agreement
dated as of June 30, 1995 between EOTT Energy Operating
Limited Partnership as Borrower, and Enron Corp., as
Lender (incorporated by reference to Exhibit 10.15 to
Annual Report on Form 10-K for the Year Ended December
31, 1998)
10.16 -- Amendment dated February 25, 1997 to the Credit Agreement
dated as of June 30, 1995 between EOTT Energy Operating
Limited Partnership as Borrower, and Enron Corp., as
Lender (incorporated by reference to Exhibit 10.16 to
Annual Report on Form 10-K for the Year Ended December
31, 1998)
10.17 -- Amendment dated February 25, 1997 to the Credit Agreement
dated as of January 3, 1996 between EOTT Energy Operating
Limited Partnership as Borrower, and Enron Corp., as
Lender (incorporated by reference to Exhibit 10.17 to
Annual Report on Form 10-K for the Year Ended December
31, 1998)
10.18 -- Amendment dated as of February 13, 1997, to the EOTT
Energy Corp. 1994 Unit Option Plan (incorporated by
reference to Exhibit 10.18 to Annual Report on Form 10-K
for the Year Ended December 31, 1998)
10.19 -- EOTT Energy Corp. Long Term Incentive Plan (incorporated
by reference to Exhibit 10.19 to Quarterly Report on Form
10-Q for the Quarter Ended September 30, 1997)
10.20 -- Agreement to Extend Distribution Support dated November
5, 1997, amending the Agreement referenced in 10.07
(incorporated by reference to Exhibit 10.20 to Annual
Report on Form 10-K for the Year Ended December 31, 1998)
10.21 -- Form of Executive Employment Agreement between EOTT
Energy Corp. and Michael D. Burke (incorporated by
reference to Exhibit 10.21 to Annual Report on Form 10-K
for the Year Ended December 31, 1998)
10.22 -- Support Agreement dated September 21, 1998 between EOTT
Energy Partners, L.P., EOTT Energy Operating Limited
Partnership and Enron Corp. (incorporated by reference to
Exhibit 10.22 to Annual Report on Form 10-K for the Year
Ended December 31, 1998)
</TABLE>
<PAGE> 123
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
**10.23 -- Crude Oil Supply and Terminalling Agreement dated as of
December 1, 1998 between Koch Oil Company and EOTT Energy
Operating Limited Partnership (incorporated by reference
to Exhibit 10.23 to Annual Report on Form 10-K for the
Year Ended December 31, 1998)
10.24 -- Amended and Restated Credit Agreement as of December 1,
1998 between EOTT Energy Operating Limited Partnership,
as Borrower, and Enron Corp., as Lender (incorporated by
reference to Exhibit 10.24 to Annual Report on Form 10-K
for the Year Ended December 31, 1998)
10.25 -- Amended and Restated Term Credit Agreement as of December
1, 1998 between EOTT Energy Operating Limited
Partnership, as Borrower, and Enron Corp., as Lender
(incorporated by reference to Exhibit 10.25 to Annual
Report on Form 10-K for the Year Ended December 31, 1998)
10.26 -- Amendment dated March 17, 1999 to the Amended and
Restated Credit Agreement as of December 1, 1998 between
EOTT Energy Operating Limited Partnership, as Borrower,
and Enron Corp., as Lender (incorporated by reference to
Exhibit 10.26 to Annual Report on Form 10-K for the Year
Ended December 31, 1998)
10.27 -- Amendment dated March 17, 1999 to the Amended and
Restated Term Credit Agreement as of December 1, 1998
between EOTT Energy Operating Limited Partnership, as
Borrower, and Enron Corp., as Lender (incorporated by
reference to Exhibit 10.27 to Annual Report on Form 10-K
for the Year Ended December 31, 1998)
**10.28 -- Amendment dated December 1, 1998 to the Crude Oil Supply
and Terminalling Agreement dated as of December 1, 1998
between Koch Oil Company and EOTT Energy Operating
Limited Partnership (incorporated by reference to Exhibit
10.28 to Annual Report on Form 10-K for the Year Ended
December 31, 1998)
10.29 -- Form of Executive Employment Agreement between EOTT
Energy Corp. and Dana R. Gibbs (incorporated by reference
to Exhibit 10.29 to Quarterly Report on Form 10-Q for the
Period Ended March 31, 1999)
10.30 -- Amendment dated August 11, 1999 to the Amended and
Restated Credit Agreement as of December 1, 1998 between
EOTT Energy Operating Limited Partnership, as Borrower,
and Enron Corp., as Lender (incorporated by reference to
Exhibit 10.30 to Quarterly Report on Form 10-Q for the
Period Ended June 30, 1999)
10.31 -- Amendment dated August 11, 1999 to the Amended and
Restated Term Credit Agreement as of December 1, 1998
between EOTT Energy Operating Limited Partnership, as
Borrower, and Enron Corp., as Lender (incorporated by
reference to Exhibit 10.31 to Quarterly Report on Form
10-Q for the Period Ended June 30, 1999)
21.1 -- Subsidiaries of the Registrant (incorporated by reference
to Exhibit 21.2 to Annual Report on Form 10-K for the
Year Ended December 31, 1999)
*23.1 -- Consent of Arthur Andersen LLP
*23.2 -- Consent of Vinson & Elkins L.L.P. (included in Exhibits
5.1 and 8.1)
***24.1 -- Power of Attorney
***27.1 -- Financial Data Schedule (incorporated by reference to
Exhibit 27 to Quarterly Report on Form 10-Q for the
Period Ended June 30, 2000)
</TABLE>
---------------
* Filed herewith.
** Confidential treatment has been granted with respect to portions of this
exhibit.
*** Previously filed.
