AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 8, 2004
REGISTRATION NO. 333-107324
REGISTRATION NO. 333-107324-01
REGISTRATION NO. 333-107324-02
REGISTRATION NO. 333-107324-03
REGISTRATION NO. 333-107324-04
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------
AMENDMENT NO. 6
TO
FORM S-3
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
---------------------
<Table>
HERITAGE PROPANE PARTNERS, L.P. DELAWARE 73-1493906
HERITAGE OPERATING, L.P. DELAWARE 73-1495293
HERITAGE SERVICE CORP. DELAWARE 73-1495294
HERITAGE-BI STATE, L.L.C. DELAWARE 73-1496351
HERITAGE ENERGY RESOURCES, L.L.C. OKLAHOMA 73-1588029
(Exact name of each registrant (State or other jurisdiction of (I.R.S. Employer
as specified in its charter) incorporation or organization) Identification Number)
</Table>
---------------------
8801 SOUTH YALE AVENUE, SUITE 310
TULSA, OKLAHOMA 74137
(918) 492-7272
(Address, including zip code, and telephone number, including area code, of each
registrant's principal executive offices)
---------------------
MICHAEL L. GREENWOOD
VICE PRESIDENT AND CHIEF FINANCIAL OFFICER
HERITAGE PROPANE PARTNERS, L.P.
8801 SOUTH YALE AVENUE, SUITE 310
TULSA, OKLAHOMA 74137
(918) 492-7272
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
---------------------
COPIES TO:
<Table>
THOMAS P. MASON ROBERT A. BURK
DOUGLAS E. MCWILLIAMS DOERNER, SAUNDERS, DANIEL & ANDERSON, L.L.P.
VINSON & ELKINS L.L.P. 320 SOUTH BOSTON, SUITE 500
2300 FIRST CITY TOWER TULSA, OKLAHOMA 74103-3725
1001 FANNIN STREET (918) 582-1211
HOUSTON, TEXAS 77002
(713) 758-2222
</Table>
---------------------
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: From time
to time after this registration statement becomes effective.
If the only securities being registered on this form are being offered
pursuant to dividend or interest reinvestment plans, please check the following
box. [ ]
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 delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
EACH 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.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
THE INFORMATION IN THIS PROSPECTUS SUPPLEMENT IS NOT COMPLETE AND MAY BE
CHANGED. THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS ARE NOT AN
OFFER TO SELL THESE SECURITIES AND WE ARE NOT SOLICITING OFFERS TO BUY THESE
SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED.
SUBJECT TO COMPLETION, DATED JANUARY 8, 2004
PROSPECTUS SUPPLEMENT
(TO PROSPECTUS DATED , 2004)
(HERITAGE PROPANE LOGO)
7,000,000 COMMON UNITS
REPRESENTING LIMITED PARTNER INTERESTS
We are offering 7,000,000 common units representing limited partner
interests. Our common units are traded on the New York Stock Exchange under the
symbol "HPG." On January 6, 2004, the last reported sales price of our common
units on the NYSE was $39.70 per common unit.
INVESTING IN THE COMMON UNITS INVOLVES RISK. SEE "RISK FACTORS" BEGINNING
ON PAGE S-14 OF THIS PROSPECTUS SUPPLEMENT AND ON PAGE 2 OF THE ACCOMPANYING
PROSPECTUS.
<Table>
<Caption>
PER COMMON UNIT TOTAL
--------------- --------
Public offering price....................................... $ $
Underwriting discount....................................... $ $
Proceeds, before expenses, to Heritage Propane Partners,
L.P....................................................... $ $
</Table>
We have granted the underwriters a 30-day option to purchase up to
1,050,000 common units on the same terms and conditions as set forth above to
cover over-allotments of common units.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved these securities or determined if this
prospectus supplement or the accompanying prospectus is truthful or complete.
Any representation to the contrary is a criminal offense.
The underwriters expect to deliver the common units on or about ,
2004.
------------------
Joint Book-Running Managers
CITIGROUP LEHMAN BROTHERS
------------------
UBS INVESTMENT BANK
A.G. EDWARDS & SONS, INC.
WACHOVIA SECURITIES
CREDIT SUISSE FIRST BOSTON
RBC CAPITAL MARKETS
RAYMOND JAMES
STEPHENS INC.
, 2004
[MAP OF PROPANE OPERATIONS]
[MAP OF MIDSTREAM OPERATIONS]
This document is in two parts. The first part is this prospectus
supplement, which describes the terms of this offering of common units. The
second part is the accompanying prospectus, which gives more general
information, some of which may not apply to the common units.
TABLE OF CONTENTS
<Table>
PROSPECTUS SUPPLEMENT
Summary..................................................... S-1
Risk Factors................................................ S-14
Use of Proceeds............................................. S-23
Price Range of Common Units and Distributions............... S-24
Capitalization.............................................. S-25
Heritage Propane Partners Selected Historical Financial and
Operating Data............................................ S-26
Energy Transfer Selected Historical Financial Data.......... S-29
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. S-31
Business.................................................... S-56
Management.................................................. S-81
Related Party Transactions.................................. S-86
Description of Units........................................ S-88
Cash Distribution Policy.................................... S-91
Tax Considerations.......................................... S-93
Underwriting................................................ S-94
Validity of the Common Units................................ S-97
Experts..................................................... S-97
Information Regarding Forward Looking Statements............ S-99
Index to Financial Statements............................... F-1
PROSPECTUS
About This Prospectus....................................... 1
Who We Are.................................................. 1
The Subsidiary Guarantors................................... 1
Risk Factors................................................ 2
Forward-Looking Statements.................................. 14
Use of Proceeds............................................. 15
Ratio of Earnings to Fixed Charges.......................... 15
Description of the Common Units............................. 17
Cash Distribution Policy.................................... 24
Description of the Debt Securities.......................... 29
Selling Unitholders......................................... 39
Material Tax Considerations................................. 40
Investment in Us by Employee Benefit Plans.................. 54
Plan of Distribution........................................ 55
Legal Matters............................................... 56
Experts..................................................... 56
Where You Can Find More Information......................... 57
</Table>
i
SUMMARY
This summary highlights information contained elsewhere in this prospectus
supplement. You should read the entire prospectus supplement, the accompanying
prospectus, the documents incorporated by reference and the other documents to
which we refer for a more complete understanding of this offering. You should
read "Risk Factors" beginning on page S-14 of this prospectus supplement and
page 2 of the accompanying prospectus for more information about important
factors that you should consider before buying common units in this offering.
The information presented in this prospectus supplement assumes that the
underwriters do not exercise their over-allotment option. Throughout this
prospectus supplement and the accompanying prospectus, we refer to ourselves,
Heritage Propane Partners, L.P., as "we," "us," "our" or "Heritage Propane
Partners." We refer to La Grange Energy, L.P. as "La Grange Energy" and we refer
to La Grange Acquisition, L.P., whose operations are conducted under the name
Energy Transfer Company, as "Energy Transfer."
You should only rely on the information contained or incorporated by
reference in this prospectus supplement or the accompanying prospectus. We have
not authorized anyone to provide you with different information. We are not
making an offer of these securities in any state where the offer is not
permitted. You should not assume that the information contained in this
prospectus supplement or the accompanying prospectus is accurate as of any date
other than the date on the front of those documents.
HERITAGE PROPANE PARTNERS, L.P.
We are one of the largest retail propane marketers in the United States,
serving more than 650,000 customers from over 300 customer service locations in
31 states. Our operations extend from coast to coast, with concentrations in the
western, upper midwestern, northeastern and southeastern regions of the United
States. We are also a wholesale propane supplier in the southwestern and
southeastern United States and in Canada, the latter through participation in
M-P Energy Partnership. M-P Energy Partnership is a Canadian partnership in
which we own a 60% interest, engaged in wholesale distribution and in supplying
our northern U.S. locations. We are a publicly traded Delaware limited
partnership formed in conjunction with our initial public offering in June of
1996. Our business has grown primarily through acquisitions of retail propane
operations and, to a lesser extent, through internal growth. Since our inception
through August 31, 2003, we have completed 97 acquisitions for an aggregate
purchase price of approximately $675 million. Volumes of propane sold to retail
customers have increased steadily from 63.2 million gallons for the fiscal year
ended August 31, 1992 to 375.9 million gallons for the fiscal year ended August
31, 2003.
RECENT EVENTS
The Energy Transfer Transaction. On November 7, 2003, we publicly
announced the signing of definitive agreements to combine our operations with
those of La Grange Energy, L.P., which is engaged in the midstream natural gas
business. La Grange Energy conducts its midstream operations through its
subsidiary, La Grange Acquisition, L.P., under the name Energy Transfer Company.
Energy Transfer's assets are primarily located in major natural gas producing
regions of Texas and Oklahoma. The Energy Transfer transaction will create a
combined entity with substantially greater scale and scope of operations. We
believe our larger size and our entry into the midstream natural gas business
will provide us with substantial internal and external growth opportunities and
reduce the seasonality associated with our propane operations.
The value of this transaction is approximately $1.0 billion based on the
average market price of our common units for the three trading days prior to and
the three trading days after the time we signed the
S-1
agreements related to the transaction. At the closing of this transaction, which
will occur simultaneously with the closing of this offering:
- La Grange Energy will contribute its interest in Energy Transfer and
certain related assets to us in exchange for the following consideration:
-- An amount in cash equal to $300 million, less the amount of Energy
Transfer debt in excess of $151.5 million, less accounts payable and
other specified liabilities of Energy Transfer, plus an agreed upon
amount for the reimbursement of capital expenditures paid by La Grange
Energy relating to the Energy Transfer business prior to closing;
-- the retirement at closing of Energy Transfer's then outstanding debt;
-- the assumption at closing of Energy Transfer's then existing accounts
payable and other specified liabilities;
-- 12,140,719 of our common units and class D units, representing a value
of approximately $433.9 million; and
-- 3,742,515 special units, representing a value of approximately $133.8
million.
For a description of our common units, class D units and special units,
please read "Description of Units" in this prospectus supplement.
- La Grange Energy will purchase all of the partnership interests of U.S.
Propane, L.P., our general partner, and all of the member interests of
U.S. Propane, L.L.C., the general partner of U.S. Propane, L.P., from the
current owners for $30 million in cash. La Grange Energy is owned by
Natural Gas Partners VI, L.P., a private equity fund, Ray C. Davis, Kelcy
L. Warren and a group of institutional investors.
- We will acquire from an affiliate of the current owners of our general
partner all of the stock of Heritage Holdings, Inc., which owns
approximately 4.4 million of our common units, for $50 million in cash
and a $50 million two-year promissory note secured by a pledge of the
units held by Heritage Holdings, and we will inherit approximately $104.7
million in liabilities of Heritage Holdings. Substantially all of these
liabilities are deferred tax liabilities arising from differences in the
book and tax basis of Heritage Holdings' assets. The promissory note
bears interest at a rate of 7% per annum.
The amounts necessary to pay the cash portion of the purchase price, retire
Energy Transfer's debt, satisfy Energy Transfer's accounts payable and other
specified liabilities and fund the expenses associated with this offering, a new
Energy Transfer credit facility and the Energy Transfer transaction will be
raised from the proceeds of this offering and borrowings under the new Energy
Transfer credit facility. The following table sets forth an estimated breakdown
of the sources and uses of the consideration to be paid in this transaction:
<Table>
<Caption>
AMOUNTS
(IN MILLIONS)
-------------
SOURCES OF CONSIDERATION:
Gross proceeds from this common unit offering............... $ 277.9
Units to be issued to La Grange Energy(a)................... 567.7
Note payable to acquire Heritage Holdings................... 50.0
Borrowings under new Energy Transfer credit facility........ 275.0
General partner cash contributions to maintain its 2%
general partner interest.................................. 14.0
--------
$1,184.6
========
</Table>
S-2
<Table>
<Caption>
AMOUNTS
(IN MILLIONS)
-------------
USES OF CONSIDERATION:
Cash payable to La Grange Energy(b)(c)...................... $ 86.8
Estimated reimbursement of capital expenditures............. 5.0
Units to be issued to La Grange Energy(a)................... 567.7
Energy Transfer debt, including accrued interest, to be
retired(b)(c)............................................. 227.0
Energy Transfer accounts payable and other specified
liabilities to be assumed(b)(c)........................... 137.2
--------
Energy Transfer transaction consideration(a).............. 1,023.7
--------
Cash payable to acquire Heritage Holdings................... 50.0
Note payable to acquire Heritage Holdings................... 50.0
Transaction costs, including underwriting discount.......... 23.8
Cash on the balance sheet................................... 37.1
--------
$1,184.6
========
</Table>
- ---------------
(a) For purposes of this table, the value attributable to the units issued to
La Grange Energy is based on the average market price for our common units
for the three trading days prior to and the three trading days after
execution of the agreements relating to the Energy Transfer transaction,
which was $35.74 per common unit. At the time these agreements were entered
into, the parties determined the value of the units based on the prior 45
day average market price, which was $33.40 per common unit, resulting in a
value of $987 million at such time for the Energy Transfer transaction.
(b) Determined as of August 31, 2003.
(c) The cash payable to La Grange Energy, the Energy Transfer debt to be
retired and the Energy Transfer accounts payable and other specified
liabilities to be assumed will equal $451.0 million in aggregate.
Heritage Propane Financial Results. Our net income for the fiscal year
ended August 31, 2003 was a record $31.1 million, or $1.79 per limited partner
unit, as compared to net income of $4.9 million, or $0.25 per limited partner
unit, for fiscal 2002 and net income of $19.7 million, or $1.43 per limited
partner unit, for fiscal 2001. Our earnings before interest, taxes, depreciation
and amortization, as adjusted, which we refer to as EBITDA, as adjusted, for
fiscal 2003 also reached a record level of $111.0 million, as compared to our
EBITDA, as adjusted, of $81.5 million for fiscal 2002 and our EBITDA, as
adjusted, of $97.4 million for fiscal 2001. These increases were due to more
favorable weather conditions during fiscal 2003 in our areas of operations that
led to higher volumes and gross margins and, to a lesser extent, the benefit of
volumes added through acquisitions. For a discussion of EBITDA, as adjusted, and
a reconciliation of EBITDA, as adjusted, to net income, please read footnote (c)
to "Heritage Propane Partners Selected Historical Financial and Operating Data"
beginning on page S-26 of this prospectus supplement.
Distribution Increase. On October 15, 2003, we paid a quarterly cash
distribution of $0.65 per common unit (an annualized rate of $2.60 per unit) on
our outstanding common units for the fourth quarter of fiscal year 2003. The
$0.65 per common unit quarterly distribution represents an increase of $0.0125
per common unit (an annualized increase of $0.05 per unit) over the distribution
paid for the third quarter of fiscal 2003 and the ninth quarterly distribution
increase since our inception. We have also declared a cash distribution of $0.65
per common unit on our outstanding units for the first quarter of fiscal year
2004, which distribution will be payable on January 14, 2004 to holders of
record as of December 30, 2003.
Recent Propane Acquisitions. In October 2003, we announced the completion
of the acquisition of the assets of Big Sky Petroleum, Archibald Propane,
Moore-L.P. Gas, Inc. and Sunbeam L.P., Gas, Inc. The companies acquired serve an
aggregate of approximately 6,900 customers in Montana, northern Utah,
S-3
southern Idaho and northern Georgia. In December 2003, we announced the
completion of the acquisition of the 50% interest in Bi-State Propane that we
did not own. We had been a partner in Bi-State since 1995 and we now own 100% of
the company, which has operations in Nevada and eastern California. In January
2004, we announced the completion of the acquisition of the assets of Metro Lift
Propane. This acquisition adds 10 new district locations to us and approximately
10 million gallons of propane sold annually. The aggregate purchase price for
these acquisitions was approximately $21.6 million in cash and 505,826 common
units, subject to some future adjustments.
ENERGY TRANSFER
Energy Transfer is a growth-oriented midstream natural gas company with
operations primarily located in major natural gas producing regions of Texas and
Oklahoma. Energy Transfer's primary assets consist of two large gathering and
processing systems in the Gulf Coast area of Texas and western Oklahoma and the
Oasis Pipeline, an intrastate natural gas pipeline that runs from the Permian
Basin in west Texas to natural gas supply and market areas in southeast Texas.
Energy Transfer's operations consist of the following:
- the gathering of natural gas from over 1,400 producing wells;
- the compression of natural gas to facilitate its flow from the wells
through Energy Transfer's gathering systems;
- the treating of natural gas to remove impurities such as carbon dioxide
and hydrogen sulfide to ensure that the natural gas meets pipeline
quality specifications;
- the processing of natural gas to extract natural gas liquids, or NGLs;
the sale of the pipeline quality natural gas, or "residue gas," remaining
after it is processed; and the sale of the NGLs to third parties at
fractionation facilities where the NGLs are separated into their
individual components, including ethane, propane, mixed butanes and
natural gasoline;
- the transportation of natural gas on its Oasis Pipeline to industrial
end-users, independent power plants, utilities and other pipelines; and
- the purchase for resale of natural gas from producers connected to its
systems and from other third parties.
Energy Transfer owns or has an interest in over 3,850 miles of natural gas
pipeline systems, three natural gas processing plants connected to its gathering
systems with a total processing capacity of approximately 400 MMcf/d and seven
natural gas treating facilities with a total treating capacity of approximately
425 MMcf/d.
Energy Transfer divides its operations into two business segments, the
Midstream segment, which consists of its natural gas gathering, compression,
treating, processing and marketing operations, and the Transportation segment,
which consists of the Oasis Pipeline.
The Midstream segment consists of the following:
- the Southeast Texas System, a 2,500-mile integrated system located in the
Gulf Coast area of Texas, covering 13 counties between Austin and
Houston. The system has a throughput capacity of approximately 720
MMcf/d, and average throughput for the 11 months ended August 31, 2003
was approximately 260 MMcf/d. The system includes the La Grange
processing plant, which has processing capacity of approximately 240
MMcf/d, and five treating facilities with an aggregate capacity of
approximately 250 MMcf/d. Average throughput for the processing plant and
the treating facilities was approximately 95 MMcf/d and 80 MMcf/d,
respectively, for the 11 months ended August 31, 2003. This system is
connected to the Katy Hub, a major natural gas market center near
Houston, through Energy Transfer's 55-mile Katy Pipeline and is also
connected to the Oasis Pipeline, as well as two power plants.
S-4
- the Elk City System, a 315-mile gathering system located in western
Oklahoma. The system has a throughput capacity of approximately 410
MMcf/d, and average throughput for the 11 months ended August 31, 2003
was approximately 170 MMcf/d. The system includes the Elk City processing
plant, which has a processing capacity of approximately 130 MMcf/d, and
one treating facility with a capacity of approximately 145 MMcf/d.
Average throughput for the processing plant was approximately 95 MMcf/d
for the 11 months ended August 31, 2003. The Elk City System is
connected, either directly or indirectly, to six major interstate and
intrastate natural gas pipelines providing access to natural gas markets
throughout the United States.
- an interest in various midstream assets located in Texas and Louisiana,
including the Vantex System, the Rusk County Gathering System, the
Whiskey Bay System and the Chalkley Transmission System. On a combined
basis, these assets have a throughput capacity of approximately 265
MMcf/d, and average throughput for these assets was approximately 50
MMcf/d for the 11 months ended August 31, 2003.
- marketing operations through Energy Transfer's producer services
business, in which Energy Transfer markets the natural gas that flows
through its assets and attracts other customers by marketing volumes of
natural gas that do not move through its assets.
The Transportation segment consists of the Oasis Pipeline, a 583-mile
natural gas pipeline that directly connects the Waha Hub, a major natural gas
market center located in the Permian Basin of west Texas, to the Katy Hub. The
Oasis Pipeline is primarily a 36-inch diameter natural gas pipeline. It has bi-
directional capability with approximately 1 Bcf/d of throughput capacity moving
west-to-east and greater than 750 MMcf/d of throughput capacity moving
east-to-west. Average throughput on the Oasis Pipeline was approximately 830
MMcf/d for the 11 months ended August 31, 2003. The Oasis Pipeline has many
interconnections with other pipelines, power plants, processing facilities,
municipalities and producers.
Energy Transfer has announced that it intends to construct a 78-mile
pipeline, which we refer to as the Bossier Pipeline, that will connect natural
gas supplies in east Texas to Energy Transfer's Katy Pipeline in Grimes County.
The Bossier Pipeline, which is part of our strategy to expand our operations in
east Texas, will enable producers to transport natural gas to the Katy Hub from
east Texas. Pipeline capacity is constrained in this area due to increasing
natural gas production from the ongoing drilling activity in the Barnett Shale
in north central Texas and the Bossier Sand and other formations. Energy
Transfer has secured contracts with three separate companies to transport
natural gas on this pipeline, including a nine-year fee-based contract with XTO
Energy, Inc. pursuant to which XTO Energy has committed approximately 200
MMcf/d. We expect the Bossier Pipeline to become commercially operational by
mid-2004.
BUSINESS STRATEGIES
Upon completion of the Energy Transfer transaction, we intend to operate as
a diversified, growth-oriented master limited partnership with a focus on
increasing the amount of cash available for distribution on each unit. We
believe that by pursuing independent operating and growth strategies for our
midstream and propane businesses, we will be best positioned to achieve our
objectives. We believe that our increased size as a result of the Energy
Transfer transaction will allow us to participate in growth opportunities not
currently available to us.
We expect that midstream acquisitions will be the primary focus of our
strategy going forward, however, we will also continue to pursue complementary
propane acquisitions. We anticipate that the Energy Transfer business will
provide internal growth projects of greater scale compared to those available in
our propane business. We believe the combined experience of the operational and
senior management of Heritage Propane Partners and Energy Transfer, both of
which will continue to operate their respective businesses, will benefit us in
achieving our growth strategy.
S-5
MIDSTREAM BUSINESS STRATEGIES
- Growth through acquisitions. We intend to make strategic acquisitions of
midstream assets in Energy Transfer's current areas of operation that
offer the opportunity for operational efficiencies and the potential for
increased utilization and expansion of its existing and acquired assets.
We will also pursue midstream asset acquisition opportunities in other
regions of the U.S. with significant natural gas reserves and high levels
of drilling activity or with growing demand for natural gas.
- Enhance profitability of existing assets. We intend to increase the
profitability of Energy Transfer's existing asset base by adding new
volumes of natural gas, undertaking additional initiatives to enhance
utilization and reducing costs by improving operations.
- Engage in construction and expansion opportunities. We intend to
leverage Energy Transfer's existing infrastructure and customer
relationships by constructing and expanding systems to meet new or
increased demand for midstream services.
- Increase cash flow from fee-based businesses. We intend to seek to
increase the percentage of Energy Transfer's midstream business conducted
with third parties under fee-based arrangements in order to reduce
exposure to changes in the prices of natural gas and NGLs.
PROPANE BUSINESS STRATEGIES
- Growth through complementary acquisitions. We believe that the
fragmented nature of the propane industry will continue to provide
opportunities for growth through the acquisition of propane businesses
that complement our existing asset base. In addition to focusing on
propane acquisition candidates in our existing areas of operations, we
will also consider core acquisitions in other higher-than-average
population growth areas in which we have no presence in order to further
reduce the impact adverse weather patterns and economic downturns in any
one region may have on our overall operations.
- Maintain low-cost, decentralized operations. We focus on controlling
costs, and we attribute our low overhead costs primarily to our
decentralized structure.
- Pursue internal growth opportunities. We have aggressively focused on
high return internal growth opportunities at our existing customer
service locations.
Please read "Business -- Overview -- Business Strategies" on page S-57 of
this prospectus supplement for a more detailed discussion of our business
strategies.
S-6
PARTNERSHIP STRUCTURE
Our operations are conducted through, and our operating assets are owned
by, our subsidiaries. Upon consummation of the offering of our common units and
the Energy Transfer transaction:
- Energy Transfer will be a wholly owned subsidiary of Heritage Propane
Partners, L.P.
- There will be approximately 32,937,950 common and class D units
outstanding. The class D units are a new class of our units that will be
issued in the Energy Transfer transaction.
- La Grange Energy will own 12,140,719 common and class D units. La Grange
will be issued a number of common units equal to 19.99% of the number of
common units outstanding immediately prior to the Energy Transfer
transaction (excluding the 4,426,916 common units held by Heritage
Holdings) after giving effect to this offering. The remainder of the
units will consist of class D units. The class D units will be similar to
the common units and will be entitled to the same cash distributions as
common units, provided that the class D units' right to share in
quarterly cash distributions and distributions on liquidation will be
subordinated to our common units' right to share in quarterly cash
distributions and distributions on liquidation. The class D units will be
converted into an equal number of common units following the approval by
our unitholders of such conversion, and we will be obligated to seek this
approval by our unitholders promptly after the closing of the Energy
Transfer transaction.
- La Grange Energy will also own all 3,742,515 special units, a new class
of our units that will be issued in the Energy Transfer transaction. The
special units will be non-voting and will not be entitled to share in any
partnership distributions. The special units will be converted into an
equal number of common units following the occurrence of both: (1) the
approval by our unitholders of such conversion and (2) the Bossier
Pipeline becoming commercially operational, which we expect to occur by
mid-2004. We will be obligated to seek this approval by our unitholders
promptly after the closing of the Energy Transfer transaction.
- In connection with the Energy Transfer transaction, Heritage Holdings
will become one of our wholly owned subsidiaries, and its 4,426,916
common units will be converted into an equal number of class E units, a
new class of our units. These class E units will be the only outstanding
class E units. The class E units will be pledged to secure the $50
million promissory note that we will issue to the current owners as part
of the purchase price for Heritage Holdings. These class E units will be
entitled to aggregate cash distributions equal to 11.1% of the total
amount of cash distributed to all unitholders, including the class E
unitholders, up to $2.82 per unit per year.
- There will be 1,000,000 class C units outstanding. The class C units are
entitled to receive any cash distributions to which the incentive
distribution rights are entitled as a result of our receiving proceeds
from outstanding litigation filed by us. The class C units are not
entitled to any other distributions, do not generally have voting rights
and are not convertible into any other class of units.
We do not include the class C units, class E units and special units in our
pro forma per unit financial results included elsewhere in this prospectus
supplement. Please read "Description of Units" in this prospectus supplement and
the "Description of Common Units" in the accompanying prospectus for a more
complete discussion of the terms of our outstanding units.
Our general partner has sole responsibility for conducting our business and
managing our operations. Our general partner does not receive any management fee
or other compensation in connection with its management of our business, but it
is reimbursed for direct and indirect expenses incurred on our behalf.
S-7
The following chart depicts our organizational and ownership structure,
after giving effect to the offering and the Energy Transfer transaction.
(GRAPH)
(1) The percentages assume that all outstanding Class D units and special units
were converted into common units and exclude the Class C units and the Class E
units.
(2) La Grange Acquisition, L.P. conducts is operations under the name Energy
Transfer Company.
S-8
THE OFFERING
Common units offered.......... 7,000,000 common units.
8,050,000 common units if the underwriters
exercise their over-allotment option in full.
Price......................... $ per common unit.
Common and class D units
outstanding after this
offering and the Energy
Transfer transaction.......... 32,937,950 common and class D units if the
underwriters do not exercise their
over-allotment option (33,987,950 common and
class D units if the underwriters exercise
their over-allotment option in full).
We have assumed that 4,118,162 common units and
8,022,557 class D units will be issued to La
Grange Energy in the Energy Transfer
transaction. The number of common units to be
issued in the transaction will equal 19.99% of
the number of common units outstanding
immediately prior to the closing of the Energy
Transfer transaction (excluding the 4,426,916
common units held by Heritage Holdings) after
giving effect to this offering. The number of
class D units to be issued in the transaction
will equal the difference between 12,140,719
and the number of common units issued in the
transaction.
Other units outstanding after
this offering and the Energy
Transfer transaction.......... 1,000,000 class C units;
4,426,916 class E units; and
3,742,515 special units.
We do not include these class C units, class E
units and special units in our per unit
financial results included elsewhere in this
prospectus supplement and the documents
incorporated by reference in this prospectus
supplement. The class E units are not included
in our per unit financial results as these
units will be owned by our wholly-owned
subsidiary, Heritage Holdings, and are treated
as treasury units for accounting purposes. The
class C and special units are not included in
our per unit financial results because
distributions on these units are contingent
upon future events. These units will be
considered in our per unit financial results if
and/or when the contingencies are resolved.
Use of proceeds............... We expect to receive net proceeds of
approximately $263 million from this offering
(after deducting underwriters' discounts and
commissions). We plan to use the net cash
proceeds from this offering to repay
outstanding indebtedness and accrued interest
under the existing Energy Transfer credit
facility, to pay expenses associated with this
offering, the new Energy Transfer credit
facility and the Energy Transfer transaction
and for general partnership purposes.
S-9
Distributions of available
cash.......................... Under our partnership agreement, we must
distribute all of our cash on hand at the end
of each quarter, less reserves established by
our general partner in its discretion. We refer
to this cash as "available cash," and we define
it in our partnership agreement. We have
declared a cash distribution of $0.65 per
common unit on our outstanding units for the
first quarter of fiscal year 2004, which
distribution will be payable on January 14,
2004 to holders of record as of December 30,
2003. Under the quarterly incentive
distribution provisions, generally our general
partner is entitled, without duplication, to
15% of amounts we distribute in excess of $0.55
per common unit, 25% of amounts we distribute
in excess of $0.635 per common unit and 50% of
amounts we distribute in excess of $0.825 per
common unit. For a description of our cash
distribution policy, please read "Description
of Units" and "Cash Distribution Policy" in
this prospectus supplement and "Description of
Common Units" and "Cash Distribution Policy" in
the accompanying prospectus.
Timing of distributions....... We make distributions approximately 45 days
following November 30, February 28, May 31 and
August 31 to unitholders on the applicable
record date.
Estimated ratio of taxable
income to distributions....... We estimate that if you own the common units
you purchase in this offering through December
31, 2006, you will be allocated, on a
cumulative basis, an amount of federal taxable
income for that period that will be less than
20% of the cash distributed to you with respect
to that period. Please read "Tax
Considerations" in this prospectus supplement
for the basis of this estimate.
New York Stock Exchange
symbol........................ HPG.
S-10
HERITAGE PROPANE PARTNERS PRO FORMA FINANCIAL DATA
The following unaudited Pro Forma Financial Data reflects our historical
results as adjusted on a pro forma basis to give effect to the consummation of
the Energy Transfer transaction, the borrowing under the new Energy Transfer
credit facility described in "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources," and
this offering and the expected use of proceeds from the borrowing and this
offering as if these transactions occurred on September 1, 2002 for income
statement purposes and August 31, 2003 for balance sheet purposes. Although
Heritage Propane Partners, L.P. will be the surviving parent entity for legal
purposes, Energy Transfer will be the accounting acquiror. As a result,
following the closing of the Energy Transfer transaction, our historical
financial statements for periods prior to the closing will be the historical
financial statements of Energy Transfer. For a discussion of the assumptions and
specific adjustments used in preparing the Pro Forma Financial Data, please read
the pro forma financial statements included elsewhere in this prospectus
supplement.
<Table>
<Caption>
TWELVE MONTHS
ENDED
AUGUST 31, 2003
---------------------
(IN THOUSANDS, EXCEPT
PER UNIT AMOUNTS)
STATEMENT OF OPERATIONS DATA:
Revenues.................................................... $1,714,440
Costs and expenses:
Costs of products sold.................................... 1,309,497
Operating expenses........................................ 175,301
Depreciation and amortization............................. 56,342
Selling, general and administrative....................... 31,789
----------
Total costs and expenses................................ 1,572,929
----------
Operating income............................................ 141,511
Other income (expense):
Interest expense.......................................... (53,945)
Equity in earnings of affiliates.......................... 1,120
Gain on disposal of assets................................ 266
Other..................................................... (2,912)
----------
Income before minority interests and income taxes........... 86,040
Minority interests.......................................... 558
----------
Income before income taxes.................................. 85,482
Income taxes................................................ 10,924
----------
Net income.................................................. 74,558
General partner's interest in net income.................... 1,491
----------
Limited partners' interest in net income.................... $ 73,067
==========
Net income per unit......................................... $ 2.32
==========
BALANCE SHEET DATA (AT END OF PERIOD):
Cash and cash equivalents................................... $ 43,081
Working capital............................................. 7,242
Property, plant and equipment (net)......................... 863,160
Total assets................................................ 1,406,771
Long term debt, less current maturities..................... 685,762
Partners' capital........................................... 407,748
OTHER FINANCIAL DATA:
EBITDA, as adjusted(a)...................................... $ 200,475
</Table>
- ---------------
(a) EBITDA, as adjusted is defined as our earnings before interest, taxes,
depreciation, amortization and other non-cash items, such as compensation
charges for unit issuances to employees, gain or loss on
S-11
disposal of assets, and other expenses. We present EBITDA, as adjusted, on a
partnership basis which includes both the general and limited partner
interests. Non-cash compensation expense represents charges for the value of
the common units awarded under our compensation plans that have not yet
vested under the terms of those plans and are charges which do not, or will
not, require cash settlement. Non-cash income such as the gain arising from
our disposal of assets is not included when determining EBITDA, as adjusted.
EBITDA, as adjusted (i) is not a measure of performance calculated in
accordance with generally accepted accounting principles, or GAAP, and (ii)
should not be considered in isolation or as a substitute for net income,
income from operations or cash flow as reflected in our consolidated
financial statements.
EBITDA, as adjusted is presented because such information is relevant and is
used by management, industry analysts, investors, lenders and rating
agencies to assess the financial performance and operating results of our
fundamental business activities. Management believes that the presentation
of EBITDA, as adjusted is useful to lenders and investors because of its use
in the propane and midstream natural gas industries and for master limited
partnerships as an indicator of the strength and performance of our ongoing
business operations, including the ability to fund capital expenditures,
service debt and pay distributions. Additionally, management believes that
EBITDA, as adjusted provides additional and useful information to our
investors for trending, analyzing and benchmarking our operating results
from period to period as compared to other companies that may have different
financing and capital structures. The presentation of EBITDA, as adjusted
allows investors to view our performance in a manner similar to the methods
used by management and provides additional insight to our operating results.
EBITDA, as adjusted is used by management to determine our operating
performance, and along with other data as internal measures for setting
annual operating budgets, assessing financial performance of our numerous
business locations, as a measure for evaluating targeted businesses for
acquisition and as a measurement component of incentive compensation. We
have a large number of business locations located in different regions of
the United States. EBITDA, as adjusted can be a meaningful measure of
financial performance because it excludes factors which are outside the
control of the employees responsible for operating and managing the business
locations, and provides information management can use to evaluate the
performance of the business locations, or the region where they are located,
and the employees responsible for operating them. To present EBITDA, as
adjusted on a full partnership basis, we add back the minority interest of
the general partner because net income is reported net of the general
partner's minority interest. Our EBITDA, as adjusted includes non-cash
compensation expense which is a non-cash expense item resulting from our
unit based compensation plans that does not require cash settlement and is
not considered during management's assessment of the operating results of
our business. Adding these non-cash compensation expenses in EBITDA, as
adjusted allows management to compare our operating results to those of
other companies in the same industry who may have compensation plans with
levels and values of annual grants that are different than us. Other
expenses include other finance charges and other asset non-cash impairment
charges that are reflected in our operating results but are not classified
in interest, depreciation and amortization. We do not include gain on the
sale of assets when determining EBITDA, as adjusted since including non-cash
income resulting from the sale of assets increases the performance measure
in a manner that is not related to the true operating results of our
business. In addition, our debt agreements contain financial covenants based
on EBITDA, as adjusted. For a description of these covenants, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations-Description of Indebtedness."
There are material limitations to using a measure such as EBITDA, as
adjusted, including the difficulty associated with using it as the sole
measure to compare the results of one company to another, and the inability
to analyze certain significant items that directly affect a company's net
income or loss. In addition, our calculation of EBITDA, as adjusted may not
be consistent with similarly titled measures of other companies and should
be viewed in conjunction with measurements that are computed in accordance
with GAAP. EBITDA, as adjusted for the periods described herein
S-12
is calculated in the same manner as presented by us in the past. Management
compensates for these limitations by considering EBITDA, as adjusted in
conjunction with its analysis of other GAAP financial measures, such as
gross profit, net income (loss), and cash flow from operating activities. A
reconciliation of EBITDA, as adjusted to net income (loss) is presented
below. Please read "-- Reconciliation of EBITDA, As Adjusted, to Pro Forma
Net Income" below.
RECONCILIATION OF PRO FORMA EBITDA, AS ADJUSTED, TO PRO FORMA NET INCOME
The following table sets forth the reconciliation of pro forma EBITDA, as
adjusted, to our pro forma net income for the twelve months ended August 31,
2003:
<Table>
<Caption>
TWELVE MONTHS ENDED
AUGUST 31, 2003
-------------------
(IN THOUSANDS)
Net income.................................................. $ 74,558
Depreciation and amortization............................... 56,342
Interest.................................................... 53,945
Taxes....................................................... 10,924
Non-cash compensation expense............................... 1,159
Other expenses.............................................. 2,912
Depreciation, amortization, and interest and taxes of
investee.................................................. 901
Less: Gain on disposal of assets............................ (266)
--------
EBITDA, as adjusted......................................... $200,475
========
</Table>
S-13
RISK FACTORS
An investment in our common units involves a high degree of risk. You
should carefully consider the following risk factors together with all of the
other information included in, or incorporated by reference into, this
prospectus supplement in evaluating an investment in our common units. If any of
the following risks were to occur, our business, financial condition or results
of operations could be adversely affected. In that case, the trading price of
our common units could decline and you could lose all or part of your
investment.
These risks only relate to the Energy Transfer transaction and the
operations of Energy Transfer. For information concerning the other risks
related to our business, please read the risk factors included under the caption
"Risk Factors" beginning on page 2 of the accompanying prospectus.
AS PART OF THE ENERGY TRANSFER TRANSACTIONS, LA GRANGE ENERGY WILL ACQUIRE OUR
GENERAL PARTNER AND A LARGE PORTION OF OUR UNITS. AS A RESULT, OUR FUTURE
MANAGEMENT AND BUSINESS STRATEGIES WILL DIFFER SUBSTANTIALLY FROM OUR PREVIOUS
MANAGEMENT AND BUSINESS STRATEGIES, WHICH WILL HAVE AN IMPACT ON AN INVESTMENT
IN OUR COMMON UNITS.
In connection with the Energy Transfer transactions, La Grange Energy will
purchase all of the partnership interests of U.S. Propane, L.P., our general
partner, and all of the member interests of U.S. Propane, L.L.C., the general
partner of U.S. Propane, L.P. In addition, La Grange Energy will own 42% of our
common units (assuming the conversion of the class D units and special units
into common units). As a result of La Grange Energy's purchase of our general
partner, it is contemplated that La Grange Energy will make various changes to
our management structure. Please read "Management" included elsewhere in this
prospectus supplement for a description of our existing management structure and
our expected management structure following the Energy Transfer transactions. La
Grange Energy was formed to invest in the midstream natural gas industry and is
the current owner of Energy Transfer, a midstream natural gas business. As the
owner of our general partner following the closing of the Energy Transfer
transactions, La Grange Energy will have significant influence over our future
business strategy. La Grange Energy and our new management team may have
different business strategies and approaches to operating our partnership than
the current owners of our general partner and our current management team. In
particular, we expect that midstream acquisitions will be the primary focus of
our acquisition strategy following the closing of the Energy Transfer
transactions. Failure to successfully implement these new business strategies
and operating approaches may have a material adverse effect on our business,
financial condition and results of operations.
AFTER COMPLETION OF THE ACQUISITION OF ENERGY TRANSFER, THE AMOUNT OF CASH WE
WILL BE ABLE TO DISTRIBUTE ON OUR COMMON UNITS PRINCIPALLY WILL DEPEND UPON THE
AMOUNT OF CASH WE GENERATE FROM THE OPERATIONS OF ENERGY TRANSFER AND OUR
EXISTING PROPANE OPERATIONS.
Under the terms of our partnership agreement, we must pay our general
partner's expenses and set aside any cash reserve amounts before making a
distribution to our unitholders. After completion of the acquisition of Energy
Transfer, the amount of cash we will be able to distribute on our common units
principally will depend upon the amount of cash we generate from the operations
of Energy Transfer and our existing propane operations. The amount of cash we
will generate will fluctuate from quarter to quarter based on, among other
things:
- the amount of natural gas transported on the Oasis Pipeline and in Energy
Transfer's gathering systems;
- the level of throughput in Energy Transfer's processing and treating
operations;
- the fees Energy Transfer charges and the margins it realizes for its
services;
- the price of natural gas;
- the relationship between natural gas and NGL prices;
S-14
- the weather in our operating areas;
- the cost to us of the propane we buy for resale and the prices we receive
for our propane;
- the level of competition from other propane companies and other energy
providers; and
- the level of our operating costs.
In addition, the actual amount of cash we will have available for
distribution will depend on other factors, some of which are beyond our control,
including:
- the level of capital expenditures we make;
- the cost of acquisitions, if any;
- our debt service requirements;
- fluctuations in our working capital needs;
- restrictions on distributions contained in our debt agreements;
- our ability to make working capital borrowings under our credit
facilities to pay distributions;
- prevailing economic conditions; and
- the amount of cash reserves established by our general partner in its
sole discretion for the proper conduct of our business.
We cannot guarantee that, after our acquisition of Energy Transfer, we will
have sufficient available cash each quarter to pay a specific level of cash
distributions to our unitholders. You should also be aware that the amount of
cash we have available for distribution depends primarily upon our cash flow,
including cash flow from financial reserves and working capital borrowings, and
is not solely a function of profitability, which will be affected by non-cash
items. As a result, we may make cash distributions during periods when we record
losses and may not make cash distributions during periods when we record net
income.
WE MAY BE UNABLE TO SUCCESSFULLY INTEGRATE THE OPERATIONS OF ENERGY TRANSFER
WITH OUR OPERATIONS AND TO REALIZE ALL OF THE ANTICIPATED BENEFITS OF THE
ACQUISITION OF ENERGY TRANSFER.
The acquisition of Energy Transfer involves the integration of two
companies in separate lines of business that previously have operated
independently, which is a complex, costly and time-consuming process. Failure to
successfully integrate these two companies may have a material adverse effect on
our business, financial condition or results of operations. The difficulties of
combining the companies include, among other things:
- operating a significantly larger combined company and adding a new
business segment, midstream operations, to our existing propane
operations;
- the necessity of coordinating geographically disparate organizations,
systems and facilities;
- integrating personnel with diverse business backgrounds and
organizational cultures; and
- consolidating corporate and administrative functions.
Combining the two companies is made particularly difficult by the large
size of Energy Transfer as compared to Heritage Propane. For example, Energy
Transfer's pro forma revenues for the 12 months ended August 31, 2003 were
approximately $1.1 billion as compared to Heritage Propane's revenues of
approximately $571 million for the same period. Additionally, the two companies
operate in distinct business segments that require different operating
strategies and different managerial expertise. Our existing management does not
have substantial experience operating in the midstream natural gas industry.
Likewise, Energy Transfer's management team does not have substantial experience
operating in the
S-15
propane industry. While we intend to operate each of these two business segments
independently by management experienced in such segments, we cannot assure you
that this approach will be successful.
The process of combining the two companies could cause an interruption of,
or loss of momentum in, the activities of the combined company's business and
the loss of key personnel. The diversion of management's attention and any
delays or difficulties encountered in connection with the acquisition and the
integration of the two companies could harm the business, results of operations,
financial condition or prospects of the combined company after the acquisition.
Furthermore, the integration of us and Energy Transfer may not result in the
realization of the full benefits anticipated by the companies to result from the
acquisition.
ENERGY TRANSFER'S PROFITABILITY IS DEPENDENT UPON PRICES AND MARKET DEMAND FOR
NATURAL GAS AND NGLS, WHICH ARE BEYOND ITS CONTROL AND HAVE BEEN VOLATILE.
Energy Transfer is subject to significant risks due to fluctuations in
commodity prices. During the 11 months ended August 31, 2003, Energy Transfer
generated approximately 54% of its gross margin from three types of contractual
arrangements under which its margin is exposed to increases and decreases in the
price of natural gas and NGLs -- discount-to-index, percentage-of-proceeds and
keep-whole arrangements.
For a portion of the natural gas gathered at the Southeast Texas System and
the Elk City System, Energy Transfer purchases natural gas from producers at the
wellhead at a price that is at a discount to a specified index price and then
gathers and delivers the natural gas to pipelines where it typically resells the
natural gas at the index price. Generally, the gross margins it realizes under
these discount-to-index arrangements decrease in periods of low natural gas
prices because these gross margins are based on a percentage of the index price.
Accordingly, a decrease in the price of natural gas could have a material
adverse effect on Energy Transfer's results of operations.
For a portion of the natural gas gathered at the Southeast Texas System and
the Elk City System, Energy Transfer enters into percentage-of-proceeds
arrangements and keep-whole arrangements, pursuant to which it agrees to gather
and process natural gas received from the producers. Under percentage-of-
proceeds arrangements, it generally sells the residue gas and NGLs at market
prices and remits to the producers an agreed upon percentage of the proceeds
based on an index price. In other cases, instead of remitting cash payments to
the producer, Energy Transfer delivers an agreed upon percentage of the residue
gas and NGL volumes to the producer and sells the volumes it keeps to third
parties at market prices. Under these arrangements, Energy Transfer's revenues
and gross margins decline when natural gas prices and NGL prices decrease.
Accordingly, a decrease in the price of natural gas or NGLs could have a
material adverse effect on its results of operations. Under keep-whole
arrangements, Energy Transfer generally sells the NGLs produced from its
gathering and processing operations to third parties at market prices. Because
the extraction of the NGLs from the natural gas during processing reduces the
Btu content of the natural gas, Energy Transfer must either purchase natural gas
at market prices for return to producers or make a cash payment to producers
equal to the value of this natural gas. Under these arrangements, Energy
Transfer's revenues and gross margins decrease when the price of natural gas
increases relative to the price of NGLs if it is not able to bypass its
processing plants and sell the unprocessed natural gas. Accordingly, an increase
in the price of natural gas relative to the price of NGLs could have a material
adverse effect on Energy Transfer's results of operations.
In the past, the prices of natural gas and NGLs have been extremely
volatile, and we expect this volatility to continue. For example, during the 11
months ended August 31, 2003, the NYMEX settlement price for the prompt month
contract ranged from a high of $9.58 per MMBtu to a low of $3.72 per MMBtu. A
composite of the Mt. Belvieu average NGLs price based upon Energy Transfer's
average NGLs composition during the 11 months ended August 31, 2003 ranged from
a high of approximately $0.82 per gallon to a low of approximately $0.41 per
gallon.
Average realized natural gas sales prices for the 11 months ended August
31, 2003 substantially exceeded Energy Transfer's historical realized natural
gas prices as well as recent natural gas prices. For
S-16
example, Energy Transfer's average realized natural gas price increased $2.31,
or 85.0%, from $2.72 per MMBtu for the 9 months ended September, 2002 to $5.03
per MMBtu for 11 months ended August 31, 2003. On December 15, 2003 the NYMEX
settlement price for January natural gas deliveries was $6.95 per MMBtu, which
was 38.2% higher than Energy Transfer's average natural gas price for the 11
months ended August 31, 2003. Natural gas prices are subject to significant
fluctuations, and there can be no assurance that natural gas prices will remain
at the high level recently experienced.
The markets and prices for residue gas and NGLs depend upon factors beyond
Energy Transfer's control. These factors include demand for oil, natural gas and
NGLs, which fluctuate with changes in market and economic conditions, and other
factors, including:
- the impact of weather on the demand for oil and natural gas;
- the level of domestic oil and natural gas production;
- the availability of imported oil and natural gas;
- actions taken by foreign oil and gas producing nations;
- the availability of local, intrastate and interstate transportation
systems;
- the availability and marketing of competitive fuels;
- the impact of energy conservation efforts; and
- the extent of governmental regulation and taxation.
ENERGY TRANSFER'S SUCCESS DEPENDS UPON ITS ABILITY TO CONTINUALLY FIND AND
CONTRACT FOR NEW SOURCES OF NATURAL GAS SUPPLY.
In order to maintain or increase throughput levels on its gathering and
transportation pipeline systems and asset utilization rates at its treating and
processing plants, Energy Transfer must continually contract for new natural gas
supplies. It may not be able to obtain additional contracts for natural gas
supplies. The primary factors affecting Energy Transfer's ability to connect new
supplies of natural gas to its gathering systems include its success in
contracting for existing natural gas supplies that are not committed to other
systems and the level of drilling activity near its gathering systems. The
primary factors affecting its ability to attract customers to the Oasis Pipeline
include its access to other natural gas pipelines, natural gas markets, natural
gas-fired power plants and other industrial end-users and the level of drilling
in areas connected to the Oasis Pipeline.
Fluctuations in energy prices can greatly affect production rates and
investments by third parties in the development of new oil and natural gas
reserves. Drilling activity generally decreases as oil and natural gas prices
decrease. Energy Transfer has no control over the level of drilling activity in
the areas of operations, the amount of reserves underlying the wells and the
rate at which production from a well will decline, sometimes referred to as the
"decline rate." In addition, Energy Transfer has no control over producers or
their production decisions, which are affected by, among other things,
prevailing and projected energy prices, demand for hydrocarbons, the level of
reserves, geological considerations, governmental regulation and the
availability and cost of capital.
A substantial portion of Energy Transfer's assets, including its gathering
systems and its processing and treating plants, are connected to natural gas
reserves and wells for which the production will naturally decline over time. In
particular, the Southeast Texas System covers portions of the Austin Chalk,
Buda, Georgetown, Edwards, Wilcox and other producing formations in southeast
Texas, which we collectively refer to as the Austin Chalk trend, and the Elk
City System covers portions of the Anadarko basin in western Oklahoma. Both of
these natural gas producing regions have generally been characterized by high
initial flow rates followed by steep initial declines in production.
Accordingly, Energy Transfer's cash flows associated with these systems will
also decline unless it is able to access new supplies of natural gas by
connecting additional production to these systems. A material decrease in
natural gas production in Energy Transfer's areas of operation, as a result of
depressed commodity prices or otherwise, would result in a
S-17
decline in the volume of natural gas it handles, which would reduce its revenues
and operating income. In addition, Energy Transfer's future growth will depend,
in part, upon whether it can contract for additional supplies at a greater rate
than the rate of natural decline in its currently connected supplies.
ENERGY TRANSFER DEPENDS ON CERTAIN KEY PRODUCERS FOR ITS SUPPLY OF NATURAL GAS
ON THE SOUTHEAST TEXAS SYSTEM AND THE ELK CITY SYSTEM, THE LOSS OF ANY OF THESE
KEY PRODUCERS COULD ADVERSELY AFFECT ITS FINANCIAL RESULTS.
For the 11 months ended August 31, 2003, Anadarko Petroleum Corp. and
Chesapeake Energy Corp. supplied Energy Transfer with approximately 44% of the
Southeast Texas System's natural gas supply, and Chesapeake Energy Corp. and
Kaiser-Francis Oil Company and its affiliates supplied Energy Transfer with
approximately 53% of the Elk City System's natural gas supply. To the extent
that these and other producers may reduce the volumes of natural gas that they
supply Energy Transfer, Energy Transfer would be adversely affected unless it
was able to acquire comparable supplies of natural gas from other producers.
LA GRANGE ENERGY MAY SELL UNITS OR OTHER LIMITED PARTNER INTERESTS IN THE
TRADING MARKET, WHICH COULD REDUCE THE MARKET PRICE OF UNITHOLDERS' LIMITED
PARTNER INTERESTS.
Following the completion of the Energy Transfer transaction, La Grange
Energy will own approximately 4,118,162 common units, 8,022,557 class D units
and 3,742,515 special units. Following the approval of our unitholders and other
conditions, the class D units and special units will be converted into an equal
number of common units. In the future, La Grange Energy may dispose of some or
all of these units. If La Grange Energy were to dispose of a substantial portion
of these units in the trading markets, it could reduce the market price of our
outstanding common units. Our partnership agreement allows La Grange Energy to
cause us to register for sale units held by La Grange Energy. These registration
rights allow La Grange Energy to request registration of its common units, class
D units and special units and to include any of those units in a registration of
other securities by us.
FEDERAL, STATE OR LOCAL REGULATORY MEASURES COULD ADVERSELY AFFECT ENERGY
TRANSFER'S BUSINESS.
As a natural gas gatherer and intrastate pipeline company, Energy Transfer
generally is exempt from Federal Energy Regulatory Commission, or FERC,
regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still
significantly affects its business and the market for its products. In recent
years, FERC has pursued pro-competitive policies in its regulation of interstate
natural gas pipelines. However, we cannot assure you that FERC will continue
this approach as it considers matters such as pipeline rates and rules and
policies that may affect rights of access to natural gas transportation
capacity. In addition, the rates, terms and conditions of some of the
transportation services Energy Transfer provides on the Oasis Pipeline are
subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or
NGPA. Under Section 311, rates charged for transportation must be fair and
equitable, and amounts collected in excess of fair and equitable rates are
subject to refund with interest.
Energy Transfer's intrastate natural gas transportation pipelines are
located in Texas and some are subject to regulation as common purchasers and as
gas utilities by the Texas Railroad Commission, or TRRC. The TRRC's jurisdiction
extends to both rates and pipeline safety. The rates Energy Transfer charges for
transportation services are deemed just and reasonable under Texas law unless
challenged in a complaint. Should a complaint be filed or should regulation
become more active, its business may be adversely affected.
Other state and local regulations also affect Energy Transfer's business.
Energy Transfer is subject to ratable take and common purchaser statutes in
Texas, Oklahoma and Louisiana, the states where it operates. Ratable take
statutes generally require gatherers to take, without undue discrimination,
natural gas production that may be tendered to the gatherer for handling.
Similarly, common purchaser statutes generally require gatherers to purchase
without undue discrimination as to source of supply or producer. These statutes
have the effect of restricting Energy Transfer's right as an owner of gathering
facilities to
S-18
decide with whom it contracts to purchase or transport natural gas. Federal law
leaves any economic regulation of natural gas gathering to the states, and some
of the states in which Energy Transfer operates have adopted complaint-based or
other limited economic regulation of natural gas gathering activities. States in
which Energy Transfer operates that have adopted some form of complaint-based
regulation, like Oklahoma and Texas, generally allow natural gas producers and
shippers to file complaints with state regulators in an effort to resolve
grievances relating to natural gas gathering rates and access.
The states in which Energy Transfer conducts operations administer federal
pipeline safety standards under the Pipeline Safety Act of 1968, which requires
certain pipelines to comply with safety standards in constructing and operating
the pipelines, and subjects pipelines to regular inspections. Certain of Energy
Transfer's gathering facilities are exempt from the requirements of this Act. In
respect to recent pipeline accidents in other parts of the country, Congress and
the Department of Transportation have passed or are considering heightened
pipeline safety requirements. See "Business -- Energy Transfer -- Regulation."
Failure to comply with applicable regulations under the NGA, NGPA, Pipeline
Safety Act and certain state laws can result in the imposition of
administrative, civil and criminal remedies.
ENERGY TRANSFER'S BUSINESS INVOLVES HAZARDOUS SUBSTANCES AND MAY BE ADVERSELY
AFFECTED BY ENVIRONMENTAL REGULATION.
Many of the operations and activities of Energy Transfer's gathering
systems, plants and other facilities are subject to significant federal, state
and local environmental laws and regulations. These include, for example, laws
and regulations that impose obligations related to air emissions and discharge
of wastes from its facilities and the cleanup of hazardous substances that may
have been released at properties currently or previously owned or operated by
Energy Transfer or locations to which it has sent wastes for disposal. Various
governmental authorities have the power to enforce compliance with these
regulations and the permits issued under them, and violators are subject to
administrative, civil and criminal penalties, including civil fines, injunctions
or both. Liability may be incurred without regard to fault for the remediation
of contaminated areas. Private parties, including the owners of properties
through which Energy Transfer's gathering systems pass, may also have the right
to pursue legal actions to enforce compliance as well as to seek damages for
non-compliance with environmental laws and regulations or for personal injury or
property damage.
There is inherent risk of the incurrence of environmental costs and
liabilities in Energy Transfer's business due to its handling of natural gas and
other petroleum products, air emissions related to its operations, historical
industry operations, waste disposal practices and the prior use of natural gas
flow meters containing mercury. In addition, the possibility exists that
stricter laws, regulations or enforcement policies could significantly increase
Energy Transfer's compliance costs and the cost of any remediation that may
become necessary. Energy Transfer may incur material environmental costs and
liabilities. Furthermore, its insurance may not provide sufficient coverage in
the event an environmental claim is made against Energy Transfer.
Energy Transfer's business may be adversely affected by increased costs due
to stricter pollution control requirements or liabilities resulting from
non-compliance with required operating or other regulatory permits. New
environmental regulations might adversely affect its products and activities,
including gathering, compression, treating, processing and transportation, as
well as waste management and air emissions. Federal and state agencies could
also impose additional safety requirements, any of which could affect Energy
Transfer's profitability. See "Business -- Energy Transfer -- Environmental
Matters."
S-19
ENERGY TRANSFER'S BUSINESS INVOLVES MANY HAZARDS AND OPERATIONAL RISKS, SOME OF
WHICH MAY NOT BE FULLY COVERED BY INSURANCE.
Energy Transfer's operations are subject to the many hazards inherent in
the gathering, compression, treating, processing and transportation of natural
gas and NGLs, including:
- damage to pipelines, related equipment and surrounding properties caused
by hurricanes, tornadoes, floods, fires and other natural disasters and
acts of terrorism;
- inadvertent damage from construction and farm equipment;
- leaks of natural gas, NGLs and other hydrocarbons; and
- fires and explosions.
These risks could result in substantial losses due to personal injury
and/or loss of life, severe damage to and destruction of property and equipment
and pollution or other environmental damage and may result in curtailment or
suspension of our related operations. Energy Transfer's operations are primarily
concentrated in Texas, and a natural disaster or other hazard affecting this
area could have a material adverse effect on its operations. Energy Transfer is
not fully insured against all risks incident to its business. It does not have
property insurance on all of its underground pipeline systems that would cover
damage to the pipelines. It is not insured against all environmental accidents
that might occur, other than those considered to be sudden and accidental.
Energy Transfer has minimal business interruption insurance that covers the
Oasis Pipeline. Under the terms of Energy Transfer's general liability and
workers compensation policies, claims of up to $1 million are insured. Energy
Transfer also has excess liability coverage for claims up to $35 million per
occurrence after the payment of a $1 million deductible. If a significant
accident or event occurs that is not fully insured, it could adversely affect
Energy Transfer's operations and financial condition.
ANY REDUCTION IN THE CAPACITY OF, OR THE ALLOCATIONS TO, ENERGY TRANSFER'S
SHIPPERS IN INTERCONNECTING, THIRD-PARTY PIPELINES COULD CAUSE A REDUCTION OF
VOLUMES TRANSPORTED IN ITS PIPELINES, WHICH WOULD ADVERSELY AFFECT ENERGY
TRANSFER'S REVENUES AND CASH FLOW.
Users of Energy Transfer's pipelines are dependent upon connections to
third-party pipelines to receive and deliver natural gas and NGLs. Any reduction
of capacities of these interconnecting pipelines due to testing, line repair,
reduced operating pressures, or other causes could result in reduced volumes
transported in Energy Transfer's pipelines. Similarly, if additional shippers
begin transporting volumes of natural gas and NGLs over interconnecting
pipelines, the allocations to existing shippers in these pipelines would be
reduced, which could also reduce volumes transported in Energy Transfer's
pipelines. Any reduction in volumes transported in Energy Transfer's pipelines
would adversely affect its revenues and cash flow.
ENERGY TRANSFER ENCOUNTERS COMPETITION FROM OTHER MIDSTREAM COMPANIES.
Energy Transfer experiences competition in all of its markets. Energy
Transfer's principal areas of competition include obtaining natural gas supplies
for the Southeast Texas System and Elk City System and natural gas
transportation customers for the Oasis Pipeline. Energy Transfer's competitors
include major integrated oil companies, interstate and intrastate pipelines and
companies that gather, compress, treat, process, transport and market natural
gas. The Oasis Pipeline competes directly with two other major intrastate
pipelines that link the Waha Hub and the Houston area, one of which is owned by
Duke Energy Field Services, LLC and the other one of which is owned by El Paso
Corporation and American Electric Power Service Corporation. The Southeast Texas
System competes with natural gas gathering and processing systems owned by Duke
Energy Field Services, LLC and Devon Energy Corporation. The Elk City System
competes with natural gas gathering and processing systems owned by Enogex,
Inc., Oneok Gas Gathering, L.L.C., CenterPoint Energy Field Services, Inc. and
Enbridge Inc., as well as producer owned systems. Many of Energy Transfer's
competitors have greater financial resources and access to larger natural gas
supplies than Energy Transfer does.
S-20
EXPANDING ENERGY TRANSFER'S BUSINESS BY CONSTRUCTING NEW PIPELINES AND TREATING
AND PROCESSING FACILITIES SUBJECTS ENERGY TRANSFER TO CONSTRUCTION RISKS.
One of the ways Energy Transfer may grow its business is through the
construction of additions to its existing gathering, compression, treating,
processing and transportation system. The construction of a new pipeline or the
expansion of an existing pipeline, by adding additional horsepower or pump
stations or by adding a second pipeline along an existing pipeline, and the
construction of new processing or treating facilities, involve numerous
regulatory, environmental, political and legal uncertainties beyond its control
and require the expenditure of significant amounts of capital. If Energy
Transfer undertakes these projects, they may not be completed on schedule or at
all or at the budgeted cost. Moreover, Energy Transfer's revenues may not
increase immediately upon the expenditure of funds on a particular project. For
instance, if Energy Transfer builds a new pipeline, the construction will occur
over an extended period of time, and Energy Transfer will not receive any
material increases in revenues until after completion of the project. Moreover,
it may construct facilities to capture anticipated future growth in production
in a region in which such growth does not materialize. As a result, new
facilities may not be able to attract enough throughput to achieve Energy
Transfer's expected investment return, which could adversely affect its results
of operations and financial condition.
ENERGY TRANSFER DEPENDS ON KOCH HYDROCARBONS, L.P. TO PURCHASE AND FRACTIONATE
THE NGLS PRODUCED AT THE ELK CITY PROCESSING PLANT.
All of the NGLs produced at the Elk City processing plant are transported
by Koch Hydrocarbons and delivered for fractionation to Conway, Kansas. There
are no other fractionation plants or other NGL markets connected to the Elk City
processing plant. As a result, if Koch Hydrocarbons refuses or is unable to
transport or fractionate these NGLs, Energy Transfer's only alternative in the
short term would be to transport NGLs by truck to another fractionation plant or
another NGL market, which would likely result in additional costs and adversely
affect its ability to market the NGLs.
ENERGY TRANSFER IS EXPOSED TO THE CREDIT RISK OF ITS CUSTOMERS, AND AN INCREASE
IN THE NONPAYMENT AND NONPERFORMANCE BY ITS CUSTOMERS COULD REDUCE OUR ABILITY
TO MAKE DISTRIBUTIONS TO OUR UNITHOLDERS.
Risks of nonpayment and nonperformance by Energy Transfer's customers are a
major concern in its business. Several participants in the energy industry have
been receiving heightened scrutiny from the financial markets in light of the
collapse of Enron Corp. Energy Transfer is subject to risks of loss resulting
from nonpayment or nonperformance by its customers. Any increase in the
nonpayment and nonperformance by its customers could reduce our ability to make
distributions to our unitholders.
ENERGY TRANSFER MAY NOT BE ABLE TO BYPASS THE LA GRANGE PROCESSING PLANT, WHICH
WOULD EXPOSE ENERGY TRANSFER TO THE RISK OF UNFAVORABLE PROCESSING MARGINS.
Because of Energy Transfer's ownership of the Oasis Pipeline, it can
generally elect to bypass the La Grange processing plant when processing margins
are unfavorable and instead deliver pipeline-quality gas by blending rich gas
from the Southeast Texas System with lean gas transported on the Oasis Pipeline.
In some circumstances, such as when Energy Transfer does not have a sufficient
amount of lean gas to blend with the volume of rich gas that it receives at the
La Grange processing plant, Energy Transfer may have to process the rich gas. If
it has to process when processing margins are unfavorable, Energy Transfer's
results of operations will be adversely affected.
ENERGY TRANSFER MAY NOT BE ABLE TO RETAIN EXISTING CUSTOMERS OR ACQUIRE NEW
CUSTOMERS, WHICH WOULD REDUCE ITS REVENUES AND LIMIT ITS FUTURE PROFITABILITY.
The renewal or replacement of existing contracts with Energy Transfer's
customers at rates sufficient to maintain current revenues and cash flows
depends on a number of factors beyond its control, including competition from
other pipelines, and the price of, and demand for, natural gas in the markets it
serves.
S-21
For the 11 months ended August 31, 2003, approximately 23% of Energy
Transfer's sales of natural gas were to industrial end-users and utilities. As a
consequence of the increase in competition in the industry and volatility of
natural gas prices, end-users and utilities are increasingly reluctant to enter
into long-term purchase contracts. Many end-users purchase natural gas from more
than one natural gas company and have the ability to change providers at any
time. Some of these end-users also have the ability to switch between gas and
alternate fuels in response to relative price fluctuations in the market.
Because there are numerous companies of greatly varying size and financial
capacity that compete with Energy Transfer in the marketing of natural gas,
Energy Transfer often competes in the end-user and utilities markets primarily
on the basis of price. The inability of Energy Transfer's management to renew or
replace its current contracts as they expire and to respond appropriately to
changing market conditions could have a negative effect on its profitability.
ENERGY TRANSFER HAS A LIMITED OPERATING HISTORY.
Energy Transfer acquired substantially all of its assets in October 2002
and December 2002 and has therefore only operated them together under common
management for a limited period of time. Furthermore, the success of Energy
Transfer's business strategy is dependent upon its operating these assets
substantially differently from the manner in which Aquila Gas Pipeline operated
them. As a result, Energy Transfer's historical and pro forma financial
information may not give you an accurate indication of what its actual results
would have been if Energy Transfer had completed the acquisitions at the
beginning of the periods presented or its future results of operations. If
Energy Transfer is unable to operate these assets in accordance with Energy
Transfer's business strategy, it will have a material adverse effect on Energy
Transfer's results of operations.
S-22
USE OF PROCEEDS
We expect to receive net proceeds of approximately $263 million from the
sale of the 7,000,000 common units we are offering, after deducting underwriting
discounts and commissions. In connection with this offering, we also expect to
receive a capital contribution of $5.7 million from our general partner to
maintain its 2% general partner interest.
We anticipate using the aggregate net proceeds of this offering:
- to repay indebtedness and accrued interest outstanding under the existing
Energy Transfer credit facility, which was $218.8 million as of December
31, 2003;
- to pay expenses associated with this offering, the new Energy Transfer
credit facility and the Energy Transfer transaction, which we expect to
be approximately $8.4 million; and
- for general partnership purposes.
Concurrently with this offering, we will borrow $275 million under the new
Energy Transfer credit facility. We anticipate using the proceeds of this
borrowing and cash on hand:
- to make a cash payment of $91.8 million to La Grange Energy as part of
the purchase price of Energy Transfer, which includes a reimbursement of
capital expenditures relating to the purchase of the assets of Aquila Gas
Pipeline Corporation and the interests in Oasis Pipe Line Company not
owned by Aquila Gas Pipeline;
- to pay Energy Transfer's accounts payable and other specified
liabilities, which were $137.2 million as of August 31, 2003; and
- to pay $50 million as part of the purchase price of Heritage Holdings.
Indebtedness outstanding under the existing Energy Transfer credit facility
was incurred to finance the acquisition of assets from Aquila Gas Pipeline and
the remaining 50% equity interest of Oasis Pipe Line Company that was not owned
by Aquila Gas Pipeline. As of December 31, 2003, there was $218.5 million
outstanding under this facility with a weighted average interest rate of 4.4%
per annum. The facility matures in September 2005.
We will use the proceeds from any exercise of the underwriters'
over-allotment option for general partnership purposes.
S-23
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
The common units are listed and traded on the New York Stock Exchange under
the symbol "HPG." The following table shows the high and low sales prices for
the common units on the New York Stock Exchange Composite Transactions Tape and
the cash distribution paid per common unit for the quarterly periods ending on
the dates indicated.
COMMON UNIT PRICE RANGE
<Table>
<Caption>
CASH
PRICE RANGE HIGH LOW DISTRIBUTIONS(a)
- ----------- ------- ------- ----------------
FISCAL 2002
November 30, 2001................................ $28.990 $24.650 $0.6375
February 28, 2002................................ 30.550 25.510 0.6375
May 31, 2002..................................... 29.000 26.500 0.6375
August 31, 2002.................................. 27.600 22.500 0.6375
FISCAL 2003
November 30, 2002................................ $28.250 $24.500 $0.6375
February 28, 2003................................ 29.570 27.050 0.6375
May 31, 2003..................................... 29.900 27.760 0.6375
August 31, 2003.................................. 32.540 29.600 0.6500
FISCAL 2004
November 30, 2003(b)............................. $ 38.70 $ 31.02 $0.6500
February 28, 2004(c)............................. 42.66 37.56 --
</Table>
- ---------------
(a) Distributions are shown in the quarter with respect to which they were
declared.
(b) Declared for unitholders of record for December 30, 2003. The distribution
is payable on January 14, 2004.
(c) Through January 6, 2004.
The last reported sales price of common units on the NYSE on January 6,
2004 was $39.70 per common unit. As of September 30, 2003, there were
approximately 16,800 individual common unitholders.
S-24
CAPITALIZATION
The following table sets forth our historical capitalization as of August
31, 2003 and our pro forma as adjusted capitalization to give effect to:
- the Energy Transfer transaction;
- the incurrence of approximately $275 million of indebtedness under the
new Energy Transfer credit facility and the use of the proceeds
therefrom; and
- our public offering of the common units made pursuant to this prospectus
supplement and the use of the proceeds therefrom.
Please read "Use of Proceeds."
<Table>
<Caption>
AS OF AUGUST 31, 2003
----------------------
PRO FORMA
ACTUAL AS ADJUSTED
-------- -----------
(UNAUDITED)
(DOLLARS IN THOUSANDS)
Cash and cash equivalents................................... $ 7,117 $ 43,081
======== ==========
Short-term debt:
Working capital facilities................................ $ 26,700 $ 26,700
Current maturities of long-term debt...................... 38,309 38,309
Long-term debt:
Senior secured notes...................................... 353,143 353,143
Senior revolving acquisition facility..................... 24,700 24,700
New Energy Transfer credit facility....................... -- 275,000
Note payable to acquire Heritage Holdings................. -- 50,000
Notes payable on noncompete agreements.................... 20,110 20,110
Other..................................................... 1,118 1,118
-------- ----------
Total long-term debt................................... 399,071 724,071
Less current maturities................................ (38,309) (38,309)
-------- ----------
Long-term debt, less current maturities................ 360,762 685,762
-------- ----------
Total debt.................................................. 425,771 750,771
-------- ----------
Partners' capital:
Common unitholders, 24,915,393 issued and outstanding..... 221,207 385,782
Class C unitholders, 1,000,000 authorized, issued and
outstanding............................................ -- --
Class D unitholders, 8,022,557 authorized, issued and
outstanding............................................ -- 207,876
Class E unitholders, 4,426,916 authorized, issued and
outstanding............................................ -- (200,386)
Special unitholders, 3,742,515 authorized, issued and
outstanding............................................ -- --
General partner........................................... 2,190 14,476
Accumulated other comprehensive income.................... (349) --
-------- ----------
Total partners' capital..................................... 223,048 407,748
-------- ----------
Total capitalization........................................ $648,819 $1,158,519
======== ==========
</Table>
S-25
HERITAGE PROPANE PARTNERS SELECTED HISTORICAL
FINANCIAL AND OPERATING DATA
The following table sets forth, for the periods and as of the dates
indicated, selected historical financial and operating data for Heritage Propane
Partners, L.P. and its subsidiaries. Information presented represents financial
and operating data prior to and following the transactions with U.S. Propane and
Peoples Gas that occurred in August 2000 and is described in detail in our
Annual Report on Form 10-K for the fiscal year ended August 31, 2003. Although
Heritage Propane Partners was the surviving entity for legal purposes in this
transaction, Peoples Gas was the accounting acquiror. The years ended December
31, 1998 and 1999, and the eight-month period ended August 31, 1999 reflect the
results of Peoples Gas on a stand-alone basis. The eight-month period ended
August 31, 2000 was treated as a transition period, and represents seven months
of Peoples Gas stand-alone and one month of Heritage Propane Partners. The years
ended August 31, 2001, 2002 and 2003 reflect the results of Heritage Propane
Partners following the transactions with U.S. Propane. This selected historical
financial and operating data should be read in conjunction with the financial
statements of Heritage Propane Partners, L.P. included in our Annual Report on
Form 10-K for the fiscal year ended August 31, 2003, which is incorporated by
reference in this prospectus supplement, and "Management's Discussion and
Analysis of Financial Condition and Results of Operations" included elsewhere in
this prospectus supplement.
<Table>
<Caption>
YEARS ENDED EIGHT MONTHS
DECEMBER 31, ENDED AUGUST 31, YEARS ENDED AUGUST 31,
------------------- ---------------------- ------------------------------
1998 1999 1999 2000 2001 2002 2003
-------- -------- ----------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER UNIT
(UNAUDITED) AMOUNTS)
STATEMENTS OF OPERATING DATA:
Revenues............................... $ 30,187 $ 34,045 $ 21,766 $ 51,534 $543,975 $462,325 $571,476
Gross profit(a)........................ 17,904 19,196 13,299 21,572 237,419 224,140 274,320
Depreciation and amortization.......... 2,855 3,088 2,037 4,686 40,431 36,998 37,959
Operating income (loss)................ 3,961 2,885 2,666 (714) 54,423 40,961 70,193
Interest expense....................... -- -- -- 2,409 35,567 37,341 35,740
Income (loss) before income taxes and
minority interests................... 3,483 2,895 2,677 (3,547) 20,524 5,476 33,041
Provision for income taxes............. 1,412 1,127 1,035 379 -- -- 1,023
Net income (loss)...................... 2,071 1,768 1,642 (3,846) 19,710 4,902 31,142
Basic net income (loss) per unit(b).... 1.19 1.02 0.94 (0.37) 1.43 0.25 1.79
Cash dividends/distributions per
unit................................. 1.13 1.30 1.30 0.87 2.38 2.55 2.60
BALANCE SHEET DATA (AT PERIOD END):
Current assets......................... $ 4,310 $ 6,643 $ 4,326 $ 84,869 $138,263 $ 95,387 $ 94,138
Total assets........................... 37,206 43,724 39,481 615,779 758,167 717,264 738,839
Current liabilities.................... 13,671 19,636 15,716 102,212 127,655 122,069 151,027
Long-term debt......................... -- -- -- 361,990 423,748 420,021 360,762
Minority interests..................... -- -- -- 4,821 5,350 3,564 4,002
Total partners' capital................ 15,596 15,107 14,981 146,756 201,414 171,610 223,048
OTHER FINANCIAL AND OPERATING DATA
(UNAUDITED):
EBITDA, as adjusted(c)................. $ 6,816 $ 5,973 $ 4,703 $ 4,507 97,444 81,536 110,963
Cash flows from operating activities... 9,219 9,353 -- 14,508 28,056 65,453 95,199
Cash flows used in investing
activities........................... (7,047) (7,191) -- (183,037) (122,313) (33,412) (48,389)
Cash flows from (used in) financing
activities........................... (2,317) (2,257) -- 173,353 95,038 (33,071) (44,289)
Capital expenditures(d)
Maintenance.......................... 5,328 6,176 2,544 3,559 8,504 12,831 15,136
Growth and acquisition............... 1,719 1,015 1,015 177,067 110,210 33,983 37,114
Retail gallons sold.................... 30,921 33,608 22,118 38,268 330,242 329,574 375,939
</Table>
- ---------------
(a) Gross profit is computed by reducing total revenues by the direct cost of
the products sold.
S-26
(b) Net income per unit is computed by dividing the limited partner's interest
in net income by the weighted average number of units outstanding.
(c) EBITDA, as adjusted is defined as our earnings before interest, taxes,
depreciation, amortization and other non-cash items, such as compensation
charges for unit issuances to employees, gain or loss on disposal of
assets, and other expenses. We present EBITDA, as adjusted, on a
partnership basis which includes both the general and limited partner
interests. Non-cash compensation expense represents charges for the value
of the common units awarded under our compensation plans that have not yet
vested under the terms of those plans and are charges which do not, or will
not, require cash settlement. Non-cash income such as the gain arising from
our disposal of assets is not included when determining EBITDA, as
adjusted. EBITDA, as adjusted (i) is not a measure of performance
calculated in accordance with GAAP and (ii) should not be considered in
isolation or as a substitute for net income, income from operations or cash
flow as reflected in our consolidated financial statements.
EBITDA, as adjusted is presented because such information is relevant and
is used by management, industry analysts, investors, lenders and rating
agencies to assess the financial performance and operating results of our
fundamental business activities. Management believes that the presentation
of EBITDA, as adjusted is useful to lenders and investors because of its
use in the propane industry and for master limited partnerships as an
indicator of the strength and performance of our ongoing business
operations, including the ability to fund capital expenditures, service
debt and pay distributions. Additionally, management believes that EBITDA,
as adjusted provides additional and useful information to our investors for
trending, analyzing and benchmarking our operating results from period to
period as compared to other companies that may have different financing and
capital structures. The presentation of EBITDA, as adjusted allows
investors to view our performance in a manner similar to the methods used
by management and provides additional insight to our operating results.
EBITDA, as adjusted is used by management to determine our operating
performance, and along with other data as internal measures for setting
annual operating budgets, assessing financial performance of our numerous
business locations, as a measure for evaluating targeted businesses for
acquisition and as a measurement component of incentive compensation. We
have a large number of business locations located in different regions of
the United States. EBITDA, as adjusted can be a meaningful measure of
financial performance because it excludes factors which are outside the
control of the employees responsible for operating and managing the
business locations, and provides information management can use to evaluate
the performance of the business locations, or the region where they are
located, and the employees responsible for operating them. To present
EBITDA, as adjusted on a full partnership basis, we add back the minority
interest of the general partner because net income is reported net of the
general partner's minority interest. Our EBITDA, as adjusted includes
non-cash compensation expense which is a non-cash expense item resulting
from our unit based compensation plans that does not require cash
settlement and is not considered during management's assessment of the
operating results of our business. Adding these non-cash compensation
expenses in EBITDA, as adjusted allows management to compare our operating
results to those of other companies in the same industry who may have
compensation plans with levels and values of annual grants that are
different than us. Other expenses include other finance charges and other
asset non-cash impairment charges that are reflected in our operating
results but are not classified in interest, depreciation and amortization.
We do not include gain on the sale of assets when determining EBITDA, as
adjusted since including non-cash income resulting from the sale of assets
increases the performance measure in a manner that is not related to the
true operating results of our business. In addition, our debt agreements
contain financial covenants based on EBITDA, as adjusted. For a description
of these covenants, please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Description of
Indebtedness."
There are material limitations to using a measure such as EBITDA, as
adjusted, including the difficulty associated with using it as the sole
measure to compare the results of one company to
S-27
another, and the inability to analyze certain significant items that
directly affect a company's net income or loss. In addition, our
calculation of EBITDA, as adjusted may not be consistent with similarly
titled measures of other companies and should be viewed in conjunction with
measurements that are computed in accordance with GAAP. EBITDA, as adjusted
for the periods described herein is calculated in the same manner as
presented by us in the past. Management compensates for these limitations
by considering EBITDA, as adjusted in conjunction with its analysis of
other GAAP financial measures, such as gross profit, net income (loss), and
cash flow from operating activities. A reconciliation of EBITDA, as
adjusted to net income (loss) is presented below. Please read
"-- Reconciliation of EBITDA, As Adjusted to Net Income" below.
RECONCILIATION OF EBITDA, AS ADJUSTED, TO NET INCOME
The following tables set forth the reconciliation of EBITDA, as adjusted,
to our net income for the periods indicated:
<Table>
<Caption>
YEARS ENDED EIGHT MONTHS ENDED
DECEMBER 31, AUGUST 31, YEARS ENDED AUGUST 31,
--------------- ------------------ ----------------------------
1998 1999 1999 2000 2001 2002 2003
------ ------ ------- -------- ------- ------- --------
(IN THOUSANDS)
NET INCOME RECONCILIATION
Net income (loss).............. $2,071 $1,768 $1,642 $(3,846) $19,710 $ 4,902 $ 31,142
Depreciation and
amortization................. 2,855 3,088 2,037 4,686 40,431 36,998 37,959
Interest....................... -- -- -- 2,409 35,567 37,341 35,740
Taxes.......................... 1,412 1,127 1,035 379 -- -- 1,023
Non-cash compensation
expense...................... -- -- -- 549 1,079 1,878 1,159
Other expenses................. 478 (10) (11) 478 394 294 3,213
Depreciation, amortization, and
interest and taxes of
investee..................... -- -- -- 73 792 743 901
Minority interest in the
Operating Partnership........ -- -- -- (100) 283 192 256
Less: Gain on disposal of
assets....................... -- -- -- (121) (812) (812) (430)
------ ------ ------ ------- ------- ------- --------
EBITDA, as adjusted............ $6,816 $5,973 $4,703 $ 4,507 $97,444 $81,536 $110,963
====== ====== ====== ======= ======= ======= ========
</Table>
(d) Capital expenditures fall generally into three categories: (1) maintenance
capital expenditures, which include expenditures for repairs that extend
the life of the assets and replacement of property, plant and equipment,
(2) growth capital expenditures, which include expenditures for purchase of
new propane tanks and other equipment to facilitate retail customer base
expansion, and (3) acquisition expenditures which include expenditures
related to the acquisition of retail propane operations and other business,
and the portion of the purchase price allocated to intangibles associated
with such acquired businesses.
S-28
ENERGY TRANSFER SELECTED HISTORICAL
FINANCIAL DATA
Although Heritage Propane Partners, L.P. will be the surviving parent
entity for legal purposes, Energy Transfer will be the accounting acquiror. As a
result, following the Energy Transfer transaction, our historical financial
statements for periods prior to the closing of the transaction will be the
historical financial statements of Energy Transfer. Energy Transfer was formed
on October 1, 2002 and will have an August 31 year-end. Energy Transfer's
predecessor entities had a December 31 year-end. Accordingly, Energy Transfer's
11-month period ended August 31, 2003 will be treated as a transition period.
Energy Transfer's historical financial information for the period from
October 1, 2002 to August 31, 2003 has been derived from the historical
financial statements of Energy Transfer included elsewhere in this prospectus
supplement. During this time period, Energy Transfer owned the Southeast Texas
System and the Elk City System. From October 1, 2002 through December 27, 2002,
Energy Transfer also owned a 50% equity interest in Oasis Pipe Line Company,
which owns the Oasis Pipeline. After December 27, 2002, Energy Transfer owned a
100% interest in Oasis Pipe Line. In addition, on December 27, 2002, an
affiliate of La Grange Energy's general partner contributed to Energy Transfer
its marketing business and the Vantex System, the Rusk County Gathering System,
the Whiskey Bay System and the Chalkley Transmission System.
Energy Transfer's historical financial information for periods prior to
October 1, 2002 has been derived from the historical financial statements of
Aquila Gas Pipeline. Prior to October 1, 2002, Aquila Gas Pipeline owned the
Southeast Texas System, the Elk City System and a 50% equity interest in Oasis
Pipe Line. All of these assets were acquired by Energy Transfer on October 1,
2002.
The financial information below for Aquila Gas Pipeline for the 9 months
ended September 30, 2002 and the years ended December 31, 2001 and 2000 and as
of September 30, 2002 and December 31, 2001 has been derived from the audited
consolidated financial statements of Aquila Gas Pipeline included elsewhere in
this prospectus supplement. The financial information below for Aquila Gas
Pipeline for the years ended December 31, 1999 and 1998 and as of December 31,
2000, 1999 and 1998 has been derived from unaudited consolidated financial
statements of Aquila Gas Pipeline, which are not included in this prospectus
supplement.
The selected historical financial data should be read in conjunction with
the financial statements of Energy Transfer and Aquila Gas Pipeline included
elsewhere in this prospectus supplement and with "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
S-29
<Table>
<Caption>
ENERGY
AQUILA GAS PIPELINE TRANSFER
------------------------------------------------------------------- -------------
NINE MONTHS ELEVEN MONTHS
YEAR ENDED DECEMBER 31, ENDED ENDED
--------------------------------------------------- SEPTEMBER 30, AUGUST 31,
1998 1999 2000 2001 2002 2003(A)
----------- ----------- ---------- ---------- ------------- -------------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS)
STATEMENT OF OPERATIONS DATA:
Revenues
Midstream segment.................... $902,045 $1,030,554 $1,758,530 $1,813,850 $933,099 $ 978,106(b)
Transportation segment............... -- -- -- -- -- 30,617
-------- ---------- ---------- ---------- -------- ----------
Total revenues................... 902,045 1,030,554 1,758,530 1,813,850 933,099 1,008,723
Gross profit........................... 80,631 94,109 117,663 98,589 53,035 109,184
Depreciation and amortization.......... 26,417 27,061 30,049 30,779 22,915 13,461
Operating income....................... 16,596 30,795 31,024 42,990 2,862 61,589
Interest expense....................... 14,125 12,894 12,098 6,858 3,931 12,057
Income before income taxes............. 3,711 17,502 18,892 41,161 4,272 51,057
Provision for income taxes............. (1,157) 5,913 7,657 15,403 (467) 4,432(c)
Net income............................. 4,868 11,589 11,235 25,758 4,739 46,625
BALANCE SHEET DATA (AT PERIOD END):
Current assets......................... 109,286 108,552 231,260 144,396 116,831 183,770(d)
Total assets........................... 632,112 620,920 724,161 633,260 601,528 600,693
Current liabilities.................... 133,299 160,419 313,506 194,816 144,076 168,063
Long-term debt, including current
maturities........................... 197,450 163,273 110,721 78,750 66,250 226,000
Stockholders' equity/Partners'
equity............................... 226,755 237,877 254,248 249,520 254,259 181,088
OTHER FINANCIAL DATA:
Cash flow from operating activities.... 45,709 43,182 76,011 65,198 12,987 70,916
Cash flow used in investing
activities........................... (20,755) (13,785) (23,459) (20,727) (487) (341,177)
Cash flow from (used in) financing
activities........................... (28,109) (34,544) (52,552) (44,471) (12,500) 323,383
</Table>
- ---------------
(a) On December 27, 2002, Energy Transfer purchased the remaining 50% of Oasis
Pipe Line. Prior to December 27, 2002, the interest in Oasis Pipe Line was
treated as an equity method investment. After this date, Oasis Pipe Line's
results of operations are consolidated with Energy Transfer as a wholly-
owned subsidiary.
(b) For purposes of this presentation, the elimination of intersegment revenues
of $10.5 million has been classified as a reduction of the midstream
segment's revenues for the 11 months ended August 31, 2003.
(c) As a partnership, Energy Transfer is not subject to income taxes. However,
its subsidiary, Oasis Pipe Line, is a corporation that is subject to income
taxes at an effective rate of 35%. As a result, all income tax expense for
Energy Transfer for the 11 months ended August 31, 2003 is directly related
to Oasis Pipe Line. Prior to 2003, Oasis Pipe Line was an equity method
investment of Energy Transfer, and taxes were netted against the equity
method earnings. Aquila Gas Pipeline was a tax paying corporation, and as
such recognized income taxes related to its earnings in all periods
presented.
(d) Prior to the closing of the Energy Transfer transaction, Energy Transfer
will distribute its cash and cash equivalents and accounts receivable to La
Grange Energy. Cash and cash equivalents and accounts receivable were $159.1
million as of August 31, 2003.
S-30
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion of our financial condition and
results of operations in conjunction with the historical and pro forma combined
financial statements and notes thereto included elsewhere in this prospectus
supplement. For more detailed information regarding the basis of presentation
for the following information, you should read the notes to the historical and
pro forma financial statements included in this prospectus supplement.
OVERVIEW
HERITAGE PROPANE PARTNERS
We are one of the largest retail propane marketers in the United States,
serving more than 650,000 customers from over 300 customer service locations in
31 states. Our operations extend from coast to coast, with concentrations in the
western, upper midwestern, northeastern and southeastern regions of the United
States. We are also a wholesale propane supplier in the southwestern and
southeastern United States and in Canada, the latter through participation in
M-P Energy Partnership. M-P Energy Partnership is a Canadian partnership in
which we own a 60% interest, engaged in wholesale distribution and in supplying
our northern U.S. locations. We are a publicly traded Delaware limited
partnership formed in conjunction with our initial public offering in June of
1996. Our business has grown primarily through acquisitions of retail propane
operations and, to a lesser extent, through internal growth. Since our inception
through August 31, 2003, we have completed 97 acquisitions for an aggregate
purchase price of approximately $675 million. Volumes of propane sold to retail
customers have increased steadily from 63.2 million gallons for the fiscal year
ended August 31, 1992 to 375.9 million gallons for the fiscal year ended August
31, 2003.
The retail propane business is a "margin-based" business in which gross
profits depend on the excess of sales price over propane supply costs. The
market price of propane is often subject to volatile changes as a result of
supply or other market conditions over which we will have no control. Product
supply contracts are typically one-year agreements subject to annual renewal and
generally provide for pricing in accordance with posted prices at the time of
delivery or the current prices established at major delivery or storage points.
In addition, some contracts include a pricing formula that typically is based on
these market prices. Most of these agreements provide maximum and minimum
seasonal purchase guidelines. The number of contracts entered into may vary from
year to year. Since rapid increases in the wholesale cost of propane may not be
immediately passed on to retail customers, such increases could reduce gross
profits. We generally have attempted to reduce price risk by purchasing propane
on a short-term basis. We have on occasion purchased significant volumes of
propane during periods of low demand, which generally occur during the summer
months, at the then current market price, for storage both at our customer
service locations and in major storage facilities for future resale.
Our retail propane business consists principally of transporting propane
purchased in the contract and spot markets, primarily from major fuel suppliers,
to our customer service locations and then to tanks located on the customers'
premises, as well as to portable propane cylinders. In the residential and
commercial markets, propane is primarily used for space heating, water heating
and cooking. In the agricultural market, propane is primarily used for crop
drying, tobacco curing, poultry brooding and weed control. In addition, propane
is used for certain industrial applications, including use as an engine fuel for
internal combustion engines that power vehicles and forklifts and as a heating
source in manufacturing and mining processes.
Our propane distribution business is largely seasonal and dependent upon
weather conditions in our service areas. Propane sales to residential and
commercial customers are affected by winter heating season requirements.
Historically, approximately two-thirds of our retail propane volume and in
excess of 80% of our EBITDA is attributable to sales during the six-month
peak-heating season of October through March. This generally results in higher
operating revenues and net income during the period from October through March
of each year and lower operating revenues, and in some cases, net losses or
lower net income
S-31
during the period from April through September of each year. Consequently, sales
and operating profits are concentrated in the first and second fiscal quarters,
while cash flow from operations is generally greatest during the second and
third fiscal quarters when customers pay for propane purchased during the
six-month peak-heating season. Sales to industrial and agricultural customers
are much less weather sensitive.
A substantial portion of our propane is used in the heating-sensitive
residential and commercial markets resulting in the temperatures realized in our
areas of operations, particularly during the six-month peak-heating season,
having a significant effect on our financial performance. In any given area,
sustained warmer-than-normal temperatures will tend to result in reduced propane
use, while sustained colder-than-normal temperatures will tend to result in
greater propane use. We use information based on normal temperatures in
understanding how temperatures that are colder or warmer than normal affect
historical results of operations and in preparing forecasts of future
operations.
Gross profit margins are not only affected by weather patterns, but also
vary according to customer mix. For example, sales to residential customers
generate higher margins than sales to certain other customer groups, such as
commercial or agricultural customers. Wholesale margins are substantially lower
than retail margins. In addition, gross profit margins vary by geographical
region. Accordingly, a change in customer or geographic mix can affect gross
profit without necessarily affecting total revenues.
THE ENERGY TRANSFER TRANSACTION
On November 7, 2003, we publicly announced the signing of definitive
agreements to combine our operations with those of La Grange Energy, which is
engaged in the midstream natural gas business. La Grange Energy conducts its
midstream operations through La Grange Acquisition, whose midstream operations
are conducted under the name Energy Transfer Company. As part of the
transactions, La Grange Energy has agreed to acquire our general partner. La
Grange Energy is owned by Natural Gas Partners VI, L.P., a private equity fund,
Ray C. Davis, Kelcy L. Warren and a group of institutional investors.
In connection with the transaction, La Grange Energy will contribute
interests in Energy Transfer and certain related assets to us in exchange for:
- $300 million in cash, subject to certain adjustments including (1) a
reduction for any accounts payable and other specified liabilities of
Energy Transfer at closing, (2) a reduction to the extent that the
long-term debt of Energy Transfer at closing is greater than $151.5
million, (3) an increase to the extent that the long-term debt of Energy
Transfer at closing is less than $151.5 million and (4) an increase by up
to $80 million to reimburse La Grange Energy for certain mutually agreed
upon capital expenditures paid by La Grange Energy to third parties prior
to the closing, and
- the retirement at closing of Energy Transfer's debt;
- the assumption at closing of Energy Transfer's accounts payable and other
specified liabilities;
- 15,883,234 units, comprising limited partner interests in us. The units
will be comprised of the following:
-- a number of common units totaling 19.99% of the number of common units
of us outstanding immediately prior to the closing (excluding the
4,426,916 common units held by Heritage Holdings) after giving effect
to the offering, which we have assumed will be 4,118,162;
-- a number of class D units that will equal the difference between
12,140,719 and the number of common units issued to La Grange Energy in
the transaction, which we have assumed will be 8,022,557; and
-- 3,742,515 special units.
Please read "Description of Units -- Class D Units" and "-- Special Units" for a
more detailed description of our class D units and special units.
S-32
In conjunction with this transaction, Energy Transfer will distribute its
cash and accounts receivable to La Grange Energy, and an affiliate of La Grange
Energy will contribute an office building to Energy Transfer, in each case prior
to the contribution of Energy Transfer to us.
The amounts necessary to pay the cash portion of the purchase price, retire
Energy Transfer's credit facilities, satisfy Energy Transfer's accounts payable
and other specified liabilities and to fund the expenses associated with the
Energy Transfer transaction will be raised from the proceeds of this offering
and borrowings under the new Energy Transfer credit facility.
Please read "-- Liquidity and Capital Resources -- Financing and Sources of
Liquidity -- Energy Transfer Facilities."
As a part of the above transaction, La Grange Energy has agreed to purchase
all of the partnership interests of U.S. Propane, L.P., our general partner, and
all of the member interests of U.S. Propane, L.L.C., the general partner of U.S.
Propane, L.P. (which are collectively referred to as our "general partner"),
from subsidiaries of AGL Resources, Inc., Atmos Energy Corporation, TECO Energy,
Inc. and Piedmont Natural Gas Company, Inc. (the "Previous Owners") for $30
million in cash. Prior to the sale of our general partner to La Grange Energy,
certain assets of our general partner, including all of the stock of Heritage
Holdings and 180,028 common units, will be distributed by our general partner to
an affiliate of the Previous Owners. Currently, U.S. Propane, L.P. owns a 1%
general partner interest in us and a 1.01% general partner interest in our
operating partnership, Heritage Operating, L.P. As part of the acquisition of
our general partner, U.S. Propane, L.P. will make a capital contribution of its
interest in the operating partnership to us in exchange for an additional 1%
general partner interest in us, such that following the capital contribution,
U.S. Propane, L.P. will own a 2% general partner interest in us.
Also in conjunction with these transactions, we will acquire from this
affiliate of the Previous Owners all of the stock of Heritage Holdings, which
owns approximately 4,426,916 common units, for $50 million in cash and a $50
million two-year promissory note secured by a pledge of the units held by
Heritage Holdings. In addition, we will inherit approximately $104.7 million in
liabilities of Heritage Holdings. Substantially all of these liabilities are
deferred tax liabilities arising from differences in the book and tax basis of
Heritage Holdings' assets. After our purchase of Heritage Holdings, the common
units owned by Heritage Holdings will be converted into class E units. Please
read "Description of Units" for a description of the class E units.
In connection with these transactions, La Grange Energy and its affiliates,
including Ray C. Davis and Kelcy L. Warren, will agree not to engage, invest or
participate, directly or indirectly, in any business activities involving (a)
the purchase, sale, exchange, marketing, trading, storage or transportation of
propane or (b) the purchase, gathering, treating, processing, marketing, sales,
storage, transportation, fractionation or distribution of natural gas and NGLs,
subject to certain limited exceptions. Each of La Grange Energy and its
affiliates will agree not to engage in these activities until the earlier of (i)
the third anniversary of the closing of the Energy Transfer transaction or (ii)
the date such party ceases to be engaged in the business of Heritage or the
business of Energy Transfer as an owner, officer, director or employee, as the
case may be.
Also in connection with the transactions, the Previous Owners will agree
not to engage, invest or participate, directly or indirectly, in any business
activities involving the purchase, sale, exchange, marketing, trading, storage
or transportation of propane, subject to certain limited exceptions, until the
third anniversary of the closing of the acquisition of Energy Transfer.
We have previously entered into employment agreements with our executive
officers, H. Michael Krimbill, R.C. Mills, Michael L. Greenwood, Bradley K.
Atkinson, Mark A. Darr, Thomas H. Rose and Curtis L. Weishahn. The consummation
of the Energy Transfer transaction will be a "change of control" under these
employment agreements. As a result, upon the consummation of the Energy Transfer
transaction, we will be obligated to make a cash payment to each of our
executive officers in an amount equal to their base salary and will also be
required to make a bonus payment in common units to each of our executive
officers. We expect that the aggregate cash payment will be approximately $1.6
million and
S-33
that the aggregate bonus payment will equal 150,018 common units. Each
employment agreement also provides that if any payment received by the executive
officer is subject to the 20% federal excise tax under Section 4999(a) of the
Internal Revenue Code, the payment will be grossed up to permit the executive
officer to retain a net amount on an after-tax basis equal to what he would have
received had the excise tax and all other federal and state taxes on such
additional amount not been payable. In addition, pursuant to the terms of the
employment agreement of Michael L. Greenwood, 20,000 common units to which he is
entitled will be awarded.
In addition, the consummation of the Energy Transfer transaction will be a
"change of control" under our Second Amended and Restated Restricted Unit Plan.
As a result, all rights to acquire common units pursuant to the Restricted Unit
Plan will immediately vest. As of December 31, 2003, unvested rights to acquire
26,100 common units were outstanding under the Restricted Unit Plan. Of these
unvested rights, rights to acquire 4,500 common units were held by non-employee
directors and rights to acquire 21,600 common units were held by employees that
are not executive officers.
Each of these employment agreements and the Restricted Unit Plan is
described in more detail in our Annual Report on Form 10-K for the fiscal year
ended August 31, 2003.
ENERGY TRANSFER
Energy Transfer is a Texas limited partnership formed in September 2002 to
own, operate and acquire midstream assets from Aquila Gas Pipeline, an affiliate
of Aquila, Inc. Energy Transfer's operations are concentrated in the Austin
Chalk trend of southeast Texas, the Anadarko Basin of western Oklahoma and the
Permian Basin of west Texas. It divides its operations into the following two
business segments:
- Midstream Segment, which focuses on the gathering, compression, treating,
processing and marketing of natural gas, primarily in the Southeast Texas
System and the Elk City System. For the 11 months ended August 31, 2003,
approximately 72% of Energy Transfer's gross margin was derived from this
segment.
- Transportation Segment, which focuses on the transportation of natural
gas through the Oasis Pipeline. For the 11 months ended August 31, 2003,
approximately 28% of Energy Transfer's gross margin was derived from this
segment.
During the 11 months ended August 31, 2003, Energy Transfer generated
approximately 46% of its gross margin from fees it charged for providing its
services, including a transportation fee it charges the producer services
business for natural gas that the producer service business transports on the
Oasis Pipeline equal to the fee it charges third parties. This transportation
fee accounted for 7% of its total gross margin for this period. Energy Transfer
generated the remaining 54% of its gross margin from discount-to-index,
percentage-of-proceeds and keep-whole arrangements and from its producer
services business. We intend to seek to increase the percentage of Energy
Transfer's business conducted under fee-based arrangements in order to reduce
our exposure to increases and decreases in the price of natural gas and NGLs.
However, in order to remain competitive, Energy Transfer will need to offer
other contractual arrangements to attract certain natural gas supplies to its
systems.
The Midstream Segment
Results from the Midstream segment are determined primarily by the volumes
of natural gas gathered, compressed, treated, processed, purchased and sold
through Energy Transfer's pipeline and gathering systems and the level of
natural gas and NGL prices. Energy Transfer generates its revenues and its gross
margins principally under the following types of arrangements:
Fee-based arrangements. Under fee-based arrangements, Energy Transfer
receives a fee or fees for one or more of the following services: gathering,
compressing, treating or processing natural gas. The revenue it earns from these
arrangements is directly related to the volume of natural gas that flows through
its systems and is not directly dependent on commodity prices. To the extent a
sustained decline in
S-34
commodity prices results in a decline in volumes, however, its revenues from
these arrangements would be reduced.
Other arrangements. Energy Transfer also utilizes other types of
arrangements in its Midstream segment, including:
- Discount-to-index price arrangements. Under discount-to-index price
arrangements, Energy Transfer generally purchases natural gas at either
(1) a percentage discount to a specified index price, (2) a specified
index price less a fixed amount or (3) a percentage discount to a
specified index price less an additional fixed amount. It then gathers
and delivers the natural gas to pipelines where it resells the natural
gas at the index price. The gross margins Energy Transfer realizes under
the arrangements described in clauses (1) and (3) above decrease in
periods of low natural gas prices because these gross margins are based
on a percentage of the index price.
- Percentage-of-proceeds arrangements. Under percentage-of-proceeds
arrangements, Energy Transfer generally gathers and processes natural gas
on behalf of producers, sells the resulting residue gas and NGL volumes
at market prices and remits to producers an agreed upon percentage of the
proceeds based on an index price. In other cases, instead of remitting
cash payments to the producer, Energy Transfer delivers an agreed upon
percentage of the residue gas and NGL volumes to the producer and sells
the volumes it keeps to third parties at market prices. Under these types
of arrangements, Energy Transfer's revenues and gross margins increase as
natural gas prices and NGL prices increase, and its revenues and gross
margins decrease as natural gas prices and NGL prices decrease.
- Keep-whole arrangements. Under keep-whole arrangements, Energy Transfer
gathers natural gas from the producer, processes the natural gas and
sells the resulting NGLs to third parties at market prices. Because the
extraction of the NGLs from the natural gas during processing reduces the
Btu content of the natural gas, Energy Transfer must either purchase
natural gas at market prices for return to producers or make a cash
payment to the producers equal to the value of this natural gas.
Accordingly, under these arrangements, Energy Transfer's revenues and
gross margins increase as the price of NGLs increases relative to the
price of natural gas, and its revenues and gross margins decrease as the
price of natural gas increases relative to the price of NGLs. In the
latter case, Energy Transfer is generally able to reduce its commodity
price exposure by bypassing its processing plants and not processing the
natural gas, as described below.
In many cases, Energy Transfer provides services under contracts that
contain a combination of more than one of the arrangements described above. The
terms of its contracts vary based on gas quality conditions, the competitive
environment at the time the contracts are signed and customer requirements. Its
contract mix and, accordingly, its exposure to natural gas and NGL prices, may
change as a result of changes in producer preferences, its expansion in regions
where some types of contracts are more common and other market factors.
A significant benefit of Energy Transfer's ownership of the Oasis Pipeline
is that Energy Transfer typically can elect not to process the natural gas at
the La Grange processing plant when processing margins are unfavorable. Instead
of processing the natural gas, Energy Transfer is able to bypass the La Grange
processing plant and deliver natural gas meeting pipeline quality specifications
by blending rich natural gas from the Southeast Texas System with lean natural
gas transported on the Oasis pipeline.
Energy Transfer can also generally bypass the Elk City processing plant.
The natural gas supplied to the Elk City System has a relatively low NGL content
and does not require processing to meet pipeline quality specifications. During
periods of unfavorable processing margins, Energy Transfer can bypass the Elk
City processing plant and deliver the natural gas directly into connecting
pipelines.
Both the Southeast Texas System and Elk City System are geographically
located in natural gas producing areas that had large production volumes in the
past several decades, and these systems were built to accommodate those larger
volumes. Both of these producing areas have matured in recent years, and
production has declined over time. As a result, utilization of these systems has
also declined. At the
S-35
time of Energy Transfer's acquisition of the Southeast Texas System and the Elk
City System, both of these systems were not being fully utilized. By
aggressively marketing directly to producers and consumers and adding
connections to new customers, during 2003, Energy Transfer has increased the
utilization of the Southeast Texas System and the Elk City System by
approximately 30% and 50%, respectively. Energy Transfer believes that it has
the opportunity to further leverage its existing asset base in order to more
fully utilize the capacity of its systems and thereby increase throughput and
cash flows. Generally, adding additional volumes to the Southeast Texas System's
and the Elk City System's pipelines requires only minimal incremental capital
expenditures. As a result, transporting additional volumes of natural gas
through these pipelines generally provides incremental operating income without
the need for additional capital.
Energy Transfer believes that it is more cost effective to install a
pipeline with throughput capacity in excess of the natural gas production that
is initially contracted for transportation on the pipeline. The capacity of a
six-inch pipeline is more than double that of a four inch pipeline, yet the
costs of construction are substantially less than double. In addition, the costs
to operate and maintain the larger pipeline are generally no greater than the
costs to operate and maintain the smaller pipeline.
However, Energy Transfer has a different approach to the construction and
operation of processing and treating plants. Unutilized capacity in processing
and treating facilities negatively impacts the per unit profitability of these
facilities. Energy Transfer seeks to maximize throughput of its plants at both
the time of installation and subsequently as production declines, by idling
underutilized plants and aggregating its processing and treating operations at
more efficient facilities to minimize the per unit cost of those plants. Idle or
unused facilities can be relocated to other parts of Energy Transfer's systems
if necessary or sold to third parties. Because aggregation can result in higher
capital costs, the decision by Energy Transfer to idle a plant and aggregate
processing and treating operations at a more efficient facility is made only
when management believes that the per unit cost reduction justifies the capital
expenditure. For the eleven months ended August 31, 2003, Energy Transfer's
utilization of capacity at its Southeast Texas System processing and treating
facilities were 40% and 32% respectively. For the reasons discussed above, this
excess capacity negatively affected Energy Transfer's profitability that was
reflected in its historical numbers. A portion of the excess capacity at the
Southeast Texas System processing facility was directly attributable to its
election to not process or treat natural gas and deliver the natural gas
directly into the Oasis Pipeline in order to take advantage of high natural gas
prices relative to NGL prices. Additionally, in September 2003, Energy Transfer
enhanced its utilization by moving an idle 145 MMcf/d treating facility from the
Southeast Texas System to the Elk City System to take advantage of additional
natural gas volumes.
Energy Transfer conducts its marketing operations through its producer
services business, in which Energy Transfer markets the natural gas that flows
through its assets, which Energy Transfer refers to as on-system gas, and
attracts other customers by marketing volumes of natural gas that do not move
through its assets, which Energy Transfer refers to as off-system gas. For both
on-system and off-system gas, Energy Transfer purchases natural gas from natural
gas producers and other supply points and sells that natural gas to utilities,
industrial consumers, other marketers and pipeline companies, thereby generating
gross margins based upon the difference between the purchase and resale prices.
Most of Energy Transfer's marketing activities involve the marketing of its
on-system gas. For the 11 months ended August 31, 2003, Energy Transfer marketed
approximately 524 MMcf/d of natural gas, 86% of which was on-system gas.
Substantially all of its on-system marketing efforts involve natural gas that
flows through either the Southeast Texas System or the Oasis Pipeline. Energy
Transfer markets only a small amount of natural gas that flows through the Elk
City System.
For its off-system gas, Energy Transfer purchases gas or acts as an agent
for small independent producers that do not have marketing operations. Energy
Transfer develops relationships with natural gas producers which facilitates its
purchase of their production on a long-term basis. Energy Transfer believes that
this business provides it with strategic insights and valuable market
intelligence which may impact its expansion and acquisition strategy.
S-36
The Transportation Segment
Results from Energy Transfer's Transportation segment are determined
primarily by the amount of capacity Energy Transfer's customers reserve as well
as the actual volume of natural gas that flows through the Oasis Pipeline. Under
Oasis Pipeline customer contracts, Energy Transfer charges its customers a
demand fee, a transportation fee, or a combination of both, generally payable
monthly.
- Demand Fee. The demand fee is a fixed fee for the reservation of an
agreed amount of capacity on the Oasis Pipeline for a specified period of
time. The customer is obligated to pay Energy Transfer the demand fee
even if the customer does not transport natural gas on the Oasis
Pipeline.
- Transportation Fee. The transportation fee is based on the actual
throughput of natural gas by the customer on the Oasis Pipeline.
For the 11 months ended August 31, 2003, Energy Transfer transported
approximately 30% of its natural gas volumes on the Oasis Pipeline pursuant to
long-term contracts. Its long-term contracts have a term of one year or more.
Energy Transfer also enters into short-term contracts with terms of less than
one year in order to utilize the capacity that is available on the Oasis
Pipeline after taking into account the capacity reserved under Energy Transfer's
long-term contracts. For the 11 months ended August 31, 2003, the Oasis Pipeline
accounted for approximately 57% of Energy Transfer's fee-based gross margin.
Operating Expenses and Administrative Costs
Energy Transfer realizes significant economies of scale related to the
Midstream segment as well as the Transportation segment. As additional volumes
of natural gas move through Energy Transfer's systems, its incremental operating
and administrative costs do not increase materially. Operating expenses are
costs directly associated with the operations of a particular asset and include
direct labor and supervision, property insurance, ad valorem taxes, repair and
maintenance expenses, measurement and utilities. These costs are generally fixed
across broad volume ranges. Energy Transfer's fuel expense to operate its
pipelines and plants is more variable in nature and is sensitive to changes in
volume and commodity prices.
Effects of Changes in Commodity Price
Energy Transfer's profitability is affected by volatility in prevailing NGL
and natural gas prices. Historically, changes in the prices of most NGL products
have generally correlated with changes in the price of crude oil. NGL and
natural gas prices have been subject to significant volatility in recent years
in response to changes in the supply and demand for NGL products and natural gas
market uncertainty. For a discussion of the volatility of natural gas and NGL
prices, please read "Risk Factors -- Energy Transfer's profitability is
dependent upon prices and market demand for natural gas and NGLs, which are
beyond its control and have been volatile." The current mix of Energy Transfer's
contractual arrangements described above together with its ability to bypass the
processing plants significantly mitigates its exposure to the volatility of
natural gas and NGL prices. Gas prices can also affect Energy Transfer's
profitability indirectly by influencing drilling activity and related
opportunities for natural gas gathering, compression, treating, processing,
transportation and marketing.
Significant Acquisitions
Energy Transfer acquired most of its assets in two strategic acquisitions.
In October 2002, Energy Transfer acquired the Southeast Texas System, the Elk
City System and a 50% equity interest in the Oasis Pipeline from Aquila Gas
Pipeline, an affiliate of Aquila, Inc., for $264 million in cash. In December
2002, Energy Transfer acquired the remaining 50% equity interest in the Oasis
Pipeline from an affiliate of The Dow Chemical Company for $87 million in cash.
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Energy Transfer operates its assets differently than did Aquila Gas
Pipeline. The differences in operations are as follows:
- Aquila Gas Pipeline owned only a 50% equity interest in the Oasis
Pipeline. As a result of Energy Transfer's 100% ownership of the Oasis
Pipeline, it is able to achieve operating efficiencies that previously
could not be achieved. These operating efficiencies include:
-- bypassing the La Grange processing plant when processing margins are
unfavorable;
-- blending natural gas into the Oasis Pipeline instead of treating this
natural gas; and
-- reducing general and administrative costs.
- Aquila Gas Pipeline had more extensive marketing and trading operations
than Energy Transfer does primarily as a result of the marketing and
trading of substantial amounts of off-system gas which utilized storage
facilities owned by its affiliates. Unlike Aquila Gas Pipeline, Energy
Transfer does not own storage facilities, and Energy Transfer focuses its
marketing activities on its on-system gas. As a result of Energy
Transfer's focus on marketing its on-system gas, its ability to bypass
the La Grange processing plant and its efforts to manage commodity price
risk by balancing its purchases of natural gas with physical forward
contracts and certain financial derivatives, we believe that Energy
Transfer's revenues, earnings and gross margins will be substantially
less volatile than Aquila Gas Pipeline's historical results.
- In addition to the midstream business, Aquila, Inc. also participates in
other areas of the energy industry including the regulated distribution
of natural gas and electricity and non-regulated electric power
generation. We believe that Energy Transfer's focus on midstream
activities, as opposed to the diversified operations of Aquila Gas
Pipeline's parent, will enable Energy Transfer to achieve additional
operational efficiencies.
RESULTS OF OPERATIONS
HERITAGE PROPANE PARTNERS
Amounts discussed below reflect 100% of the results of M-P Energy
Partnership. M-P Energy Partnership is a general partnership in which we own a
60% interest. Because M-P Energy Partnership is primarily engaged in
lower-margin wholesale distribution, its contribution to our net income is not
significant and the minority interest of this partnership is excluded from the
EBITDA, as adjusted, calculation. All other financial information and operating
data included in management's discussion and analysis of financial condition and
results of operations includes references to the foreign wholesale results of
M-P Energy Partnership.
Fiscal Year Ended August 31, 2003 Compared to the Fiscal Year Ended August 31,
2002
Volume. Total retail gallons sold in fiscal year 2003 were 375.9 million,
an increase of 46.3 million from the 329.6 million gallons sold in fiscal year
2002. Of the increase in volume, approximately 6.0 million gallons was
attributable to the volume added through acquisitions and approximately 40.3
million gallons was attributable to more favorable weather conditions in 2003 in
some of our areas of operations, offset by warmer than normal weather conditions
in other areas of operations.
We sold approximately 74.3 million wholesale gallons during fiscal year
2003 of which 15.3 million were domestic wholesale and 59.0 million were foreign
wholesale. In fiscal year 2002, we sold 16.8 million domestic wholesale gallons
and 65.3 million foreign wholesale gallons. The 6.3 million gallon decrease in
foreign wholesale volumes of M-P Energy Partnership was primarily due to an
exchange contract that was in effect during fiscal year 2002, which was not
economical to renew during fiscal year 2003.
Revenues. Total revenues for fiscal year 2003 were $571.4 million, an
increase of $109.1 million, as compared to $462.3 million in fiscal year 2002.
Retail revenues for fiscal year 2003 were $463.4 million as compared to $365.3
million for fiscal year 2002, an increase of $98.1 million, of which $40.9
million was
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primarily due to higher selling prices, and $49.8 million was primarily due to
the increase in gallons sold as a result of colder weather conditions, and $7.4
million was due to the increase in gallons sold by customer service locations
added through acquisitions. Selling prices in all the reportable segments
increased from last year in response to higher supply costs. Domestic wholesale
revenues increased $0.7 million to $10.7 million, due to an increase of
approximately $1.7 million related to higher selling prices, offset by a
decrease of approximately $1.0 million related to a decrease in gallons sold.
Foreign wholesale revenues were $36.6 million for fiscal year 2003 as compared
to $31.2 million for fiscal year 2002, an increase of $5.4 million primarily due
to an approximate $9.3 million increase related to higher selling prices offset
by an approximate $3.9 million related to decreased volumes as described above.
Net liquids marketing revenues increased to $1.3 million in fiscal year 2003
from $0.5 million in fiscal year 2002, primarily due to more favorable movement
in product prices in the current fiscal year. Other domestic revenues increased
by $4.1 million to $59.4 million for fiscal year 2003, compared to $55.3 million
for fiscal year ended 2002 primarily as a result of acquisitions.
Cost of Products Sold. Total cost of sales increased $58.9 million to
$297.1 million as compared to $238.2 million for fiscal year 2002. Retail fuel
cost of sales increased $51.7 million to $236.3 million for fiscal year 2003, of
which approximately $29.1 million was due to increased volumes, and
approximately $22.6 million was due to higher supply costs. U.S. wholesale cost
of sales decreased $0.1 million to $9.6 million. Foreign wholesale cost of sales
increased $4.7 million to $34.0 million, of which approximately $8.4 million was
due to increased product costs this fiscal year, offset by an approximate
decrease of $3.7 million attributable to the decreased volumes described above.
Other cost of sales increased $2.6 million to $17.2 million for fiscal year 2003
primarily due to acquisitions.
Gross Profit. Total gross profit increased to $274.3 million in fiscal
year 2003 as compared to $224.1 million in fiscal year 2002, due to the
aforementioned increases in volumes and revenues described above, and the
results of acquisitions, offset in part by the increases in product costs. For
fiscal year 2003, retail fuel gross profit was $227.1 million, domestic
wholesale fuel gross profit was $1.1 million, liquids marketing gross profit was
$1.3 million, other gross profit was $42.2 million, and foreign wholesale gross
profit was $2.6 million. As a comparison, for fiscal year 2002, we recorded
retail fuel gross profit of $180.7 million, domestic wholesale fuel gross profit
of $0.3 million, liquids marketing gross profit of $0.5 million, other gross
profit of $40.6 million and foreign wholesale gross profit of $2.0 million.
Operating Expenses. Operating expenses were $152.1 million for fiscal year
2003 as compared to $133.2 million for fiscal year 2002. The increase of $18.9
million is primarily the result of $6.8 million of additional operating expenses
incurred for employee wages and benefits related to the growth of us from
acquisitions made during fiscal year 2002, an increase of $5.5 million in the
performance-based compensation plan expense due to higher operating performance,
an increase of approximately $5.5 million in operating expenses in certain areas
of our operations due to acquisitions and to accommodate increased winter demand
and industry-wide increases in business insurance costs of $1.1 million.
Selling, General and Administrative. Selling, general and administrative
expenses were $14.0 million for fiscal year 2003 as compared to $13.0 million
for fiscal year 2002. This increase is primarily related to the
performance-based compensation plan expense in 2003 that was not incurred in
2002, offset by a $0.7 million decrease in deferred compensation expense related
to the adoption of FASB Statement No. 123 Accounting for Stock-Based
Compensation (SFAS 123).
Depreciation and Amortization. Depreciation and amortization for fiscal
year 2003 was $37.9 million, an increase of $0.9 million as compared to $37.0
million in fiscal year 2002. The increase is attributable to current year
acquisitions.
Operating Income. We reported operating income of $70.2 million in fiscal
year 2003 as compared to the operating income of $41.0 million for fiscal year
2002. This increase is a combination of increased gross profit and a $0.7
million increase due to the adoption of SFAS 123, offset by increased operating
expenses described above.
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Interest Expense. Interest expense for fiscal year 2003 was $35.7 million,
a decrease of $1.6 million as compared to $37.3 million in fiscal year 2002. The
decrease was primarily attributable to the retirement of a portion of
outstanding debt during the year.
Other Expense. Other expense for fiscal year 2003 was $3.2 million, an
increase of $2.9 million as compared to $0.3 million in fiscal year 2002. The
increase was primarily attributable to the reclassification into earnings of a
$2.8 million loss on marketable securities in fiscal year 2003 that was
previously recorded as accumulated other comprehensive loss on the balance
sheet.
Taxes. Taxes for the year ended August 31, 2003 were $1.0 million due to
the tax expense incurred by our corporate subsidiaries and other franchise taxes
owed. Of the $1.0 million increase, $0.3 million was incurred in connection with
the liquidation of Guilford Gas Service, Inc. during the fiscal year ended
August 31, 2003. There was no tax expense for these subsidiaries for the year
ended August 31, 2002.
Net Income. We reported net income of $31.1 million, or $1.79 per limited
partner unit, for fiscal year 2003, an increase of $26.2 million from net income
of $4.9 million for fiscal year 2002. The increase is primarily the result of
the increase in operating income, which includes a $0.7 million decrease in
expenses due to the adoption of SFAS 123, partially offset by the increase in
other expenses and taxes described above.
EBITDA, as adjusted. EBITDA, as adjusted, increased $29.5 million to
$111.0 million for fiscal year 2003, as compared to EBITDA, as adjusted, of
$81.5 million for fiscal year 2002. This increase is due to the operating
conditions described above and is a record level of EBITDA, as adjusted, for our
fiscal year results. Please read footnote (c) under "Heritage Propane Partners
Selected Historical Financial and Operating Data".
ENERGY TRANSFER
Energy Transfer commenced operations on October 1, 2002 with the
acquisition of the Southeast Texas System, the Elk City System and a 50% equity
interest in Oasis Pipe Line Company from Aquila Gas Pipeline. On December 27,
2002, Energy Transfer acquired the remaining interest in Oasis Pipe Line. As a
result, Energy Transfer's historical financial information for the period from
October 1, 2002 to August 31, 2003, which is Energy Transfer's fiscal year end,
has been derived from the historical financial statements of Energy Transfer.
Energy Transfer's historical financial information for periods prior to
October 1, 2002 has been derived from the historical financial statements of
Aquila Gas Pipeline. Prior to October 1, 2002, Aquila Gas Pipeline owned the
Southeast Texas System, the Elk City System and a 50% equity interest in Oasis
Pipe Line.
Therefore, we are comparing the results of operations of Energy Transfer
for the 11 months ended August 31, 2003 to the results of operations of Aquila
Gas Pipeline for the 9 months ended September 30, 2002.
Historical 11 Months Ended August 31, 2003 Compared to Historical 9 Months
Ended September 30, 2002
Revenues. Total revenues were $1,008.7 million for the 11 months ended
August 31, 2003 compared to $933.1 million for the 9 months ended September 30,
2002, an increase of $75.6 million or 8.1%. On an annualized basis this
represents an 11.6% decrease.
Midstream revenues were $978.1 million for the 11 months ended August 31,
2003 compared to $933.1 million for the 9 months ended September 30, 2002, an
increase of $45.0 million or 4.8%. However, on an annualized basis this
represents a 14.2% decrease. This annualized decrease was directly attributable
to a reduction in natural gas and NGL daily sales volumes partially offset by
higher natural gas and NGL sales prices.
Natural gas sales volumes were 524,000 MMBtu/d for the 11 months ended
August 31, 2003 compared to 1,147,000 MMBtu/d for the 9 months ended September
30, 2002, a decrease of
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623,000 MMBtu/d or 54.3%. NGL sales volumes were 12,857 Bbls/d for the 11 months
ended August 31, 2003 compared to 18,881 Bbls/d for the 9 months ended September
30, 2002, a decrease of 6,024 Bbls/d or 31.9%. Natural gas sales volumes
decreased significantly as a result of the smaller scope of Energy Transfer's
marketing activities as compared to Aquila Gas Pipeline's extensive marketing
and trading activities. NGL sales volumes decreased due to Energy Transfer's
frequent election to bypass its La Grange processing plant and deliver
unprocessed natural gas from its Southeast Texas System directly into the Oasis
Pipeline during the portion of the 11 month period ended August 31, 2003 that it
owned 100% of Oasis. Energy Transfer elected to bypass the La Grange processing
plant to avoid unfavorable processing margins.
Average realized natural gas sales prices were $5.03 per MMBtu for the 11
months ended August 31, 2003 compared to $2.72 per MMBtu for the 9 months ended
September 30, 2002, an increase of $2.31 per MMBtu or 85.0%. In addition,
average realized NGL sales prices were $0.41 per gallon for the 11 months ended
August 31, 2003 compared to $0.32 per gallon for the 9 months ended September
30, 2002, an increase of $0.09 per gallon or 26.8%.
Transportation revenues were $30.6 million for the 11 months ended August
31, 2003. Energy Transfer's results for the 9 month period ended September 30,
2002 and for the 3 month period ended December 27, 2002 exclude revenues of
Oasis Pipe Line because Energy Transfer's investment in Oasis Pipe Line was
treated as an equity method investment prior to December 27, 2002. Had Oasis
Pipe Line been consolidated in both periods, Transportation revenues would have
been $38.6 million for the 11 months ended August 31, 2003 and $24.7 million for
the 9 months ended September 30, 2002, an increase of $13.9 million or 56.3%. On
an annualized basis this represents a 28.0% increase. This increase was due to
an increase in volumes transported on the Oasis Pipeline from 912,584 MMBtu/d
for the 9 months ended September 30, 2002 to 921,316 MMBtu/d for the 11 months
ended August 31, 2003 and to an increase in the transportation rate on the Oasis
Pipeline from $0.09 per MMBtu for the 9 months ended September 30, 2002 to $0.12
per MMBtu for the 11 months ended August 31, 2003. The increase in Energy
Transfer's average transportation rate was achieved, in part, due to a widening
of the difference, also known as the basis differential, between the average
price for natural gas at the Katy Hub near Houston, Texas and the average price
for natural gas at the Waha Hub in West Texas. The widening of the basis
differential allows Energy Transfer to increase the transportation rates it
charges between these points. The average basis differential for the 11 months
ended August 31, 2003 was approximately $0.28 per MMBtu as compared to $0.11 per
MMBtu for the 9 months ended September 30, 2002.
Cost of Sales. Total cost of sales was $899.5 million for the 11 months
ended August 31, 2003 compared to $880.1 million for the 9 months ended
September 30, 2002, an increase of $19.4 million or 2.2%. On an annualized basis
this represents a 16.4% decrease.
Midstream cost of sales was $899.4 million for the 11 months ended August
31, 2003 compared to $880.1 million for the 9 months ended September 30, 2002,
an increase of $19.3 million or 2.2%. However, on an annualized basis this
represents a 16.4% decrease. This annualized decrease was primarily attributable
to a reduction in volumes of natural gas and NGLs, partially offset by the
increase in natural gas prices. The Transportation segment sold excess inventory
during the 11 months ended August 31, 2003 resulting in a cost of sales of $0.1
million. The Transportation segment only periodically engages in activities that
generate cost of sales.
Operating Expenses. Operating expenses were $19.1 million for the 11
months ended August 31, 2003 compared to $12.7 million for the 9 months ended
September 30, 2002, an increase of $6.4 million or 50.0%. On an annualized basis
this represents a 22.8% increase. This increase was due to the inclusion of
approximately $4.9 million of operating expenses associated with Oasis Pipe Line
subsequent to December 27, 2002. Oasis Pipe Line's operating expenses were not
included in Aquila Gas Pipeline's results for the 9 month period ended September
30. 2002, because Aquila Gas Pipeline accounted for its investment in Oasis Pipe
Line under the equity method. Oasis Pipe Line's operating expenses on a
standalone basis were $4.7 million for the 9 months ended September 30, 2002 and
$6.6 million for the 11 months ended August 31, 2003.
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General and Administrative Expenses. General and administrative expenses
were $16.0 million for the 11 months ended August 31, 2003 compared to $9.6
million for the 9 months ended September 30, 2002, an increase of $6.4 million
or 66.7%. On an annualized basis this represents a 36.4% increase. This
annualized increase resulted primarily from higher employee bonuses and
increased travel and insurance costs as well as the inclusion of general and
administrative expense of Oasis Pipe Line subsequent to December 27, 2002.
Depreciation and Amortization. Depreciation and amortization expense was
$13.4 million for the 11 months ended August 31, 2003 compared to $22.9 million
for the 9 months ended September 30, 2002, a decrease of $9.5 million or 41.3%.
On an annualized basis this represents a 51.9% decrease. Depreciation and
amortization expense decreased for the 11 months ended August 31, 2003 primarily
due to the acquisition of midstream assets from Aquila Gas Pipeline, which
resulted in a reduction in the depreciable basis on which these assets are
depreciated. Aquila Gas Pipeline's book value of the acquired assets
significantly exceeded Energy Transfer's book value in them. In addition, Aquila
Gas Pipeline amortized $2.4 million during the 9 months ended September 30, 2002
related to a transportation rights contract that has expired. This decrease was
partially offset by the inclusion of $2.8 million of depreciation and
amortization expense of Oasis Pipe Line subsequent to December 27, 2002.
Unrealized Loss (Gain) on Derivatives. The unrealized gain on derivatives
was $0.9 million for the 11 months ended August 31, 2003 compared to an
unrealized loss of $5.0 million for the 9 months ended September 30, 2002.
Derivative price changes worked to the detriment of Aquila Gas Pipeline during
the 9 months ended September 30, 2002.
Equity in Net Income (Loss) of Affiliates. Equity in net income of
affiliates was $1.4 million for the 11 months ended August 31, 2003 compared to
$5.4 million for the 9 months ended September 30, 2002, a decrease of $4.0
million or 73.8%. This decrease resulted from equity in net income (loss) of
affiliates for the 11 months ended August 31, 2003 not reflecting any equity
earnings associated with Oasis Pipe Line subsequent to December 27, 2002 while
Oasis Pipe Line's earnings were recognized under the equity method of accounting
for the 3 months ended December 27, 2002 and the 9 months ended September 30,
2002. Equity earnings from Oasis Pipe Line included in total equity in net
income (loss) of affiliates was $1.6 million and $5.4 million for the 3 months
ended December 27, 2002 and 9 months ended September 30, 2002, respectively.
Interest Expense. Interest expense was $12.1 million for the 11 months
ended August 31, 2003 compared to $3.9 million for the 9 months ended September
30, 2002, an increase of $8.2 million or 210.3%. The increase was primarily due
to the increased borrowings used to finance the purchase of midstream assets
from Aquila Gas Pipeline and Dow Hydrocarbons Resources, Inc.
Income Tax Expense. Income tax expense was $4.4 million for the 11 months
ended August 31, 2003 compared to a benefit of $0.5 million for the 9 months
ended September 30, 2002. As a partnership, Energy Transfer is not subject to
income taxes. However, Energy Transfer's subsidiary, Oasis Pipe Line, is a
corporation that is subject to income taxes at an effective rate of 35%. The
benefit for the 9 months ended September 30, 2002 was related to the operating
results of Aquila Gas Pipeline, which is a corporation subject to income taxes.
Net Income. Energy Transfer's net income for the 11 months ended August
31, 2003 was $46.6 million compared to $4.7 million for the 9 months ended
September 30, 2002, an increase of $41.9 million. The increase in net income was
due to the reasons described above.
LIQUIDITY AND CAPITAL RESOURCES
Our ability to satisfy our obligations will depend on our future
performance, which will be subject to prevailing economic, financial, business
and weather conditions, and other factors, many of which are beyond our control.
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HERITAGE PROPANE PARTNERS FUTURE CAPITAL REQUIREMENTS
Our future capital requirements for our retail propane operations will
generally consist of:
- maintenance capital expenditures;
- growth capital expenditures, mainly for customer tanks; and
- acquisition capital expenditures.
We believe that cash generated from the operations of our propane business
will be sufficient to meet anticipated propane maintenance capital expenditures,
which we anticipate will be approximately $15.5 million during fiscal 2004. We
will initially finance all our propane capital requirements by cash flows from
propane operating activities. To the extent our future propane capital
requirements exceed cash flows from propane operating activities:
- propane maintenance capital expenditures will be financed by the proceeds
of borrowings under the working capital facility of our operating
partnership, Heritage Operating, L.P. described below, which will be
repaid by subsequent seasonal reductions in inventory and accounts
receivable;
- propane growth capital expenditures will be financed by the proceeds of
borrowings under the acquisition facility of Heritage Operating; and
- propane acquisition capital expenditures will be financed by the proceeds
of borrowings under the acquisition facility of Heritage Operating, other
lines of credit, long-term debt, the issuance of additional common units
or a combination thereof.
The assets utilized in the propane business do not typically require
lengthy manufacturing process time or complicated, high technology components.
Accordingly, we do not have any significant financial commitments for
maintenance capital expenditures in our propane business. In addition, we have
not experienced any significant increases attributable to inflation in the cost
of these assets or in our propane operations.
Acquisition capital expenditures, which include expenditures related to the
acquisition of retail propane operations and intangibles associated with such
acquired businesses, were $24.9 million for the fiscal year ended August 31,
2003 as compared to $19.7 million for fiscal year 2002. In addition to the $24.9
million of cash expended for acquisitions of retail propane operations during
fiscal year 2003, $15.0 million of common units and $0.9 million for notes
payable on non-compete agreements were issued and $1.0 million in liabilities
were assumed in connection with certain acquisitions. In comparison, in addition
to the $19.7 million of cash expended for acquisitions of retail propane
operations during the fiscal year ended August 31, 2002, $2.7 million for notes
payable on non-compete agreements were issued in connection with such
acquisitions.
ENERGY TRANSFER FUTURE CAPITAL REQUIREMENTS
We anticipate that our future capital requirements for the Energy Transfer
business will consist of:
- maintenance capital expenditures, which include capital expenditures made
to connect additional wells to Energy Transfer's systems in order to
maintain or increase throughput on existing assets;
- growth capital expenditures, mainly to expand and upgrade gathering
systems, transportation capacity, processing plants or treating plants;
and
- acquisition capital expenditures, including to construct new pipelines,
processing plants and treating plants.
We believe that cash generated from the operations of the Energy Transfer
business will be sufficient to meet its anticipated maintenance capital
expenditures, which we anticipate will be approximately $6 million during fiscal
2004. We will initially finance all of Energy Transfer's capital requirements by
cash
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flow from the Energy Transfer business. To the extent Energy Transfer's future
capital requirements exceed cash flows from the Energy Transfer business:
- Energy Transfer's maintenance capital expenditures will be financed by
the proceeds of borrowings under the new Energy Transfer credit facility
which will be repaid from subsequent cash flows generated from the Energy
Transfer business;
- Energy Transfer's growth capital expenditures will be financed by the
proceeds of borrowings under the new Energy Transfer credit facility; and
- Energy Transfer's acquisition capital expenditures will be financed by
the proceeds of borrowings under the new Energy Transfer credit facility,
other lines of credit, long-term debt, the issuance of additional common
units or a combination thereof.
The assets utilized in the Energy Transfer businesses, including pipelines,
gathering systems and related facilities, are generally long-lived assets and do
not require significant maintenance capital expenditures.
We anticipate that we will continue to invest significant amounts of
capital to construct and acquire midstream assets. For example, Energy Transfer
has announced that it intends to construct the Bossier Pipeline connecting its
Katy Pipeline in Grimes County to natural gas supplies in east Texas. We
anticipate that the Bossier Pipeline will require capital expenditures of
approximately $75 million to complete, and we expect to complete the Bossier
Pipeline by mid-2004.
HERITAGE PROPANE PARTNERS CASH FLOWS
Operating Activities. Cash provided by operating activities for fiscal
year 2003 was $95.2 million as compared to cash provided by operating activities
of $65.4 million for fiscal year 2002. The net cash provided from operations of
$95.2 million for fiscal year 2003 consisted of net income of $31.1 million and
non-cash charges of $43.2 million, primarily depreciation and amortization, and
a decrease in working capital items of $20.9 million.
Investing Activities. We completed six acquisitions during fiscal year
2003 investing $24.9 million, net of cash received. This capital expenditure
amount is reflected in the cash used in investing activities of $48.4 million
along with $15.1 million invested for maintenance needed to sustain operations
at current levels and $12.2 million for customer tanks and other expenditures to
support growth of operations. Investing activities also includes proceeds from
the sale of property of $3.8 million.
Financing Activities. Cash used in financing activities of $44.3 million
during fiscal year 2003 was primarily comprised of a net decrease in short-term
debt of $3.5 million, a net decrease in long-term debt of $42.1 million and
$43.4 million of cash distributions paid to unitholders and our general partner,
offset by $44.5 million of net proceeds from the issuance of common units and
$0.2 million contributed by our general partner to maintain its general partner
interest in us.
ENERGY TRANSFER CASH FLOWS
Operating Activities. Energy Transfer's net cash provided by operating
activities was $70.9 million for the 11 months ended August 31, 2003. The net
cash provided from operations consisted of net income of $46.6 million and
non-cash charges of $15.8 million, primarily depreciation and amortization, and
a decrease in working capital and certain long-term liabilities of $8.9 million.
Additionally, Energy Transfer's operating cash flow was negatively impacted by
the difference between equity earnings and dividends from equity investments of
$0.4 million.
Investing Activities. Energy Transfer's net cash used in investing
activities was $341.2 million for the 11 months ended August 31, 2003.
Approximately $337.1 million (net of acquired cash through acquisitions) was
invested by Energy Transfer for the acquisition of the midstream assets and the
50% interest in Oasis Pipe Line previously owned by Aquila Gas Pipeline and the
purchase of the remaining 50% interest in Oasis Pipe Line previously owned by
Dow Hydrocarbons Resources, Inc. During this
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period, Energy Transfer sold its 20% interest in the Nustar Joint Venture, which
Energy Transfer determined was not a strategic asset. No gain or loss was
recognized as a result of the sale. Energy Transfer's net proceeds from the sale
of its interest in Nustar was $9.6 million. Capital expenditures were $13.9
million during the 11 months ended August 31, 2003.
Financing Activities. Energy Transfer's net cash used in financing
activities was $323.4 million for the 11 months ended August 31, 2003. Energy
Transfer borrowed $239.5 million, net of financing fees, for the purpose of
financing the acquisition activity discussed above. Energy Transfer retired
$20.0 million of this debt during this same period and made a $4.8 million
distribution to its partners in April 2003. The partners contributed $108.7
million to initially capitalize the partnership.
FINANCING AND SOURCES OF LIQUIDITY
Upon consummation of the Energy Transfer transaction, we will maintain
separate credit facilities for each of Heritage Operating and Energy Transfer.
Each credit facility will be secured only by the assets of the operating
partnership that it finances, and neither operating partnerships nor its
subsidiaries will guarantee the debt of the other operating partnership.
Heritage Propane Partners Facilities. We have a bank credit facility with
various financial institutions that is for the exclusive use of Heritage
Operating, which includes a working capital facility, providing for up to $65.0
million of borrowings to be used for working capital and other general
partnership purposes, and an acquisition facility, providing for up to $50.0
million of borrowings to be used for retail propane acquisitions and
improvements. The bank credit facility is secured by all receivables, contracts,
equipment, inventory and general intangibles of Heritage Operating. Under the
terms of the bank credit facility agreement, the working capital facility is set
to expire June 30, 2004 and the acquisition facility was set to expire December
31, 2003, at which time the outstanding balance on the acquisition facility was
to convert to a term loan payable in quarterly installments with a final
maturity of June 30, 2006. We are currently negotiating and expect to enter into
an amendment to the bank credit facility to increase the amount available to be
borrowed under each of the working capital facility and the acquisition facility
to up to $75 million and to extend the maturity of each facility to December 31,
2006. The weighted average interest rate was 2.49% for the amounts outstanding
at August 31, 2003 on both the working capital facility and the acquisition
facility. At August 31, 2003, there was $38.3 million available for borrowing
under the working capital facility and $25.3 million available under the
acquisition facility.
Energy Transfer Facilities. In connection with the Energy Transfer
transaction, Energy Transfer will enter into a new credit facility with its
existing lenders providing for a four-year non-amortizing term loan of up to
$325 million and a $125 million revolving credit facility. The term loan, which
is initially expected to be in the amount of $275 million, will be used to
retire Energy Transfer's existing credit facilities, satisfy Energy Transfer's
accounts payable and other specified liabilities as they become due and fund
certain other expenses in connection with the Energy Transfer transaction.
Energy Transfer may also elect to borrow an additional $50 million under the
term loan to refinance the $50 million two-year promissory note that is to be
issued by us in the Energy Transfer transaction. The interest rate will
fluctuate based on a ratio of total funded debt to EBITDA. At Energy Transfer's
option, interest shall be payable at the alternative base rate plus an
applicable margin ranging from 0.75% to 1.75% or the Eurodollar rate plus an
applicable margin ranging from 2.00% to 3.00%. The revolving credit facility is
expected to provide for up to $125 million in borrowings and may be utilized for
general working capital needs, issuance of letters of credit, funding of the
construction of the proposed Bossier Pipeline and financing of other capital
expenditures for acquisitions and growth projects. The Energy Transfer credit
facility will be fully secured by substantially all of Energy Transfer's assets.
We may refinance the Energy Transfer credit facility at a later date with other
bank debt, private placement debt with institutional investors, a public debt
offering, a public equity offering, or a combination of one or more of the
foregoing.
Cash Distributions. We use our cash provided by operating activities and
borrowings under our working capital facilities to provide distributions to our
unitholders. Under our partnership agreement, we will distribute to our general
partner and our limited partners, 45 days after the end of each fiscal quarter,
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an amount equal to all of our available cash for such quarter. Available cash
generally means, with respect to any quarter, all cash on hand at the end of
such quarter less the amount of cash reserves established by our general partner
in its reasonable discretion that are necessary or appropriate to provide for
future cash requirements. Our commitment to our unitholders is to distribute
increases in our cash flow while maintaining prudent reserves for our
operations. The distribution was $0.6375 per unit ($2.55 annually) for each of
the quarters ended February 28, 2002 through and including May 31, 2003. We
raised the quarterly distribution $0.0125 per unit for the quarter ended August
31, 2003, to $0.65 per unit ($2.60 annually). We have also declared a cash
distribution of $0.65 per common unit on our outstanding units for the first
quarter of fiscal year 2004, which distribution will be payable on January 14,
2004 to holders of record as of December 30, 2003. The current distribution
level includes incentive distributions payable to our general partner to the
extent the quarterly distribution exceeds $0.55 per unit ($2.20 annually).
DESCRIPTION OF INDEBTEDNESS
In connection with our initial public offering, on June 25, 1996, we
entered into a Note Purchase Agreement whereby we issued $120 million principal
amount of 8.55% Senior Secured Notes to institutional investors. Interest is
payable semi-annually in arrears on each December 31 and June 30. These notes
have a final maturity of June 30, 2011, with ten equal mandatory repayments of
principal, which began on June 30, 2002. At August 31, 2003, $96 million
principal amount of the notes was outstanding.
On November 19, 1997, we entered into a Note Purchase Agreement that
provided for the issuance of up to $100 million of senior secured promissory
notes if certain conditions were met, which we refer to as our medium term note
program. An initial placement of $32 million (Series A and B), at an average
interest rate of 7.23% with an average 10-year maturity, was completed at the
closing of the medium term note program. Interest is payable semi-annually in
arrears on each November 19 and May 19. An additional placement of $15 million
(Series C, D and E), at an average interest rate of 6.59% with an average
12-year maturity, was completed in March 1998. Interest is payable on Series C
and D semi-annually in arrears on each September 13 and March 13. The proceeds
of the placements were used to refinance amounts outstanding under the
acquisition facility. No future placements are permitted under the unused
portion of the medium term note program. During the fiscal year ended August 31,
2003, we used $3.9 million and $5.0 million of the proceeds from the issuance of
1,610,000 common units to retire the balance of the Series D and Series E senior
secured notes. At August 31, 2003, $34.1 million principal amount of senior
secured notes was outstanding.
On August 10, 2000, we entered into a Note Purchase Agreement that provided
for the issuance of up to $250 million of fixed rate senior secured promissory
notes if certain conditions were met. An initial placement of $180 million
(Series A through F), at an average rate of 8.66% with an average 13-year
maturity, was completed in conjunction with our merger with U.S. Propane.
Interest is payable quarterly. The proceeds were used to finance the transaction
with U.S. Propane and retire a portion of existing debt. On May 24, 2001, we
issued an additional $70 million (Series G through I) of the senior secured
promissory notes to a group of institutional lenders with 7-, 12- and 15-year
maturities and an average coupon rate of 7.66%. We used the net proceeds from
the senior secured promissory notes to repay the balance outstanding under the
acquisition facility and to reduce other debt. Interest is payable quarterly.
During the fiscal year ended August 31, 2003, we used $7.5 million and $19.5
million of the proceeds from the issuance of 1,610,000 common units to retire a
portion of the Series G and Series H senior secured promissory notes,
respectively. At August 31, 2003, $223 million principal amount of senior
secured promissory notes was outstanding.
The note agreements for each of the senior secured notes, medium term note
program and senior secured promissory notes and the Heritage bank credit
facility contain customary restrictive covenants applicable to Heritage
Operating, including limitations on the level of additional indebtedness,
creation of liens and sale of assets. These covenants require Heritage Operating
to maintain ratios of consolidated funded indebtedness to consolidated EBITDA
(as these terms are similarly defined in the Heritage bank credit facility and
the note agreements) of not more than 5.00 to 1 for the Heritage bank credit
facility
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and not more than 5.25 to 1 for the note agreements and consolidated EBITDA to
consolidated interest expense (as these terms are similarly defined in the
Heritage bank credit facility and the note agreements) of not less than 2.25 to
1. The consolidated EBITDA used to determine these ratios is calculated in
accordance with these debt agreements. For purposes of calculating the ratios
under the Heritage bank credit facility and the note agreements, consolidated
EBITDA is based upon our EBITDA, as adjusted, during the most recent four
quarterly periods and modified to give pro forma effect for acquisitions and
divestitures made during the test period and is compared to consolidated funded
indebtedness as of the test date and the consolidated interest expense for the
most recent twelve months. The debt agreements also provide that Heritage
Operating may declare, make, or incur a liability to make a restricted payment
during each fiscal quarter, if: (a) the amount of such restricted payment,
together with all other restricted payments during such quarter, do not exceed
available cash with respect to the immediately preceding quarter; and (b) no
default or event of default exists before such restricted payment and after
giving effect thereto. The debt agreements further provide that available cash
is required to reflect a reserve equal to 50% of the interest to be paid on the
notes. In addition, in the third, second and first quarters preceding a quarter
in which a scheduled principal payment is to be made on the notes, available
cash is required to reflect a reserve equal to 25%, 50% and 75%, respectively,
of the principal amount to be repaid on such payment dates.
Failure to comply with the various restrictive and affirmative covenants of
the Heritage bank credit facility and the note agreements could negatively
impact our ability to incur additional debt and to pay distributions. We are
required to measure these financial tests and covenants quarterly and were in
compliance with all financial requirements, tests, limitations and covenants
related to financial ratios under the senior secured notes, medium term note
program, senior secured promissory notes and the Heritage bank credit facility
at August 31, 2003.
The new Energy Transfer credit facility is expected to contain customary
restrictive covenants applicable to Energy Transfer, including limitations on
the level of additional indebtedness, creation of liens and sale of assets.
These covenants will also require Energy Transfer to maintain ratios of (1)
consolidated funded indebtedness to consolidated EBITDA (as such terms are
defined in the new Energy Transfer credit facility) of not more than 4.0 to 1,
(2) adjusted consolidated funded indebtedness to adjusted consolidated EBITDA
(as these terms are defined in the new Energy Transfer credit facility) of not
more than (x) 5.25 to 1 from the closing date of the Energy Transfer transaction
to November 30, 2005 and (y) 5.0 to 1 on any applicable date of determination
thereafter, and (3) consolidated EBITDA to consolidated interest expense (as
these terms are defined in the new Energy Transfer credit facility) of not less
than 2.75 to 1. The financial tests described in clause (1) and (2) above are
calculated quarterly, and the financial test described in clause (3) above is
calculated with respect to a period of four consecutive quarters. Consolidated
EBITDA is based upon the net income of Energy Transfer and its consolidated
subsidiaries and is modified to give pro forma effect to the Bossier Pipeline
for the ratios described in clauses (1) and (2) above and for acquisitions and
divestitures made during any period of determination for purposes of all three
ratios described above. The credit facility also provides that Energy Transfer
may make distributions to us or make other specified payments (each referred to
as a "restricted payment") during each fiscal quarter, if: (a) the amount of
such restricted payment, together with all other restricted payments during such
quarter, does not exceed available cash (defined in a manner similar to the
definition of available cash in our partnership agreement) with respect to the
immediately preceding quarter; and (b) no event of default exists before such
restricted payment and after giving effect thereto. Failure to comply with the
various restrictive and affirmative covenants of the new Energy Transfer credit
facility could negatively impact our ability to incur additional debt and to pay
distributions.
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HERITAGE PROPANE PARTNERS CONTRACTUAL OBLIGATIONS
The following table summarizes our long-term debt and other contractual
obligations as of August 31, 2003:
<Table>
<Caption>
PAYMENTS DUE BY PERIOD
--------------------------------------------------------
LESS THAN MORE THAN
TOTAL 1 YEAR 1-3 YEARS 3-5 YEARS 5 YEARS
-------- --------- --------- --------- ---------
(IN THOUSANDS)
Long-term debt................... $399,071 $38,309 $88,762 $83,737 $188,263
Operating lease obligations...... 8,856 2,916 3,231 1,863 846
-------- ------- ------- ------- --------
Totals........................... $407,927 $41,225 $91,993 $85,600 $189,109
======== ======= ======= ======= ========
</Table>
See Note 4 -- "Working Capital Facility and Long-Term Debt" to the
Consolidated Financial Statements beginning on Page F-1 of our Annual Report on
Form 10-K for the fiscal year ended August 31, 2003 for further discussion of
the long-term debt classifications and the maturity dates and interest rates
related to long-term debt.
ENERGY TRANSFER CONTRACTUAL OBLIGATIONS
The following table summarizes Energy Transfer's long-term debt and other
contractual obligations as of August 31, 2003:
<Table>
<Caption>
PAYMENTS DUE BY PERIOD
--------------------------------------------------------
LESS THAN MORE THAN
TOTAL 1 YEAR 1-3 YEARS 3-5 YEARS 5 YEARS
-------- --------- --------- --------- ---------
(IN THOUSANDS)
Long term debt........................... $226,000 $30,000 $196,000 $-- $ --
Operating lease obligations.............. 2,244 920 1,323 1 --
-------- ------- -------- --- ----
Total.................................. $228,244 $30,920 $197,323 $ 1 $ --
</Table>
The above table does not include any commodity physical contract
commitments for natural gas or NGLs. Energy Transfer has forward commodity
contracts, which will be settled by physical delivery. Short-term contracts,
which expire in less than one year, require delivery of up to 54,000 MMBtu/d.
Long-term contracts require delivery of up to 156,000 MMBtu/d. The long-term
contracts run through July 2013.
A portion of the proceeds from this offering will be used to retire all of
the long term debt described above. In connection with the Energy Transfer
transaction, we intend to obtain a new Energy Transfer credit facility described
in "-- Liquidity and Capital Resources -- Financing and Sources of Liquidity --
Energy Transfer Facilities."
NEW ACCOUNTING STANDARDS
In June 2002, the FASB issued Statement No. 146, Accounting for Costs
Associated with Exit or Disposal Activities (SFAS 146). SFAS 146 addresses
financial accounting and reporting for costs associated with exit or disposal
activities and requires that a liability for a cost associated with an exit or
disposal activity be recognized and measured initially at fair value only when
the liability is incurred. We adopted the provisions of SFAS 146 effective for
exit or disposal activities that are initiated after December 31, 2002. The
adoption did not have a material impact on our consolidated financial position
or results of operations.
In November 2002, the FASB issued Financial Interpretation No. 45
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 expands the
existing disclosure requirements for guarantees and requires that companies
recognize a liability for guarantees issued after December 31, 2002. The
implementation of FIN 45 did not have a significant impact on our financial
position or results of operations.
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In January of 2003, the FASB issued Financial Interpretation No. 46
Consolidation of Variable Interest Entities -- An Interpretation of ARB No. 51
(FIN 46). FIN 46 clarifies Accounting Research Bulletin No. 51, Consolidated
Financial Statements. If certain conditions are met, this interpretation
requires the primary beneficiary to consolidate certain variable interest
entities in which equity investors lack the characteristics of a controlling
interest or do not have sufficient equity investment at risk to permit the
variable interest entity to finance its activities without additional
subordinated financial support from other parties. FIN 46 is effective
immediately for variable interest entities created or obtained after January 31,
2003. For variable interest entities acquired before February 1, 2003, the
interpretation is effective for the first fiscal year or interim period
beginning after June 15, 2003. Management does not believe FIN 46 will have a
significant impact on our financial position or results of operations.
In April 2003, the FASB issued Statement No. 149, Amendment of Statement
133 on Derivative Instruments and Hedging Activities (SFAS 149). SFAS 149 amends
and clarifies financial accounting and reporting for derivative instruments
embedded in other contracts (collectively referred to as derivatives) and for
hedging activities under SFAS 133. SFAS 149 is effective for contracts entered
into or modified after June 30, 2003, and for hedging relationships designated
after June 30, 2003. We adopted SFAS 149 as of July 1, 2003. The adoption of
SFAS 149 did not have a material impact on our consolidated financial position
or results of operations.
In May 2003, the FASB issued Statement No. 150, Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity (SFAS
150). SFAS 150 establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. It requires that an issuer classify a financial instrument that is
within the scope of SFAS 150 as a liability (or an asset in some circumstances).
This statement is effective for financial instruments entered into or modified
after May 31, 2003 and otherwise is effective at the beginning of the first
interim period beginning after June 15, 2003. We adopted the provisions of SFAS
150 as of September 1, 2003. The adoption did not have a material impact on our
consolidated financial position or results of operations.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
HERITAGE PROPANE PARTNERS
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to establish accounting policies and make estimates and assumptions
that affect reported amounts of assets and liabilities and disclosures of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period. We
evaluate its policies and estimates on a regular basis. Actual results could
differ from these estimates.
Our significant accounting policies are discussed in Note 2 -- "Summary of
Significant Accounting Policies and Balance Sheet Detail" to the Consolidated
Financial Statements beginning on page F-1 of our Annual Report on Form 10-K for
the fiscal year ended August 31, 2003. We believe the following are critical
accounting policies:
Marketable Securities. We have marketable securities that are classified
as available-for-sale. Unrealized holding losses occur as a result of declines
in the market value of our holdings. The fair market value of our holdings is
determined based upon the market price of the securities, which are publicly
traded securities. Based on the performance of the securities over the preceding
nine-month period, we review the fair market value to determine if an other-than
temporary impairment should be recorded.
Long-Lived Assets. We review long-lived assets for impairment whenever
events or changes in circumstances indicate that the carrying amount of such
assets may not be recoverable. We perform this review by considering if the
carrying values of the assets exceed the undiscounted cash flows expected to
result from the use and eventual disposition of the assets. If such a review
should indicate that the carrying amount of long-lived assets is not
recoverable, we reduce the carrying amount of such assets to fair value. We have
never recorded an impairment as a result of this review.
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Stock Based Compensation Plans. We account for its stock compensation
plans following the fair value recognition method. We adopted this accounting
method on a prospective basis beginning on September 1, 2002 for all stock based
compensation granted to date by us. This method was adopted as we believe it is
the preferable method of accounting for stock based compensation. Please see the
caption "Stock Based Compensation Plans" in Note 2 -- "Summary of Significant
Accounting Policies and Balance Sheet Detail" to the Consolidated Financial
Statements beginning on page F-1 of our Annual Report on Form 10-K for the
fiscal year ended August 31, 2003 for additional information about this adoption
and a comparison to amounts recorded in prior periods.
Depreciation of Property, Plant, and Equipment. We calculate depreciation
using the straight-line method based on the estimated useful lives of the assets
ranging from 5 to 30 years. Changes in the estimated useful lives of the assets
could have a material effect on our results of operation. We do not anticipate
future changes in the estimated useful live of its property, plant, and
equipment.
Amortization of Intangible Assets. We calculate amortization using the
straight-line method over periods ranging from 2 to 15 years. We use
amortization methods and determines asset values based on management's best
estimate using reasonable and supportable assumptions and projections. Changes
in the amortization methods or asset values could have a material effect on our
results of operations. We do not anticipate future changes in the estimated
useful lives of our intangible assets.
Fair Value of Derivative Commodity Contracts. We enter into commodity
forward, swaps and options contracts involving propane and related products,
which, in accordance with SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities", are not accounting hedges, but are used for risk
management trading purposes. To the extent such contracts are entered into at
fixed prices and thereby subject us to market risk, the contracts are accounted
for using the fair value method. Under this valuation method, derivatives are
carried in the consolidated balance sheets at fair value with changes in value
recognized in earnings. We classify all gains and losses from these derivative
contracts entered into for risk management purposes as liquids marketing revenue
in the consolidated statement of operations. We utilize published settlement
prices for exchange-traded contracts, quotes provided by brokers and estimates
of market prices based on daily contract activity to estimate the fair value of
these contracts. Changes in the methods used to determine the fair value of
these contracts could have a material effect on our results of operations. We do
not anticipate future changes in the methods used to determine the fair value of
these derivative contracts.
ENERGY TRANSFER
The following discussion summarizes Energy Transfer's critical accounting
policies.
Revenue Recognition. Energy Transfer recognizes revenue for sales of
natural gas and NGLs upon delivery. Service revenues, including transportation,
compression, treating and gas processing, are recognized at the time service is
performed. Transportation capacity payments are recognized when earned in the
period the capacity was made available.
Commodity Risk Management. In 1999, Aquila Gas Pipeline transferred all of
its trading operations to Aquila Energy Marketing, a wholly owned subsidiary of
Aquila, Inc. Aquila Energy Marketing entered into forward physical contracts
with third parties for the benefit of Aquila Gas Pipeline and where deemed
necessary entered into intercompany financial derivative positions, such as
swaps, futures and options, with Aquila Gas Pipeline and other affiliates to
assist them in managing their exposures. As a result, Aquila Gas Pipeline had
forward physical contracts with third parties and financial derivative positions
with Aquila Energy Marketing and its affiliates. Aquila Gas Pipeline received
the margins associated with these transactions, and Aquila Energy Marketing
charged Aquila Gas Pipeline for its share of Aquila Energy Marketing's cost to
manage Aquila Gas Pipeline's positions.
Aquila Gas Pipeline accounted for its derivative positions, both
speculative forward positions and financial derivatives, under Emerging Issues
Task Force Issue 98-10 "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities" ("EITF 98-10"). Under EITF 98-10, Aquila Gas
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Pipeline valued the derivative positions at market value with all changes being
recognized in earnings. Realized gains and losses were included in revenues,
while unrealized gains and losses were classified as such in the consolidated
statements of income. Aquila Gas Pipeline's derivative positions were classified
on its balance sheet as current or long-term price risk management assets and
liabilities based on their maturity. Although Energy Transfer is also involved
in energy marketing activities and use derivatives to manage its exposures,
Energy Transfer did not purchase the derivative positions of Aquila Gas Pipeline
when it purchased the assets of Aquila Gas Pipeline.
Effective in the fourth quarter of 2002, the Emerging Issues Task Force
issued Issue 02-03, which rescinded EITF 98-10. As a result all energy trading
derivative transactions are now governed by Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
("SFAS No. 133"). SFAS No. 133 as amended by Statement of Financial Accounting
Standards No. 138, Accounting for Certain Derivative Activities and Certain
Hedging Activities ("SFAS 138"), requires 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 market value. The statements require that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge criteria are
met. Special accounting for qualifying hedges allows a derivative's gain and
loss 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.
Energy Transfer utilizes various exchange-traded and over-the-counter
commodity financial instrument contracts to limit its exposure to margin
fluctuations in natural gas and NGL prices. These contracts consist primarily of
futures and swaps. As its financial derivative positions are typically
short-term positions, Energy Transfer has generally elected not to designate
them as hedges under SFAS No. 133, although Energy Transfer believes some of
them would qualify as hedges if they were designated as such. As a result, the
net gain or loss arising from marking to market these positions is recognized
currently in earnings.
In the course of normal operations, Energy Transfer also routinely enters
into forward physical contracts for the purchase and sale of natural gas and
NGLs along various points of its systems. These positions require physical
delivery and are treated as normal purchases and sales contracts under SFAS No.
133. Accordingly, unlike Aquila Gas Pipeline under EITF 98-10, under EITF 02-03
and SFAS No. 133, Energy Transfer does not mark these contracts to market on its
financial statements. They are accounted for at the time of delivery.
The market prices used to value forward physical contracts and financial
derivatives at Aquila Gas Pipeline and financial derivatives at Energy Transfer
reflect management's estimates considering various factors, including closing
exchange and over-the-counter quotations and the time value of the underlying
commitments. The values have been adjusted to reflect the potential impact of
liquidating a position in an orderly manner over a reasonable period of time
under existing market conditions.
Property, Plant and Equipment. Pipeline, property, plant, and equipment
are stated at cost. Maintenance capital expenditures are capital expenditures
made to replace partially or fully depreciated assets in order to maintain the
existing operating capacity of Energy Transfer's assets and to extend their
useful lives. Maintenance capital expenditures also include capital expenditures
made to connect additional wells to Energy Transfer's systems in order to
maintain or increase throughput on its existing assets. Expansion capital
expenditures are capital expenditures made to expand the existing operating
capacity of its assets, whether through construction or acquisition. Energy
Transfer treats repair and maintenance expenditures that do not extend the
useful life of existing assets as operating expenses as Energy Transfer incurs
them. Upon disposition or retirement of pipeline components or gas plant
components, any gain or loss is recorded to accumulated depreciation. When
entire pipeline systems, gas plants or other property and equipment are retired
or sold, any gain or loss is included in operations.
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Depreciation of the pipeline systems, gas plants and processing equipment
is provided using the straight-line method based on an estimated useful life of
primarily twenty years. The Oasis Pipeline is depreciated based on an estimated
useful life of sixty-five years.
Energy Transfer reviews its assets for impairment whenever facts and
circumstances indicate impairment may be present. When impairment indicators are
present, Energy Transfer evaluates whether the assets in question are able to
generate sufficient cash flows to recover their carrying value on an
undiscounted basis. If not, Energy Transfer impairs the assets to the fair
value, which may be determined based on discounted cash flows.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
HERITAGE PROPANE PARTNERS
Interest Rate Exposure. We have little cash flow exposure due to interest
rate changes for long-term debt obligations. We had $51.4 million of variable
rate debt outstanding as of August 31, 2003. The variable rate debt consists of
the bank credit facility described elsewhere in this report. The balance in the
bank credit facility generally fluctuates throughout the year. A theoretical
change of 1% in the interest rate on the balance outstanding at August 31, 2003
would result in an approximate $514 thousand change in net income. We primarily
incur debt obligations to support general corporate purposes including capital
expenditures and working capital needs. Our long-term debt instruments are
typically issued at fixed interest rates. When these debt obligations mature, we
may refinance all or a portion of such debt at then-existing market interest
rates which may be more or less than the interest rates on the maturing debt.
Commodity price risk arises from the risk of price changes in the propane
inventory that we buy and sell. The market price of propane is often subject to
volatile changes as a result of supply or other market conditions over which we
have no control. In the past, price changes have generally been passed along to
our customers to maintain gross margins, mitigating the commodity price risk. In
order to help ensure adequate supply sources are available to us during periods
of high demand, we at times will purchase significant volumes of propane during
periods of low demand, which generally occur during the summer months, at the
then current market price, for storage both at our customer service locations
and in major storage facilities and for future resale.
Propane Hedging. We also attempt to minimize the effects of market price
fluctuations for our propane supply by entering into certain financial
contracts. In order to manage a portion of our propane price market risk, we use
contracts for the forward purchase of propane, propane fixed-price supply
agreements and derivative commodity instruments such as price swap and option
contracts. The swap instruments are a contractual agreement to exchange
obligations of money between the buyer and seller of the instruments as propane
volumes during the pricing period are purchased. The swaps are tied to a fixed
price bid by the buyer and a floating price determination for the seller based
on certain indices at the end of the relevant trading period. We have entered
into these swap instruments in the past to hedge the projected propane volumes
to be purchased during each of the one-month periods during the projected
heating season.
At August 31, 2003, we had no outstanding propane hedges. We continue to
monitor propane prices and may enter into additional propane hedges in the
future. Inherent in the portfolio from our liquids marketing activities are
certain business risks, including market risk and credit risk. Market risk is
the risk that the value of the portfolio will change, either favorably or
unfavorably, in response to changing market conditions. Credit risk is the risk
of loss from nonperformance by suppliers, customers, or financial counter
parties to a contract. We take an active role in managing and controlling market
and credit risk and have established control procedures, which are reviewed on
an ongoing basis. We monitor market risk through a variety of techniques,
including routine reporting to senior management. We attempt to minimize credit
risk exposure through credit policies and periodic monitoring procedures.
Liquids Marketing. We buy and sell derivative financial instruments, which
are within the scope of SFAS 133 and that are not designated as accounting
hedges. We also enter into energy trading contracts,
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which are not derivatives, and therefore are not within the scope of SFAS 133.
EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities (EITF 98-10), applied to energy trading contracts not
within the scope of SFAS 133 that were entered into prior to October 25, 2002.
The types of contracts we utilize in our liquids marketing segment include
energy commodity forward contracts, options and swaps traded on the
over-the-counter financial markets. In accordance with the provisions of SFAS
133, derivative financial instruments utilized in connection with our liquids
marketing activity are accounted for using the mark-to-market method.
Additionally, all energy trading contracts entered into prior to October 25,
2002 were accounted for using the mark-to-market method in accordance with the
provisions of EITF 98-10. Under the mark-to-market method of accounting,
forwards, swaps, options and storage contracts are reflected at fair value and
are shown in the consolidated balance sheet as assets and liabilities from
liquids marketing activities. As of August 31, 2002, we adopted the applicable
provisions of EITF Issue No. 02-3, Issues Related to Accounting for Contracts
Involved in Energy Trading and Risk Management Activities (EITF 02-3), which
requires that gains and losses on derivative instruments be shown net in the
statement of operations if the derivative instruments are held for trading
purposes. Net realized and unrealized gains and losses from the financial
contracts and the impact of price movements are recognized in the statement of
operations as liquids marketing revenue. Changes in the assets and liabilities
from the liquids marketing activities result primarily from changes in the
market prices, newly originated transactions and the timing and settlement of
contracts. EITF 02-3 also rescinds EITF 98-10 for all energy trading contracts
entered into after October 25, 2002 and specifies certain disclosure
requirements. Consequently, we do not apply mark-to-market accounting for any
contracts entered into after October 25, 2002 that are not within the scope of
SFAS 133. We attempt to balance our contractual portfolio in terms of notional
amounts and timing of performance and delivery obligations. However, net
unbalanced positions can exist or are established based on management's
assessment of anticipated market movements.
The notional amounts and terms of these financial instruments as of August
31, 2003 and 2002 include fixed price payor for 45,000 and 1,180,000 barrels of
propane, respectively, and fixed price receiver of 195,000 and 1,076,900 barrels
of propane, respectively. Notional amounts reflect the volume of the
transactions, but do not represent the amounts exchanged by the parties to the
financial instruments. Accordingly, notional amounts do not accurately measure
our exposure to market or credit risks.
The fair value of the financial instruments related to liquids marketing
activities as of August 31, 2003 and 2002 was assets of $83 thousand and $2.3
million, respectively, and liabilities of $80 thousand and $1.8 million,
respectively.
Sensitivity Analysis. Estimates related to our liquids marketing
activities are sensitive to uncertainty and volatility inherent in the energy
commodities markets and actual results could differ from these estimates. A
theoretical change of 10% in the underlying commodity value of the liquids
marketing contracts would result in an approximate $345 thousand change in the
market value of the contracts as there were approximately 6.3 million gallons of
net unbalanced positions at August 31, 2003.
Disclosures about Liquids Marketing Activities Accounted for at Fair
Value. The following table summarizes the fair value of our contracts,
aggregated by method of estimating fair value of the contracts as of August 31,
2003 and 2002, where settlement had not yet occurred. Our contracts all have a
maturity of less than 1 year. The market prices used to value these transactions
reflect management's best estimate
S-53
considering various factors including closing average spot prices for the
current and outer months plus a differential to consider time value and storage
costs.
<Table>
<Caption>
AUGUST 31, AUGUST 31,
SOURCE OF FAIR VALUE 2003 2002
- -------------------- ---------- ----------
(IN THOUSANDS)
Prices actively quoted...................................... $80 $1,276
Prices based on other valuation methods..................... 3 1,025
--- ------
Assets from liquids marketing............................. $83 $2,301
=== ======
Prices actively quoted...................................... $80 $ 669
Prices based on other valuation methods..................... -- 1,149
--- ------
Liabilities from liquids marketing........................ $80 $1,818
=== ======
Unrealized gains............................................ $ 3 $ 483
=== ======
</Table>
The following table summarizes the changes in the unrealized fair value of
our contracts where settlement had not yet occurred for the fiscal years ended
August 31, 2003, 2002 and 2001.
<Table>
<Caption>
AUGUST 31, AUGUST 31, AUGUST 31,
2003 2002 2001
---------- ---------- ----------
(IN THOUSANDS)
Unrealized gains (losses) in fair value of contracts
outstanding at the beginning of the period.......... $ 483 $(665) $ 591
Unrealized gains (losses) recognized at inception of
contracts........................................... -- -- --
Unrealized gains (losses) recognized as a result of
changes in valuation techniques and assumptions..... -- -- --
Other unrealized gains (losses) recognized during the
period.............................................. 850 1,207 250
Less: Realized gains (losses) recognized during the
period.............................................. 1,330 59 1,506
------ ----- ------
Unrealized gains (losses) in fair value of contracts
outstanding at the end of the period................ $ 3 $ 483 $ (665)
====== ===== ======
</Table>
ENERGY TRANSFER
Energy Transfer's primary market risk is commodity price risk. Commodity
price risk is present in Energy Transfer's inventory and exchange positions,
Energy Transfer's forward physical contracts and commodity derivative positions.
Energy Transfer's inventory and exchange position is generally not material
and the imbalances turn over monthly. Inventory imbalances generally arise when
actual volumes delivered differ from nominated amounts or due to other timing
differences. Energy Transfer attempts to balance its purchases and sales each
month to prevent inventory imbalances from occurring and if necessary attempts
to clear any imbalance that arises in the following month. As a result, the
volumes involved are generally not significant and turn over quickly. Because
Energy Transfer believes that the cost approximates the market value at the end
of each month, Energy Transfer has adopted a policy of valuing inventory and
imbalances at market value at the end of each month.
Energy Transfer enters into forward physical commitments as a convenience
to its customers or to take advantage of market opportunities. Energy Transfer
generally attempts to mitigate any market exposure to its forward commitments by
either entering into offsetting forward commitments or financial derivative
positions.
Energy Transfer enters into commodity derivative contracts to manage its
exposure to commodity prices for both natural gas and NGLs.
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The following summarizes Energy Transfer's open commodity derivative
positions:
<Table>
<Caption>
NOTIONAL
BASIS VOLUME ENERGY TRANSFER ENERGY TRANSFER
SWAPS COMMODITY MMBTU MATURITY PAYS RECEIVES FAIR VALUE
- ----- --------- ---------- -------- --------------- --------------- ----------
HSC Gas 6,865,000 2003 Nymex IFERC $ (250,650)
Gas 14,870,000 2003 IFERC Nymex 1,000,713
HSC Gas 900,000 2004 Nymex IFERC 2,250
Gas 450,000 2004 IFERC Nymex (1,125)
Waha Gas 2,400,000 2003 Nymex IFERC 64,200
Gas 7,230,000 2003 IFERC Nymex (325,525)
Waha Gas -- 2004 Nymex IFERC --
Gas 1,780,000 2004 IFERC Nymex (62,300)
----------
$ 427,563
==========
</Table>
<Table>
<Caption>
NOTIONAL AVERAGE
LONG/ VOLUME STRIKE
FUTURES COMMODITY SHORT MMBTU MATURITY PRICE FAIR VALUE
- ------- --------- ----- --------- -------- ------- ----------
Gas Long 3,085,000 2003 $4.979 $(52,970)
Gas Short 5,910,000 2003 $5.039 533,865
Gas Short 60,000 2004 $5.285 7,480
Gas Long 30,000 2004 $5.257 (2,890)
--------
$485,485
========
</Table>
Energy Transfer is exposed to market risk for changes in interest rates
related to its term note. An interest rate swap agreement is used to manage a
portion of the exposure to changing interest rates by converting floating rate
debt to fixed-rate debt. The interest rate swap has a notional value of $75
million and is tied to the maturity of the term note. Under the terms of the
interest rate swap agreement, Energy Transfer pays a fixed rate of 2.76% and
receives three-month LIBOR. Management has elected not to designate the swap as
a hedge for accounting purposes. The fair value of the interest rate swap at
August 31, 2003 is a liability of $807,000 and has been recognized as a
component of interest expense.
Unrealized gains recognized in earnings related to Energy Transfer's
commodity derivative activities were $912,000 for the 11 months ended August 31,
2003. The realized losses on commodity derivatives, which were included in
revenue, for the 11 months ended August 31, 2003, were $2,001,000. Realized
losses on the interest rate swap included in interest expense were $312,000.
Management believes that many of its derivatives positions would qualify as
hedges if management had designated them as such for accounting purposes. Had
Energy Transfer designated its derivatives as hedges for accounting purposes, a
substantial portion of the fair value of its derivatives at August 31, 2003
would not have been recognized through earnings.
Credit Risk. Energy Transfer is diligent in attempting to ensure that it
issues credit only to credit-worthy counterparties. However, its purchase and
resale of gas exposes Energy Transfer to significant credit risk because the
margin on any sale is generally a very small percentage of the total sales
price. Therefore, a credit loss can be very large relative to Energy Transfer's
overall profitability. Historically, Energy Transfer's credit losses have not
been significant.
S-55
BUSINESS
OVERVIEW
HERITAGE PROPANE PARTNERS
We are one of the largest retail propane marketers in the United States,
serving more than 650,000 customers from over 300 customer service locations in
31 states. Our operations extend from coast to coast, with concentrations in the
western, upper midwestern, northeastern and southeastern regions of the United
States. We are also a wholesale propane supplier in the southwestern and
southeastern United States and in Canada, the latter through participation in
M-P Energy Partnership. M-P Energy Partnership is a Canadian partnership in
which we own a 60% interest, engaged in wholesale distribution and in supplying
our northern U.S. locations. We are a publicly traded Delaware limited
partnership formed in conjunction with our initial public offering in June of
1996. Our business has grown primarily through acquisitions of retail propane
operations and, to a lesser extent, through internal growth. Since our inception
through August 31, 2003, we have completed 97 acquisitions for an aggregate
purchase price of approximately $675 million. Volumes of propane sold to retail
customers have increased steadily from 63.2 million gallons for the fiscal year
ended August 31, 1992 to 375.9 million gallons for the fiscal year ended August
31, 2003.
ENERGY TRANSFER
Energy Transfer is a growth-oriented midstream natural gas company with
operations primarily located in major natural gas producing regions of Texas and
Oklahoma. Its primary assets consist of two large gathering systems in the Gulf
Coast area of Texas and western Oklahoma and the Oasis Pipeline, an intrastate
natural gas pipeline that runs from the Permian Basin in west Texas to natural
gas supply and market areas in southeast Texas.
Energy Transfer owns or has an interest in over 3,850 miles of natural gas
pipeline systems, three natural gas processing plants connected to its gathering
systems with a total processing capacity of approximately 400 MMcf/d and seven
natural gas treating facilities with a total treating capacity of approximately
425 MMcf/d.
Energy Transfer divides its operations into two primary business segments,
the Midstream segment, which consists of its natural gas gathering, compression,
treating, processing and marketing operations, and the Transportation segment,
which consists of the Oasis Pipeline.
The table set forth below contains certain information regarding the
Southeast Texas System, the Elk City System and the Oasis Pipeline.
<Table>
<Caption>
11 MONTHS ENDED
AUGUST 31, 2003
------------------------
APPROXIMATE THROUGHPUT AVERAGE UTILIZATION
LENGTH WELLS CAPACITY THROUGHPUT OF
ASSET TYPE (MILES) CONNECTED (MMCF/D) (MMCF/D) CAPACITY(%)
- ----- ---- ------- ----------- ---------- ---------- -----------
Southeast Texas Gathering and transportation
System pipelines................. 2,500 1,000 720 260 36
(Midstream) Processing facility......... -- -- 240 95 40
Treating facilities......... -- -- 250 80 32
Elk City System Gathering pipelines......... 315 300 410 170 41
(Midstream) Processing facility......... -- -- 130 95 73
Treating facilities......... -- -- 145 -- --
Oasis Pipeline Transportation pipeline..... 583 -- 1,000 830 83
(Transportation)
</Table>
Energy Transfer has announced that it intends to construct a 78-mile
pipeline that will connect natural gas supplies in east Texas to its Katy
Pipeline in Grimes County. The Bossier Pipeline will enable producers to
transport natural gas to the Katy Hub from the east Texas area. Pipeline
capacity is constrained in this area due to the ongoing drilling activity in the
Barnett Shale in north central Texas and
S-56
the Bossier Sand and other formations. Energy Transfer has secured contracts
with three separate companies to transport natural gas on this pipeline,
including a nine-year fee-based contract with XTO Energy, Inc. Under the
agreement, XTO Energy is committed to pay for firm capacity rights on the
Bossier Pipeline. That commitment gives XTO Energy the right to use capacity
averaging 200 MMcf/d. XTO Energy is obligated to pay for those firm capacity
rights whether or not the capacity is utilized thus assuring a continuing
revenue stream to the pipeline project.
The Bossier Pipeline is scheduled to be completed by mid calendar year
2004. The pipe to be used in the Bossier Pipeline is currently being
manufactured and is scheduled to be delivered to Energy Transfer in January
2004. Physical construction of the Bossier Pipeline is expected to begin March
1, 2004. In order to complete the Bossier Pipeline, Energy Transfer needs to
complete its acquisition of all necessary rights of way. Energy Transfer has
purchased approximately 50% of these rights of way. Energy Transfer has an
agreement in principle to purchase an additional 20% of the necessary rights of
way and is currently negotiating to purchase the remaining rights of way. We
anticipate that the Bossier Pipeline will require capital expenditures of
approximately $75 million to complete. Energy Transfer has incurred
approximately $1.4 million in capital expenditures associated with the
construction of the Bossier Pipeline through November 30, 2003. The timing and
cost of the completion of the Bossier Pipeline may be impacted by any unforeseen
costs or difficulties associated with the manufacture of the components of the
pipeline, the construction of the pipeline or the acquisition or condemnation of
the necessary rights of way.
BUSINESS STRATEGIES
Upon completion of the Energy Transfer transaction, we intend to operate as
a diversified, growth-oriented master limited partnership with a focus on
increasing the amount of cash available for distribution on each unit. We
believe that by pursuing independent operating and growth strategies for our
midstream and propane businesses, we will be best positioned to achieve our
objectives. We believe that our increased size as a result of the Energy
Transfer transaction will allow us to participate in growth opportunities not
currently available to us.
We expect that midstream acquisitions will be the primary focus of our
strategy going forward, however, we will also continue to pursue complementary
propane acquisitions. We anticipate that the Energy Transfer business will
provide internal growth projects of greater scale compared to those available in
our propane business. We believe the combined experience of the operational and
senior management of Heritage and Energy Transfer, both of whom will continue to
operate their respective businesses, will benefit us in achieving our growth
strategy.
MIDSTREAM BUSINESS STRATEGIES
- Growth through acquisitions. We intend to make strategic acquisitions of
midstream assets in Energy Transfer's current areas of operation that
offer the opportunity for operational efficiencies and the potential for
increased utilization and expansion of its existing and acquired assets.
We will also pursue midstream asset acquisition opportunities in other
regions of the U.S. with significant natural gas reserves and high levels
of drilling activity or with growing demand for natural gas. We believe
we will be well positioned to benefit from the additional acquisition
opportunities likely to arise as a result of the ongoing divestiture of
midstream assets by large industry participants.
- Enhance profitability of existing assets. We intend to increase the
profitability of Energy Transfer's existing asset base by adding new
volumes of natural gas, undertaking additional initiatives to enhance
utilization and reducing costs by improving operations. Recently Energy
Transfer has increased the profitability of its assets by:
- continuing to add new volumes of natural gas gathered in west Texas
under long-term producer commitments and transporting such natural gas
on the Oasis Pipeline;
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- increasing fee-based revenues and enhancing utilization by moving an
idle 145 MMcf/d treating facility from the Southeast Texas System to the
Elk City System to take advantage of additional natural gas volumes;
- reducing operating costs by blending untreated natural gas from the
Southeast Texas System with gas on the Oasis Pipeline to meet pipeline
quality specifications, which permitted Energy Transfer to shut down
treating facilities in the Southeast Texas System; and
- reducing operating costs by relocating an existing compressor to the
inlet side of the La Grange processing plant, which permitted Energy
Transfer to shut down 13 compressors in the Southeast Texas System.
- Engage in construction and expansion opportunities. We intend to
leverage Energy Transfer's existing infrastructure and customer
relationships by constructing and expanding systems to meet new or
increased demand for midstream services. These projects include expansion
of existing systems, such as the Bossier Pipeline in east Texas, and
construction of new facilities. Once completed, we expect that the
Bossier Pipeline will lead to additional growth opportunities in this
area.
- Increase cash flow from fee-based businesses. Energy Transfer generated
approximately 46% of its gross margin during the 11 months ended August
31, 2003 from fees charged for providing midstream services, including a
transportation fee Energy Transfer charges its producer services business
for natural gas that it transports on the Oasis Pipeline equal to the fee
charged to third parties. This transportation fee accounted for 7% of
total gross margin for this period. These fee-based services are
dependent on throughput volume and are typically less affected by
short-term changes in commodity prices. We intend to seek to increase the
percentage of Energy Transfer's midstream business conducted with third
parties under fee-based arrangements in order to reduce exposure to
changes in the prices of natural gas and NGLs. For example, we expect the
fee-based contracts associated with the Bossier Pipeline to significantly
increase the fee-based component of Energy Transfer's gross margin.
PROPANE BUSINESS STRATEGIES
- Growth through complementary acquisitions. We believe that our position
as one of the largest propane marketers provides us a solid foundation to
continue our acquisition growth strategy through consolidation. We
believe that the fragmented nature of the propane industry will continue
to provide opportunities for growth through the acquisition of propane
businesses that complement our existing asset base. In addition to
focusing on propane acquisition candidates in our existing areas of
operations, we will also consider core acquisitions in other
higher-than-average population growth areas in which we have no presence
in order to further reduce the impact adverse weather patterns and
economic downturns in any one region may have on our overall operations.
- Maintain low-cost, decentralized operations. We focus on controlling
costs, and we attribute our low overhead costs primarily to our
decentralized structure. By delegating all customer billing and
collection activities to the customer service location level, as well as
delegating other responsibilities to the operating level, we have been
able to operate without a large corporate staff. In addition, our
customer service location level incentive compensation program encourages
employees at all levels to control costs while increasing revenues.
- Pursue internal growth opportunities. In addition to pursuing expansion
through acquisitions, we have aggressively focused on high return
internal growth opportunities at our existing customer service locations.
We believe that by concentrating our operations in areas experiencing
higher-than-average population growth we are well positioned to achieve
internal growth by adding new customers.
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COMPETITIVE STRENGTHS
Upon the completion of the Energy Transfer transaction, we believe that we
will be well positioned to compete in both the natural gas midstream and propane
industries based on the following strengths:
MIDSTREAM BUSINESS STRENGTHS
- Energy Transfer has a significant market presence in major natural gas
supply areas. Energy Transfer has a significant market presence in each
of its operating areas, which are located in major natural gas producing
regions of the United States.
- Energy Transfer's Southeast Texas System has additional capacity, which
provides opportunities for higher levels of utilization. We expect to
connect new supplies of natural gas volumes by utilizing the available
capacity on the Southeast Texas System. The available capacity also
provides us with opportunities to extend the Southeast Texas System to
additional natural gas producing areas, such as east Texas through the
recently announced Bossier Pipeline project.
- Energy Transfer's assets provide marketing flexibility through its access
to numerous markets and customers. Energy Transfer's Oasis Pipeline
combined with its Southeast Texas System provides its customers direct
access to the Waha and Katy Hubs and to virtually all other market areas
in the United States via interconnections with major intrastate and
interstate natural gas pipelines. Furthermore, its Oasis Pipeline is tied
directly or indirectly to a number of major power generation facilities
in Texas as well as several industrial and utility end-users.
Additionally, Energy Transfer's Elk City System has direct access to six
major intrastate and interstate pipelines.
- Energy Transfer's ability to bypass its La Grange and Elk City processing
plants reduces its commodity price risk. A significant benefit of Energy
Transfer's ownership of the Oasis Pipeline is that it can elect not to
process natural gas at its La Grange processing plant when processing
margins (or the difference between NGL sales prices and the cost of
natural gas) are unfavorable. Instead of processing the natural gas,
Energy Transfer is able to deliver natural gas meeting pipeline quality
specifications by blending rich gas, or gas with a high NGL content, from
the Southeast Texas System with lean gas, or gas with a low NGL content,
transported on the Oasis Pipeline. This enables Energy Transfer to sell
the blended natural gas for a higher price than it would have been able
to realize upon the sale of NGLs if it had to process the natural gas to
extract NGLs. In addition, Energy Transfer also has the option to not
process natural gas at its Elk City processing plant because the gas
produced in this area meets pipeline quality specifications without
processing.
PROPANE BUSINESS STRENGTHS
- Experience in identifying, evaluating and completing acquisitions. Since
inception through August 31, 2003, we completed 97 propane acquisitions.
We follow a disciplined acquisition strategy that concentrates on propane
companies that (1) are located in geographic areas experiencing
higher-than-average population growth, (2) provide a high percentage of
sales to residential customers, (3) have a strong reputation for quality
service, and (4) own a high percentage of the propane tanks used by their
customers. In addition we attempt to capitalize on the reputations of the
companies we acquire by maintaining local brand names, billing practices
and employees, thereby creating a sense of continuity and minimizing
customer loss. We believe that this strategy has helped to make us an
attractive buyer for many propane acquisition candidates from the
seller's viewpoint.
- Geographically diverse retail propane network. We believe our
geographically diverse network of retail propane assets reduces our
exposure to unfavorable weather patterns and economic downturns in any
one geographic region, thereby reducing the volatility of our cash flows.
- Operations that are focused in areas experiencing higher-than-average
population growth. We believe that our concentration in
higher-than-average population growth areas provides a strong economic
foundation for expansion through acquisitions and internal growth. We do
not believe that
S-59
we are more vulnerable than our competitors to displacement by natural
gas distribution systems because the majority of our areas of operations
are located in rural areas where natural gas is not readily available.
- Low-cost administrative infrastructure. We are dedicated to maintaining
a low-cost operating profile and have a successful track record of
aggressively pursuing opportunities to reduce costs. Of the 2,418
full-time employees as of August 31, 2003, only 92, or approximately 4%,
were general and administrative.
- Decentralized operating structure and entrepreneurial workforce. We
believe that our decentralized operations foster an entrepreneurial
corporate culture by: (1) having operational decisions made at the
customer service location and operating level, (2) retaining billing,
collection and pricing responsibilities at the local and operating level,
and (3) rewarding employees for achieving financial targets at the local
level.
PROPANE INDUSTRY OVERVIEW
Propane, a by-product of natural gas processing and petroleum refining, is
a clean-burning energy source recognized for its transportability and ease of
use relative to alternative forms of stand-alone energy sources. Retail propane
use falls into three broad categories: (i) residential applications, (ii)
industrial, commercial and agricultural applications and (iii) other retail
applications, including motor fuel sales. Residential customers use propane
primarily for space and water heating. Industrial customers use propane
primarily as fuel for forklifts, stationary engines, furnaces, as a cutting gas,
in mining operations and in other process applications. Commercial customers,
such as restaurants, motels, laundries and commercial buildings, use propane in
a variety of applications, including cooking, heating and drying. In the
agricultural market, propane is primarily used for tobacco curing, crop drying,
poultry brooding and weed control. Other retail uses include motor fuel for cars
and trucks, outdoor cooking and other recreational uses, propane resales and
sales to state and local governments. In its wholesale operations, we sell
propane principally to large industrial end-users and other propane
distributors.
Propane is extracted from natural gas at processing plants or separated
from crude oil during the refining process. Propane is normally transported and
stored in a liquid state under moderate pressure or refrigeration for ease of
handling in shipping and distribution. When the pressure is released or the
temperature is increased, it is usable as a flammable gas. Propane is naturally
colorless and odorless. An odorant is added to allow its detection. Like natural
gas, propane is a clean burning fuel and is considered an environmentally
preferred energy source.
Propane competes with other sources of energy, some of which are less
costly for equivalent energy value. We compete for customers against suppliers
of electricity, natural gas and fuel oil. Competition from alternative energy
sources has been increasing as a result of reduced utility regulation. Except
for certain industrial and commercial applications, propane is generally not
competitive with natural gas in areas where natural gas pipelines already exist
because natural gas is a significantly less expensive source of energy than
propane. The gradual expansion of the nation's natural gas distribution systems
has resulted in the availability of natural gas in many areas that previously
depended upon propane. Although the extension of natural gas pipelines tends to
displace propane distribution in areas affected, we believe that new
opportunities for propane sales arise as more geographically remote
neighborhoods are developed. Even though propane is similar to fuel oil in
certain applications and market demand, propane and fuel oil compete to a lesser
extent primarily because of the cost of converting from one to another. Based
upon industry publications, propane accounts for three to four percent of
household energy consumption in the United States.
In addition to competing with alternative energy sources, we compete with
other companies engaged in the retail propane distribution business. Competition
in the propane industry is highly fragmented and generally occurs on a local
basis with other large multi-state propane marketers, thousands of smaller local
independent marketers and farm cooperatives. Most of our customer service
locations compete with five or more marketers or distributors. Each retail
distribution outlet operates in its own competitive environment
S-60
because retail marketers tend to locate in close proximity to customers. The
typical retail distribution outlet generally has an effective marketing radius
of approximately 50 miles although in certain rural areas the marketing radius
may be extended by satellite locations.
The ability to compete effectively further depends on the reliability of
service, responsiveness to customers and the ability to maintain competitive
prices. We believe that our safety programs, policies and procedures are more
comprehensive than many of its smaller, independent competitors and give us a
competitive advantage over such retailers. We also believe that our service
capabilities and customer responsiveness differentiate us from many of these
smaller competitors. Our employees are on call 24-hours-a-day, 7-days-a-week for
emergency repairs and deliveries.
The wholesale propane business is highly competitive. For fiscal year 2003,
our domestic wholesale operations (excluding M-P Energy Partnership) accounted
for only 3.9% of our total gallons sold in the United States and approximately
1% of our gross profit. We do not emphasize wholesale operations, but we believe
that limited wholesale activities enhance our ability to supply our retail
operations.
MIDSTREAM NATURAL GAS INDUSTRY OVERVIEW
The midstream natural gas industry is the link between the exploration and
production of natural gas and the delivery of its components to end-use markets
and consists of natural gas gathering, compression, treating, processing and
transportation and NGL fractionation and transportation. The midstream industry
is generally characterized by regional competition based on the proximity of
gathering systems and processing plants to natural gas producing wells.
The following diagram illustrates the natural gas gathering, compression,
treating, processing, fractionation and transportation processes.
[GRAPH]
Demand for natural gas. Natural gas continues to be a critical component
of energy consumption in the United States. According to the Energy Information
Administration, or the EIA, total domestic consumption of natural gas is
expected to increase by over 2.2% per annum, on average, to 27.1 Tcf by 2010,
from an estimated 22.2 Tcf consumed in 2001, representing approximately 25% of
all total end-user energy requirements by 2010. During the last five years, the
United States has on average consumed approximately 22.6 Tcf per year, with
average domestic production of approximately 19.1 Tcf per year during the same
period. The industrial and electricity generation sectors currently account for
the largest usage of natural gas in the United States.
Natural gas reserves and production. As of December 31, 2001, operators in
the United States had 183.5 Tcf of proved "lean" natural gas reserves and 191.7
Tcf of proved "rich" natural gas reserves. Natural gas is described as lean or
rich depending on its content of heavy components or liquids content. These are
relative terms, but as generally used, rich gas may contain as much as five to
six gallons or
S-61
more of NGLs per Mcf, whereas lean gas usually contains less than one gallon of
NGLs per Mcf. Driven by growth in natural gas demand, the EIA projects that
domestic natural gas production is projected to increase from 19.7 Tcf per year
to 21.9 Tcf per year between 2001 and 2010. According to the EIA, in 2001,
Texas, Louisiana and Oklahoma represented the first, second and fourth largest
states, respectively, in terms of domestic natural gas production.
Natural gas gathering. The natural gas gathering process begins with the
drilling of wells into gas bearing rock formations. Once a well has been
completed, the well is connected to a gathering system. Gathering systems
generally consist of a network of small diameter pipelines and, if necessary,
compression systems that collect natural gas from points near producing wells
and transport it to larger pipelines for further transportation.
Natural gas compression. Gathering systems are operated at design
pressures that will maximize the total throughput from all connected wells.
Specifically, lower pressure gathering systems allow wells, which produce at
progressively lower field pressures as they age, to remain connected to
gathering systems and continue to produce for longer periods of time. As the
pressure of a well declines, it becomes increasingly more difficult to deliver
the remaining production in the ground against a higher pressure that exists in
the connecting gathering system. Field compression is typically used to lower
the pressure of a gathering system. If field compression is not installed, then
the remaining production in the ground will not be produced because it cannot
overcome the higher gathering system pressure. In contrast, if field compression
is installed, then a well can continue delivering production that otherwise
would not be produced.
Natural gas treating. Natural gas has a varied composition depending on
the field, the formation and the reservoir from which it is produced. Natural
gas from certain formations is high in carbon dioxide, hydrogen sulfide or
certain other contaminants. Treating plants remove carbon dioxide and hydrogen
sulfide from natural gas to ensure that it meets pipeline quality
specifications.
Natural gas processing. Some natural gas produced by a well does not meet
pipeline quality specifications or is not suitable for commercial use and must
be processed to remove the mixed NGL stream. In addition, some natural gas
produced by a well, while not required to be processed, can be processed to take
advantage of favorable processing margins. Natural gas processing involves the
separation of natural gas into pipeline quality natural gas, or residue gas, and
a mixed NGL stream.
Natural gas fractionation. NGL fractionation facilities separate mixed NGL
streams into discrete NGL products: ethane, propane, isobutane, normal butane
and natural gasoline. Ethane is primarily used in the petrochemical industry as
feedstock for ethylene, one of the basic building blocks for a wide range of
plastics and other chemical products. Isobutane is fractionated from mixed
butane (a stream of normal butane and isobutane in solution) or refined from
normal butane through the process of isomerization, principally for use to
enhance the octane content of motor gasoline. Normal butane is used as a
petrochemical feedstock in the production of ethylene and butadiene (a key
ingredient in synthetic rubber), as a blendstock for motor gasoline and to
derive isobutane through isomerization. Natural gasoline, a mixture of pentanes
and heavier hydrocarbons, is used primarily as motor gasoline blend stock or
petrochemical feedstock. Energy Transfer does not own or operate fractionation
facilities.
Natural gas transportation. Natural gas transportation pipelines receive
natural gas from other mainline transportation pipelines and gathering systems
and deliver the natural gas to industrial end-users, utilities and other
pipelines.
HERITAGE PROPANE PARTNERS
PRODUCTS, SERVICES AND MARKETING
We distribute propane through a nationwide retail distribution network
consisting of over 300 customer service locations in 31 states. Our operations
are concentrated in large part in the western, upper midwestern, northeastern
and southeastern regions of the United States. We serve more than 650,000 active
customers. Historically, approximately two-thirds of our retail propane volumes
and in excess of 80%
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of our EBITDA, as adjusted, were attributable to sales during the six-month
peak-heating season from October through March, as many customers use propane
for heating purposes. Consequently, sales and operating profits are normally
concentrated in the first and second fiscal quarters, while cash flows from
operations are generally greatest during the second and third fiscal quarters
when customers pay for propane purchased during the six-month peak season. To
the extent necessary, we will reserve cash from peak periods for distribution to
unitholders during the warmer seasons.
Typically, customer service locations are found in suburban and rural areas
where natural gas is not readily available. Generally, such locations consist of
a one to two acre parcel of land, an office, a small warehouse and service
facility, a dispenser and one or more 18,000 to 30,000 gallon storage tanks.
Propane is generally transported from refineries, pipeline terminals, leased
storage facilities and coastal terminals by rail or truck transports to our
customer service locations where it is unloaded into storage tanks. In order to
make a retail delivery of propane to a customer, a bobtail truck is loaded with
propane from the storage tank. Propane is then delivered to the customer by the
bobtail truck, which generally holds 2,500 to 3,000 gallons of propane, and
pumped into a stationary storage tank on the customer's premises. The capacity
of these customer tanks ranges from approximately 100 gallons to 1,200 gallons,
with a typical tank capacity of 100 to 300 gallons in milder climates and from
500 to 1,000 gallons in colder climates. We also deliver propane to retail
customers in portable cylinders, which typically have a capacity of 5 to 35
gallons. When these cylinders are delivered to customers, empty cylinders are
picked up for refilling at our distribution locations or are refilled on site.
We also deliver propane to certain other bulk end-users of propane in
tractor-trailer transports, which typically have an average capacity of
approximately 10,500 gallons. End-users receiving transport deliveries include
industrial customers, large-scale heating accounts, mining operations and large
agricultural accounts.
We encourage our customers whose propane needs are temperature sensitive to
implement a regular delivery schedule. Many of our residential customers receive
their propane supply pursuant to an automatic delivery system which eliminates
the customer's need to make an affirmative purchase decision and allows for more
efficient route scheduling. We also sell, install and service equipment related
to our propane distribution business, including heating and cooking appliances.
We own, through our subsidiaries, a 60% interest in M-P Energy Partnership,
a Canadian partnership that supplies us with propane as described below under
"Propane Supply and Storage."
Approximately 96% of the domestic gallons we sold in the fiscal year ended
August 31, 2003 were to retail customers and 4% were to wholesale customers. Of
the retail gallons we sold, 60% were to residential customers, 25% were to
industrial, commercial and agricultural customers, and 15% were to other retail
users. Sales to residential customers in the fiscal year ended August 31, 2003
accounted for 58% of total domestic gallons sold but accounted for approximately
72% of our gross profit from propane sales. Residential sales have a greater
profit margin and a more stable customer base than the other markets we serve.
Industrial, commercial and agricultural sales accounted for 18% of our gross
profit from propane sales for the fiscal year ended August 31, 2003, with all
other retail users accounting for 9%. Additional volumes sold to wholesale
customers contributed 1% of our gross profit from propane sales. No single
customer accounts for 10% or more of revenues.
The propane business is very seasonal with weather conditions significantly
affecting demand for propane. We believe that the geographic diversity of our
operations helps to reduce our overall exposure to less than favorable weather
conditions in any particular region of the United States. Although overall
demand for propane is affected by climate, changes in price and other factors,
we believe our residential and commercial business to be relatively stable due
to the following characteristics:
- residential and commercial demand for propane has been relatively
unaffected by general economic conditions due to the largely
non-discretionary nature of most propane purchases,
- loss of customers to competing energy sources has been low due to the
lack of availability or the high cost of alternative fuels,
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- the tendency of our customers to remain with us due to the product being
delivered pursuant to a regular delivery schedule and to our ownership of
90% of the storage tanks utilized by our customers, which prevents fuel
deliveries from competitors, and
- our historic ability to more than offset customer losses through internal
growth of our customer base in existing markets.
Since home heating usage is the most sensitive to temperature, residential
customers account for the greatest usage variation due to weather. Variations in
the weather in one or more regions in which we operate can significantly affect
the total volumes of propane that we sell and the margins realized thereon and,
consequently, our results of operations. We believe that sales to the commercial
and industrial markets, while affected by economic patterns, are not as
sensitive to variations in weather conditions as sales to residential and
agricultural markets.
PROPANE SUPPLY AND STORAGE
Supplies of propane from our sources historically have been readily
available. We purchase from over 50 energy companies and natural gas processors
at numerous supply points located in the United States and Canada. In the fiscal
year ended August 31, 2003, Enterprise Products Operating L.P. ("Enterprise")
and Dynegy Liquids Marketing and Trade ("Dynegy") provided approximately 29% and
13% of our total propane supply, respectively. In addition, M-P Oils, Ltd., our
wholly owned subsidiary that owns a 60% interest in M-P Energy Partnership, a
Canadian partnership, procured 19% of our total propane supply during the fiscal
year ended August 31, 2003 through M-P Energy Partnership. M-P Energy
Partnership buys and sells propane for its own account and supplies propane to
us for our northern United States operations.
We believe that if supplies from Enterprise and Dynegy were interrupted we
would be able to secure adequate propane supplies from other sources without a
material disruption of our operations. Aside from Enterprise, Dynegy and the
supply procured by M-P Oils, Ltd., no single supplier provided more than 10% of
our total domestic propane supply during the fiscal year ended August 31, 2003.
We believe that our diversification of suppliers will enable us to purchase all
of our supply needs at market prices without a material disruption of our
operations if supplies are interrupted from any of our existing sources.
Although no assurances can be given that supplies of propane will be readily
available in the future, we expect a sufficient supply to continue to be
available. However, increased demand for propane in periods of severe cold
weather, or otherwise, could cause future propane supply interruptions or
significant volatility in the price of propane.
We typically enter into one-year supply agreements. The percentage of
contract purchases may vary from year to year. Supply contracts generally
provide for pricing in accordance with posted prices at the time of delivery or
the current prices established at major delivery or storage points, and some
contracts include a pricing formula that typically is based on these market
prices. Most of these agreements provide maximum and minimum seasonal purchase
guidelines. We receive our supply of propane predominately through railroad tank
cars and common carrier transport.
Because our profitability is sensitive to changes in wholesale propane
costs, we generally seek to pass on increases in the cost of propane to
customers. We have generally been successful in maintaining retail gross margins
on an annual basis despite changes in the wholesale cost of propane, but there
is no assurance that we will always be able to pass on product cost increases
fully, particularly when product costs rise rapidly. Consequently, our
profitability will be sensitive to changes in wholesale propane prices. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Overview."
We lease space in larger storage facilities in New York, Georgia, Michigan,
South Carolina, Arizona, New Mexico, Texas, Alberta, Canada and smaller storage
facilities in other locations and have the opportunity to use storage facilities
in additional locations when we "pre-buy" product from sources having such
facilities. We believe that we have adequate third party storage to take
advantage of supply
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purchasing advantages as they may occur from time to time. Access to storage
facilities allows us to buy and store large quantities of propane during periods
of low demand, which generally occur during the summer months, or at favorable
prices, thereby helping to ensure a more secure supply of propane during periods
of intense demand or price instability.
PRICING POLICY
Pricing policy is an essential element in the marketing of propane. We rely
on regional management to set prices based on prevailing market conditions and
product cost, as well as local management input. All regional managers are
advised regularly of any changes in the posted price of each customer service
location's propane suppliers. In most situations, we believe that our pricing
methods will permit us to respond to changes in supply costs in a manner that
protects our gross margins and customer base, to the extent such protection is
possible. In some cases, however, our ability to respond quickly to cost
increases could occasionally cause our retail prices to rise more rapidly than
those of our competitors, possibly resulting in a loss of customers.
BILLING AND COLLECTION PROCEDURES
Customer billing and account collection responsibilities are retained at
the local customer service locations. We believe that this decentralized
approach is beneficial for several reasons:
- the customer is billed on a timely basis;
- the customer is more apt to pay a "local" business;
- cash payments are received more quickly; and
- local personnel have a current account status available to them at all
times to answer customer inquiries.
GOVERNMENT REGULATION
We are subject to various federal, state and local environmental, health
and safety laws and regulations. Generally, these laws impose limitations on the
discharge of pollutants and establish standards for the handling of solid and
hazardous wastes. These laws include, without limitation, the Resource
Conservation and Recovery Act, the Comprehensive Environmental Response,
Compensation and Liability Act of 1980, as amended ("CERCLA"), the Clean Air
Act, the Occupational Safety and Health Act, the Emergency Planning and
Community Right-to-Know Act, the Clean Water Act and comparable state statutes.
CERCLA, also known as the "Superfund" law, imposes joint and several liability
in most instances, 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 or threatened release of a "hazardous substance" into the
environment. Propane is not a hazardous substance within the meaning of CERCLA.
However, certain automotive waste products generated by our truck fleet, as well
as "hazardous substances" or "hazardous waste" disposed of during past
operations by third parties on our properties, could subject us to liability
under CERCLA. Such laws and regulations could result in civil or criminal
penalties in cases of non-compliance and impose liability for remediation costs.
In addition, third parties may make claims against owners or operators of
properties for personal injuries and property damage associated with releases of
hazardous or toxic substances or waste.
In connection with all acquisitions of retail propane businesses that
involve the acquisition of any interests in real estate, we conduct an
environmental review in an attempt to determine whether any substance other than
propane has been sold from, or stored on, any such real estate prior to its
purchase. Such review includes questioning the seller, obtaining representations
and warranties concerning the seller's compliance with environmental laws and
conducting inspections of the properties. Where warranted, independent
environmental consulting firms are hired to look for evidence of hazardous
substances or the existence of underground storage tanks.
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Petroleum-based contamination or environmental wastes are known to be
located on or adjacent to six sites, which we presently have or which we or our
predecessors formerly had operations. These sites were evaluated at the time of
their acquisition. In all cases, remediation operations have been or will be
undertaken by others, and in all six cases, we obtained indemnification for
expenses associated with any remediation from the former owners or related
entities. We have not been named as a potentially responsible party at any of
these sites, nor have our operations contributed to the environmental issues at
these sites. Accordingly, no amounts have been recorded in our August 31, 2003
or 2002 consolidated balance sheets for any liability that may be attributable
to any required remediation. Based on information currently available to us,
such projects are not expected to have a material adverse effect on our
financial condition or results of operations.
In July 2001, we acquired a company that had previously received a request
for information from the Environmental Protection Agency (the "EPA") regarding
potential contribution to a widespread groundwater contamination problem in San
Bernardino, California, known as the Newmark Groundwater Contamination. Although
the EPA has indicated that the groundwater contamination may be attributable to
releases of solvents from a former military base located within the subject area
that occurred long before the facility acquired by us was constructed, it is
possible that the EPA may seek to recover all or a portion of groundwater
remediation costs from private parties under CERCLA. Based upon information
currently available to us, it is not believed that our liability, if such action
were to be taken by the EPA, would have a material adverse effect on our
financial condition or results of operations.
National Fire Protection Association Pamphlets No. 54 and No. 58, which
establish rules and procedures governing the safe handling of propane, or
comparable regulations, have been adopted as the industry standard in all of the
states in which we operate. In some states these laws are administered by state
agencies, and in others they are administered on a municipal level. With respect
to the transportation of propane by truck, we are subject to regulations
promulgated under the Federal Motor Carrier Safety Act. These regulations cover
the transportation of hazardous materials and are administered by the United
States Department of Transportation. We conduct ongoing training programs to
help ensure that our operations are in compliance with applicable regulations.
We maintain various permits that are necessary to operate our facilities, some
of which may be material to our operations. We believe that the procedures
currently in effect at all of our facilities for the handling, storage, and
distribution of propane are consistent with industry standards and are in
compliance in all material respects with applicable laws and regulations.
We have implemented environmental programs and policies designed to avoid
potential liability and cost under applicable environmental laws. It is
possible, however, that we will have increased costs due to stricter pollution
control requirements or liabilities resulting from non-compliance with operating
or other regulatory permits. It is not anticipated that our compliance with or
liabilities under environmental, health and safety laws and regulations,
including CERCLA, will have a material adverse effect on us. To the extent that
there are any environmental liabilities unknown to us or environmental, health
and safety laws or regulations are made more stringent, there can be no
assurance that our results of operations will not be materially and adversely
affected.
EMPLOYEES
As of August 31, 2003, we had 2,418 full time employees who were employed
by our general partner or our subsidiaries, of whom 92 were general and
administrative and 2,326 were operational employees. Of our operational
employees, 57 are represented by labor unions. Our general partner believes that
its relations with its employees are satisfactory. Historically, our general
partner has also hired seasonal workers to meet peak winter demands.
TITLE TO PROPERTIES
We operate bulk storage facilities at nearly 300 customer service
locations. We own substantially all of these facilities and have entered into
long-term leases for those that we do not own. We believe that the increasing
difficulty associated with obtaining permits for new propane distribution
locations makes our
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high level of site ownership and control a competitive advantage. We own
approximately 34 million gallons of above ground storage capacity at our various
plant sites and have leased an aggregate of approximately 50 million gallons of
underground storage facilities in New York, Georgia, Michigan, South Carolina,
Arizona, New Mexico, Texas and Alberta, Canada. We do not own or operate any
underground storage facilities (excluding customer and local distribution tanks)
or propane pipeline transportation assets (other than local delivery systems).
Prior to January 2004, we owned a 50% interest in Bi-State Propane, a
California general partnership that conducts business in California and Nevada.
Bi-State Propane operates twelve customer service locations that were included
on a gross basis in our site, customer and other property descriptions contained
herein. However, our 50% interest was accounted for under the equity method. In
January 2004, our subsidiary, Heritage Bi-State, L.L.C., acquired 100% of the
assets of Bi-State Propane and continues to conduct those operations under the
tradename Bi-State Propane.
The transportation of propane requires specialized equipment. The trucks
and railroad tank cars used for this purpose carry specialized steel tanks that
maintain the propane in a liquefied state. As of August 31, 2003, we utilized
approximately 52 transport truck tractors, 50 transport trailers, 12 railroad
tank cars, 1,063 bobtails and 1,749 other delivery and service vehicles, all of
which we own. As of August 31, 2003, we owned approximately 625,000 customer
storage tanks with typical capacities of 120 to 1,000 gallons that are leased or
available for lease to customers. These customer storage tanks are pledged as
collateral to secure our obligations to our banks and the holders of our notes.
We believe that we have satisfactory title to or valid rights to use all of
our material properties. Although some of such properties are subject to
liabilities and leases, liens for taxes not yet due and payable, encumbrances
securing payment obligations under non-competition agreements and immaterial
encumbrances, easements and restrictions, we do not believe that any such
burdens will materially interfere with our continued use of such properties in
our business, taken as a whole. In addition, we believe that we have, or are in
the process of obtaining, all required material approvals, authorizations,
orders, licenses, permits, franchises and consents of, and have obtained or made
all required material registrations, qualifications and filings with, the
various state and local government and regulatory authorities which relate to
ownership of our properties or the operations of our business.
We utilize a variety of trademarks and tradenames that we own or have
secured the right to use, including "Heritage Propane." These trademarks and
tradenames have been registered or are pending registration before the United
States Patent and Trademark Office or the various jurisdictions in which the
marks or tradenames are used. We believe that our strategy of retaining the
names of the companies we have acquired has maintained the local identification
of these companies and has been important to the continued success of these
businesses. Some of our most significant trade names include AGL Propane,
Balgas, Bi-State Propane, Blue Flame Gas of Charleston, Blue Flame Gas of Mt.
Pleasant, Blue Flame Gas, Carolane Propane Gas, Gas Service Company, EnergyNorth
Propane, Gibson Propane, Guilford Gas, Holton's L.P. Gas, Ikard & Newsom,
Northern Energy, Sawyer Gas, Peoples Gas Company, Piedmont Propane Company,
ProFlame, Rural Bottled Gas and Appliance, ServiGas, V-1 Propane and TECO
Propane. We regard our trademarks, tradenames and other proprietary rights as
valuable assets and believe that they have significant value in the marketing of
our products.
LEGAL PROCEEDINGS
Propane is a flammable, combustible gas. Serious personal injury and
significant property damage can arise in connection with its storage,
transportation or use. In the ordinary course of business, we are sometimes
threatened with or are named as a defendant in various lawsuits seeking actual
and punitive damages for product liability, personal injury and property damage.
We maintain liability insurance with insurers in amounts and with coverages and
deductibles we believe are reasonable and prudent, and which are generally
accepted in the industry. However, there can be no assurance that the levels of
insurance protection currently in effect will continue to be available at
reasonable prices or that such levels will remain adequate to protect us from
material expenses related to product liability, personal injury or
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property damage in the future. Of the pending or threatened matters in which we
are a party, none have arisen outside the ordinary course of business except for
an action filed by us on November 30, 1999, that is currently pending in the
Court of Common Pleas, State of South Carolina, Richland County, against SCANA
Corporation, Cornerstone Ventures, L.P. and Suburban Propane, L.P. (the "SCANA
litigation"). We have asserted under a number of contract and fraud causes of
action that SCANA litigation defendants materially breached its contract with us
to sell its assets to us and are seeking an unspecified amount of compensatory
and punitive damages. The defendants have denied the claims and discovery is
ongoing. Although any litigation is inherently uncertain, based on past
experience, the information currently available and the availability of
insurance coverage, we do not believe that pending or threatened litigation
matters will have a material adverse effect on our financial condition or
results of operations.
ENERGY TRANSFER
THE MIDSTREAM SEGMENT
The Midstream business segment consists of Energy Transfer's natural gas
gathering, compression, treating, processing and marketing operations. This
segment consists of the Southeast Texas System, the Elk City System, certain
other assets in east Texas and Louisiana and Energy Transfer's marketing
business.
Southeast Texas System
A map representing the location of the Southeast Texas System is set forth
below:
[MAP OF SOUTHEAST TEXAS SYSTEM]
General. The Southeast Texas System is a large natural gas gathering
system in the Gulf Coast area of Texas, covering 13 counties between Austin and
Houston. The system consists of approximately 2,500 miles of natural gas
gathering and transportation pipelines, ranging in size from two inches to 30
inches in diameter, the La Grange processing plant and five natural gas treating
facilities. The system has a capacity of approximately 720 MMcf/d and average
throughput on the system was approximately 260 MMcf/d for the 11 months ended
August 31, 2003. Thirty-two compressor stations are located within the system,
comprised of 54 units with an aggregate of approximately 42,000 horsepower.
Energy Transfer recently relocated an existing compressor to the inlet side of
the La Grange processing plant, permitting Energy Transfer to shut down 13
compressors on the gathering system and lower its operating cost.
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The Southeast Texas System includes the Katy Pipeline and the La Grange
residue line. Energy Transfer's Katy Pipeline is a 55-mile pipeline that
connects the Southeast Texas System to the Oasis Pipeline at the Katy Hub and to
a third-party storage facility and provides transportation services for gas
customers from east and southeast Texas to Katy, Texas. The La Grange residue
line connects the outlet side of the La Grange processing plant to the Oasis
Pipeline, as well as two natural gas fired power plants.
The La Grange processing plant is a cryogenic natural gas processing plant
that processes the rich natural gas that flows through Energy Transfer's system
to produce residue gas and NGLs. The plant has a processing capacity of
approximately 240 MMcf/d. During the 11 months ended August 31, 2003, the
facility processed approximately 95 MMcf/d of natural gas and produced
approximately 9,000 Bbls/d of NGLs.
The Southeast Texas System also includes five natural gas treating
facilities with aggregate capacity of approximately 250 MMcf/d. Energy
Transfer's treating facilities remove carbon dioxide and hydrogen sulfide from
natural gas that is gathered into its system before the natural gas is
introduced to transportation pipelines to ensure that it meets pipeline quality
specifications. Four of its treating facilities are amine treating facilities.
The amine treating process involves a continuous circulation of a liquid
chemical called amine that physically contacts with the natural gas. Amine has a
chemical affinity for hydrogen sulfide and carbon dioxide that allows it to
absorb the impurities from the natural gas. Energy Transfer's remaining treating
facility is a hydrogen sulfide scavenger facility. This facility uses a liquid
or solid chemical that reacts with hydrogen sulfide thereby removing it from the
natural gas.
Natural Gas Supply. Energy Transfer currently has approximately 1,000
wells connected to the Southeast Texas System. Approximately 90% of these wells
are connected to the western portion of this system, which is located in an area
that produces rich natural gas that can be processed and which accounted for
approximately 56% of Energy Transfer's throughput on the system for the 11
months ended August 31, 2003. Lean natural gas is generally produced on the
eastern portion of the system. The natural gas supplied to the Southeast Texas
System is generally dedicated to Energy Transfer under individually negotiated
long-term contracts that provide for the commitment by the producer of all
natural gas produced from designated properties. Generally, the initial term of
such agreements is three to five years or, in some cases, the life of the lease.
However, in almost all cases, the term of these agreements is extended for the
life of the reserves. Energy Transfer's top two suppliers of natural gas to the
Southeast Texas System are Chesapeake Energy Corp. and Anadarko Petroleum Corp.,
which collectively accounted for approximately 44% of the natural gas supplied
to this system for the 11 months ended August 31, 2003. Other suppliers of
natural gas to the Southeast Texas System are Clayton Williams, Marathon, Devon
Energy Corporation, Duke, Crawford, Stroud and Westport, which represented in
the aggregate approximately 38% of the Southeast Texas System's natural gas
supply for the 11 months ended August 31, 2003.
Energy Transfer continually seeks new supplies of natural gas, both to
offset natural declines in production from connected wells and to increase
throughput volume. Energy Transfer obtains new natural gas supplies in its
operating areas by contracting for production from new wells, connecting new
wells drilled on dedicated acreage or by obtaining natural gas that has been
released from other gathering systems. Although most new wells connected to the
Southeast Texas System experience rapid declines in production over the first
year or two of production, thereafter they decline at slower rates.
Approximately 65% of the natural gas supplied to the Southeast Texas System
comes from wells that are older than three years, which are currently not
experiencing the rapid declines in production associated with new wells.
Markets for Sale of Natural Gas and NGLs. The Southeast Texas System has
numerous market outlets for the natural gas that Energy Transfer gathers and
NGLs that it produces on the system. Through Energy Transfer's Katy Pipeline, it
transports natural gas to the Katy Hub and has access to all of its
interconnecting pipelines. The La Grange residue line is connected to the Oasis
Pipeline, as well as the Lower Colorado River Authority Sim Gideon and the
Calpine Lost Pines power plants. NGLs from the La Grange processing plant are
delivered to the Phillips EZ and Seminole Pipeline Company products pipelines,
which are connected to Mont Belvieu, Texas, the largest NGL hub in the United
States.
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Elk City System
A map representing the location of the Elk City System is set forth below:
[MAP OF ELK CITY SYSTEM]
General. The Elk City System is located in western Oklahoma and consists
of over 315 miles of natural gas gathering pipelines, the Elk City processing
plant and the Prentiss treating facility. The gathering system has a capacity of
approximately 410 MMcf/d and average throughput was approximately 170 MMcf/d for
the 11 months ended August 31, 2003. There are five compressor stations located
within the system, comprised of 18 units with an aggregate of approximately
19,000 horsepower.
The Elk City processing plant is a cryogenic natural gas processing plant
that processes natural gas on the Elk City System to produce residue gas and
NGLs. The plant has a processing capacity of approximately 130 MMcf/d. During
the 11 months ended August 31, 2003, the facility processed approximately 95
MMcf/d of natural gas and produced approximately 3,600 Bbls/d of NGLs. Energy
Transfer's Prentiss treating facility, located in Beckham County, Oklahoma, is
an amine treating facility with an aggregate capacity of approximately 145
MMcf/d.
Natural Gas Supply. Energy Transfer currently has approximately 300 wells
connected to the Elk City System. Approximately 80% of these wells are connected
to the eastern portion of this system, which is located in an area that produces
rich natural gas that can be processed and which accounted for approximately 77%
of Energy Transfer's throughput on the system for the 11 months ended August 31,
2003. Lean natural gas is generally produced on the western portion of this
system. The natural gas supplied to the Elk City System is generally dedicated
to Energy Transfer under individually negotiated long-term contracts. The term
of such agreements will typically extend for one to six years. The primary
suppliers of natural gas to the Elk City System are Chesapeake Energy Corp. and
Kaiser-Francis Oil Company and its affiliates, which represented approximately
28% and 25%, respectively, of the Elk City System's natural gas supply for the
11 months ended August 31, 2003.
The Elk City System is located in an active drilling area. Certain
producers are actively drilling in the Springer, Atoka and Arbuckle formations
in western Oklahoma at depths in excess of 15,000 feet. Energy Transfer recently
moved one of its treating plants from Grimes County, Texas to Beckham County,
Oklahoma to treat natural gas produced in the western portion of the system.
Energy Transfer believes that many of the producers drilling in the area will
choose to treat their gas through its new treating plant due to the lack of
other competitive alternatives.
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Markets for Sale of Natural Gas and NGLs. The Elk City processing plant
has access to five major interstate and intrastate downstream pipelines
including Natural Gas Pipeline Company of America, Panhandle Eastern Pipeline
Co., Reliant Gas Transmission, Northern Natural Gas and Enogex. There are also
direct connections to Natural Gas Pipeline Company and Oneok in the field area.
The NGLs that Energy Transfer removes are transported on the Koch Hydrocarbons
pipeline and delivered for fractionation into Conway, Kansas, a major market
center.
Other Assets
In addition to the midstream assets described above, Energy Transfer owns
or has an interest in assets located in Texas and Louisiana. These assets
consist of the following:
- Vantex System. Energy Transfer owns a 50% interest in the Vantex natural
gas pipeline, a converted 285 mile oil transport line that runs from near
the east Texas town of Van to near the Beaumont, Texas industrial area
and has a capacity of approximately 100 MMcf/d of natural gas.
- Rusk County Gathering System. Energy Transfer's Rusk County Gathering
System consists of approximately 33 miles of natural gas gathering
pipeline located in east Texas with a capacity of approximately 15 MMcf/d
of natural gas.
- Whiskey Bay System. The Whiskey Bay System consists of approximately 60
miles of gathering pipelines and a 30 MMcf/d processing plant located in
south Louisiana east of Lafayette.
- Chalkley Transmission System. Energy Transfer's Chalkley Transmission
System is a 32 mile natural gas gathering system located in south central
Louisiana and has a capacity of 100 MMcf/d of natural gas.
Producer Services
Through Energy Transfer's producer services operations, it markets
on-system gas and attracts other customers by marketing off-system gas. For both
on-system and off-system gas, Energy Transfer purchases natural gas from natural
gas producers and other supply points and sells that natural gas to utilities,
industrial consumers, other marketers and pipeline companies, thereby generating
gross margins based upon the difference between the purchase and resale prices.
Most of Energy Transfer's marketing activities involve the marketing of its
on-system gas. For the 11 months ended August 31, 2003, Energy Transfer marketed
approximately 524 MMcf/d of natural gas, 86% of which was on-system gas.
Substantially all of Energy Transfer's on-system marketing efforts involve
natural gas that flows through either the Southeast Texas System or the Oasis
Pipeline. Energy Transfer markets only a small amount of natural gas that flows
through the Elk City System.
For the off-system gas, Energy Transfer purchases gas or acts as an agent
for small independent producers that do not have marketing operations. Energy
Transfer develops relationships with natural gas producers to facilitate the
purchase of their production on a long-term basis. Energy Transfer believes that
this business provides Energy Transfer with strategic insights and valuable
market intelligence which may impact its expansion and acquisition strategy.
During the 11 months ended August 31, 2003, Dow Hydrocarbons and Resources
Inc. and Houston Pipe Line Company were Energy Transfer's largest producer
services customers based on total revenues. During this time period, Energy
Transfer had gross sales to Dow Hydrocarbons and Resources and Houston Pipe Line
as a percentage of total revenues of 18.9% and 11.3%, respectively.
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THE TRANSPORTATION SEGMENT
A map representing the location of the Oasis Pipeline is set forth below:
[MAP OF OASIS PIPELINE]
General. The Oasis Pipeline is a 583-mile, natural gas pipeline that
directly connects the Waha Hub in west Texas to the Katy Hub near Houston,
Texas. The Oasis Pipeline, constructed in the early 1970's, is primarily a
36-inch diameter natural gas pipeline. The Oasis Pipeline also has direct
connections to three independent power plants and is connected to two other
power plants through the Southeast Texas System. The Oasis Pipeline has
bi-directional capability with approximately 1 Bcf/d of natural gas throughput
capacity moving west-to-east and greater than 750 MMcf/d of natural gas
throughput capacity moving east-to-west. Average throughput was approximately
830 MMcf/d of natural gas for the 11 months ended August 31, 2003. The Oasis
Pipeline includes seven mainline compressor stations with approximately 103,000
of installed horsepower.
The Oasis Pipeline is integrated with the Southeast Texas System and is an
important component to maximizing the Southeast Texas System's profitability.
The Oasis Pipeline enhances the Southeast Texas System:
- by providing Energy Transfer the ability to bypass the La Grange
processing plant when processing margins are unfavorable;
- by providing the natural gas on the Southeast Texas System access to
other third party supply and market points and interconnecting pipelines;
and
- by allowing Energy Transfer to bypass its treating facilities on the
Southeast Texas System and blend untreated gas from the Southeast Texas
System with gas on the Oasis Pipeline to meet pipeline quality
specifications.
Markets and Customers. Energy Transfer generally transports natural gas
west-to-east on the Oasis Pipeline. The primary receipt points on the Oasis
Pipeline are at the Waha Hub, several third party processing plants, the La
Grange processing plant through the La Grange residue line and the Katy Hub. The
Oasis Pipeline also takes receipt of natural gas from producers at multiple
receipt points along the pipeline. The primary delivery points are at the Waha
Hub, three independent power plants located mid-system and the Katy Hub. The
Waha and Katy Hubs also connect the Oasis Pipeline to pipelines that provide
access to substantially all major U.S. market centers.
The Oasis Pipeline's transportation customers include, among others, the
independent power plants connected to the pipeline, other major pipelines,
natural gas marketers, natural gas producers and other
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industrial end-users and utilities. The Oasis Pipeline provides direct service
to the 1,100 megawatt, or MW, American National Power Hays County power plant,
the 1,000 MW Panda Guadalupe Power Partners power plant and the 850 MW
Constellation Rio Nogales power plant, all of which are gas-fired, electric
generation facilities with a combined maximum natural gas fuel requirement of
approximately 480 MMcf/d. In addition, through the La Grange residue line, the
Oasis Pipeline provides service to the Lower Colorado River Authority Sim Gideon
and the Calpine Lost Pines units, which have a combined maximum natural gas fuel
requirement of approximately 240 MMcf/d. These power plants provide electricity
for residential, commercial and industrial end-users.
COMPETITION
Energy Transfer experiences competition in all of its markets. Energy
Transfer's principal areas of competition include obtaining natural gas supplies
for the Southeast Texas System and Elk City System and natural gas
transportation customers for the Oasis Pipeline. Energy Transfer's competitors
include major integrated oil companies, interstate and intrastate pipelines and
companies that gather, compress, treat, process, transport and market natural
gas. The Oasis Pipeline competes directly with two other major intrastate
pipelines that link the Waha Hub and the Houston area, one of which is owned by
Duke Energy Field Services and the other one of which is owned by El Paso and
American Electric Power Service Corporation. The Southeast Texas System competes
with natural gas gathering and processing systems owned by Duke Energy Field
Services and Devon Energy Corporation. The Elk City System competes with natural
gas gathering and processing systems owned by Enogex, Inc., Oneok Gas Gathering,
L.L.C., CenterPoint Energy Field Services, Inc. and Enbridge Inc., as well as
producer owned systems.
REGULATION
Regulation by FERC of Interstate Natural Gas Pipelines. Energy Transfer
does not own any interstate natural gas pipelines, so FERC does not directly
regulate any of Energy Transfer's pipeline operations pursuant to its
jurisdiction under the NGA. However, FERC's regulation influences certain
aspects of Energy Transfer's business and the market for Energy Transfer's
products. In general, FERC has authority over natural gas companies that provide
natural gas pipeline transportation services in interstate commerce and its
authority to regulate those services includes:
- the certification and construction of new facilities;
- the extension or abandonment of services and facilities;
- the maintenance of accounts and records;
- the acquisition and disposition of facilities;
- the initiation and discontinuation of services; and
- various other matters.
Failure to comply with the NGA can result in the imposition of
administrative, civil and criminal remedies.
In recent years, FERC has pursued pro-competitive policies in its
regulation of interstate natural gas pipelines. However, we cannot assure you
that FERC will continue this approach as it considers matters such as pipelines'
rates and rules and policies that may affect rights of access to natural gas
transportation capacity.
Intrastate Pipeline Regulation. Energy Transfer's intrastate natural gas
pipeline operations generally are not subject to rate regulation by FERC, but
they are subject to regulation by various agencies in Texas, where they are
located. However, to the extent that Energy Transfer's intrastate pipeline
systems transport natural gas in interstate commerce, the rates, terms and
conditions of such transportation service are subject to FERC jurisdiction under
Section 311 of the NGPA, which regulates, among other things, the provision of
transportation services by an intrastate natural gas pipeline on behalf of a
local distribution
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company or an interstate natural gas pipeline. Under Section 311, rates charged
for transportation must be fair and equitable, and amounts collected in excess
of fair and equitable rates are subject to refund with interest. Failure to
comply with the NGPA can result in the imposition of administrative, civil and
criminal remedies.
Energy Transfer's intrastate pipeline operations in Texas are subject to
the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is
vested with authority to ensure that rates, operations and services of gas
utilities, including intrastate pipelines, are just and reasonable and not
discriminatory. The TRRC has authority to ensure that rates charged by
intrastate pipelines for natural gas sales or transportation services are just
and reasonable. The rates Energy Transfer charges for transportation services
are deemed just and reasonable under Texas law unless challenged in a complaint.
We cannot predict whether such a complaint will be filed against Energy Transfer
or whether the TRRC will change its regulation of these rates. Failure to comply
with the Texas Utilities Code can result in the imposition of administrative,
civil and criminal remedies.
Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas
gathering facilities from the jurisdiction of FERC under the NGA. Energy
Transfer owns a number of natural gas pipelines in Texas, Oklahoma and Louisiana
that Energy Transfer believes meet the traditional tests FERC has used to
establish a pipeline's status as a gatherer not subject to FERC jurisdiction.
However, the distinction between FERC-regulated transmission services and
federally unregulated gathering services is the subject of substantial, on-going
litigation, so the classification and regulation of Energy Transfer's gathering
facilities are subject to change based on future determinations by FERC and the
courts. State regulation of gathering facilities generally includes various
safety, environmental and, in some circumstances, nondiscriminatory take
requirements and in some instances complaint-based rate regulation.
In Texas, Energy Transfer's gathering facilities are subject to regulation
by the TRRC under the Texas Utilities Code in the same manner as described above
for Energy Transfer's intrastate pipeline facilities. Its operations in Oklahoma
are regulated by the Oklahoma Corporation Commission through a complaint based
procedure. Under the Oklahoma Corporation Commission's regulations, Energy
Transfer is prohibited from charging any unduly discriminatory fees for its
gathering services and in certain circumstances is required to provide open
access natural gas gathering for a fee. Louisiana's Pipeline Operations Section
of the Department of Natural Resources' Office of Conservation is generally
responsible for regulating intrastate pipelines and gathering facilities in
Louisiana and has authority to review and authorize natural gas transportation
transactions and the construction, acquisition, abandonment and interconnection
of physical facilities. Historically, apart from pipeline safety, it has not
acted to exercise this jurisdiction respecting gathering facilities. Energy
Transfer's Chalkley System is regulated as an intrastate transporter, and the
Office of Conservation has determined Energy Transfer's Whiskey Bay System is a
gathering system.
Energy Transfer is subject to state ratable take and common purchaser
statutes in all of the states in which Energy Transfer operates. The ratable
take statutes generally require gatherers to take, without undue discrimination,
natural gas production that may be tendered to the gatherer for handling.
Similarly, common purchaser statutes generally require gatherers to purchase
without undue discrimination as to source of supply or producer. These statutes
are designed to prohibit discrimination in favor of one producer over another
producer or one source of supply over another source of supply. These statutes
have the effect of restricting Energy Transfer's right as an owner of gathering
facilities to decide with whom it contracts to purchase or transport natural
gas.
Natural gas gathering may receive greater regulatory scrutiny at both the
state and federal levels now that FERC has taken a more light-handed approach to
regulation of the gathering activities of interstate pipeline transmission
companies and a number of such companies have transferred gathering facilities
to unregulated affiliates. For example, the TRRC has approved changes to its
regulations governing transportation and gathering services performed by
intrastate pipelines and gatherers, which prohibit such entities from unduly
discriminating in favor of their affiliates. Many of the producing states have
adopted some form of complaint-based regulation that generally allows natural
gas producers and shippers to file
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complaints with state regulators in an effort to resolve grievances relating to
natural gas gathering access and rate discrimination. Energy Transfer's
gathering operations could be adversely affected should they be subject in the
future to the application of state or federal regulation of rates and services.
Energy Transfer's gathering operations also may be or become subject to safety
and operational regulations relating to the design, installation, testing,
construction, operation, replacement and management of gathering facilities.
Additional rules and legislation pertaining to these matters are considered or
adopted from time to time. We cannot predict what effect, if any, such changes
might have on Energy Transfer's operations, but the industry could be required
to incur additional capital expenditures and increased costs depending on future
legislative and regulatory changes.
Sales of Natural Gas. Sales for resale of natural gas in interstate
commerce made by intrastate pipelines or their affiliates are subject to FERC
regulation unless the gas is produced by the pipeline or affiliate. Under
current federal rules, however, the price at which Energy Transfer sells natural
gas currently is not regulated, insofar as the interstate market is concerned
and, for the most part, is not subject to state regulation. Effective as of
January 12, 2004, the FERC has issued rules that require pipelines and their
affiliates who sell gas in interstate commerce subject to FERC's jurisdiction to
adhere to a code of conduct prohibiting market manipulation and transactions
that have no legitimate business purpose or result in prices not reflective of
legitimate forces of supply and demand. Those who violate such code of conduct
may be subject to suspension or loss of authorization to perform such sales,
disgorgement of unjust profits, or other appropriate non-monetary remedies
imposed by FERC. The rules are subject to rehearing and possible court appeals.
We cannot predict the outcome of these further proceedings, but do not believe
Energy Transfer will be affected materially differently from other intrastate
gas pipelines and their affiliates. In addition, Energy Transfer's sales of
natural gas are affected by the availability, terms and cost of pipeline
transportation. As noted above, the price and terms of access to pipeline
transportation are subject to extensive federal and state regulation. FERC is
continually proposing and implementing new rules and regulations affecting those
segments of the natural gas industry, most notably interstate natural gas
transmission companies, that remain subject to FERC's jurisdiction. These
initiatives also may affect the intrastate transportation of natural gas under
certain circumstances. The stated purpose of many of these regulatory changes is
to promote competition among the various sectors of the natural gas industry and
these initiatives generally reflect more light-handed regulation. We cannot
predict the ultimate impact of these regulatory changes to Energy Transfer's
natural gas marketing operations, and Energy Transfer notes that some of FERC's
more recent proposals may adversely affect the availability and reliability of
interruptible transportation service on interstate pipelines. Energy Transfer
does not believe that it will be affected by any such FERC action materially
differently than other natural gas marketers with whom it competes.
Pipeline Safety. The states in which Energy Transfer conducts operations
administer federal pipeline safety standards under the Natural Gas Pipeline
Safety Act of 1968, as amended, which requires certain pipelines to comply with
safety standards in constructing and operating the pipelines and subjects the
pipelines to regular inspections. Failure to comply with the Act may result in
the imposition of administrative, civil and criminal remedies. The "rural
gathering exemption" under the Natural Gas Pipeline Safety Act of 1968 presently
exempts substantial portions of Energy Transfer's gathering facilities from
jurisdiction under that statute. The portions of Energy Transfer's facilities
that are exempt include those portions located outside of cities, towns or any
area designated as residential or commercial, such as a subdivision or shopping
center. The "rural gathering exemption", however, may be restricted in the
future, and it does not apply to Energy Transfer's intrastate natural gas
pipelines.
ENVIRONMENTAL MATTERS
The operation of pipelines, plants and other facilities for gathering,
compressing, treating, processing, or transporting natural gas, natural gas
liquids and other products is subject to stringent and complex laws and
regulations pertaining to health, safety and the environment. As an owner or
operator of these facilities, Energy Transfer must comply with these laws and
regulations at the federal, state and local
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levels. These laws and regulations can restrict or prohibit Energy Transfer's
business activities that affect the environment in many ways, such as:
- restricting the way Energy Transfer can release materials or waste
products into the air, water, or soils;
- limiting or prohibiting construction activities in sensitive areas such
as wetlands or areas of endangered species habitat, or otherwise
constraining how or when construction is conducted;
- requiring remedial action to mitigate pollution from former operations,
or requiring plans and activities to prevent pollution from ongoing
operations; and
- imposing substantial liabilities on Energy Transfer for pollution
resulting from Energy Transfer's operations, including, for example,
potentially enjoining the operations of facilities if it were determined
that they were not in compliance with permit terms.
In most instances, the environmental laws and regulations affecting Energy
Transfer's operations relate to the potential release of substances or waste
products into the air, water or soils and include measures to control or prevent
the release of substances or waste products to the environment. Costs of
planning, designing, constructing and operating pipelines, plants and other
facilities must incorporate compliance with environmental laws and regulation
and safety standards. Failure to comply with these laws and regulations may
trigger a variety of administrative, civil and criminal enforcement measures,
which can include the assessment of monetary penalties, the imposition of
remedial requirements, the issuance of injunctions and federally authorized
citizen suits. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of substances or other waste products to the environment.
The clear trend in environmental regulation is to place more restrictions
and limitations on activities that may affect the environment, and thus there
can be no assurance as to the amount or timing of future expenditures for
environmental compliance or remediation, and actual future expenditures may be
different from the amounts Energy Transfer currently anticipates. Energy
Transfer will attempt to anticipate future regulatory requirements that might be
imposed and plan accordingly in order to remain in compliance with changing
environmental laws and regulations and to minimize the costs of such compliance.
The following is a discussion of certain environmental and safety concerns
that relate to the midstream natural gas and NGLs industry. It is not intended
to constitute a complete discussion of all applicable federal, state and local
laws and regulations, or specific matters, to which Energy Transfer may be
subject.
Energy Transfer's operations are subject to the federal Clean Air Act and
comparable state laws and regulations. These laws and regulations govern
emissions of pollutants into the air resulting from Energy Transfer's
activities, for example in relation to Energy Transfer's processing plants and
its compressor stations, and also impose procedural requirements on how it
conducts its operations. Such laws and regulations may include requirements that
Energy Transfer obtain pre-approval for the construction or modification of
certain projects or facilities expected to produce air emissions, strictly
comply with the emissions and operational limitations of air emissions permits
Energy Transfer is required to obtain, or utilize specific equipment or
technologies to control emissions. For example, beginning in mid-2004, increased
natural gas supplies from the Bossier Pipeline project will likely require the
Katy Compressor Station to run one or both of its turbines. The new clean air
plan for Houston will require sources of nitrogen oxides or "NOx" emissions
(such as these turbines) to hold "allowances" for each ton of NOx emitted.
Energy Transfer currently expects to satisfy this plan requirement between 2004
and 2007 by purchasing annual allowances escalating in cost from $6,300 in 2004
to $126,000 in 2007. After 2007, Energy Transfer could make a one-time purchase
of a perpetual stream of allowances at a currently estimated cost of
approximately $2.3 million. However, rather than simply making a one-time
purchase of a large number of perpetual credits, Energy Transfer believes that
there are less costly alternatives for satisfying this plan requirement, such as
the installation of selective catalytic reduction equipment coupled with the
one-time purchase of a limited amount of NOx emission reduction credits at a
combined
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currently estimated cost of approximately $1.3 million. Notwithstanding these
current plans, Energy Transfer is engaged in negotiations with the Texas
Commission on Environmental Quality that could result in the agency granting a
variance over a two-year period that would allow Energy Transfer to establish a
NOx emissions baseline, such that fewer NOx allowances would have to be
purchased by Energy Transfer. In addition, Energy Transfer currently anticipates
spending between $1 million and $1.5 million prior to 2007 to upgrade its
Prairie Lea Compressor Station to comply with recently enacted Texas air
permitting regulations. Its failure to comply with these requirements exposes
Energy Transfer to civil enforcement actions from the state agencies and perhaps
the EPA, including monetary penalties, injunctions, conditions or restrictions
on operations and potentially criminal enforcement actions or federally
authorized citizen suits.
Energy Transfer's operations generate wastes, including some hazardous
wastes, that are subject to the federal Resource Conservation and Recovery Act
("RCRA") and comparable state laws. However, RCRA currently exempts many natural
gas gathering and field processing wastes from classification as hazardous
waste. Specifically, RCRA excludes from the definition of hazardous waste
produced waters and other wastes associated with the exploration, development,
or production of crude oil, natural gas or geothermal energy. Unrecovered
petroleum product wastes, however, may still be regulated under RCRA as solid
waste. Moreover, ordinary industrial wastes such as paint wastes, waste
solvents, laboratory wastes and waste compressor oils, may be regulated as
hazardous waste. The transportation of natural gas and NGLs in pipelines may
also generate some hazardous wastes. Although Energy Transfer believes it is
unlikely that the RCRA exemption will be repealed in the near future, repeal
would increase costs for waste disposal and environmental remediation at Energy
Transfer's facilities.
Energy Transfer's operations could incur liability under CERCLA and
comparable state laws regardless of Energy Transfer's fault, in connection with
the disposal or other release of hazardous substances or wastes, including those
arising out of historical operations conducted by Energy Transfer's
predecessors. Although "petroleum" as well as natural gas and NGLs are excluded
from CERCLA's definition of "hazardous substance," in the course of its ordinary
operations Energy Transfer will generate wastes that may fall within the
definition of a "hazardous substance." CERCLA authorizes the EPA and, in some
cases, third parties to take actions in response to threats to the public health
or the environment and to seek to recover from the responsible classes of
persons the costs they incur. It is not uncommon for neighboring landowners and
other third parties to file claims for personal injury and property damage
allegedly caused by hazardous substances or other wastes released into the
environment. If Energy Transfer was to incur liability under CERCLA, Energy
Transfer could be subject to joint and several liability for the costs of
cleaning up hazardous substances, for damages to natural resources and for the
costs of certain health studies.
Energy Transfer currently owns or leases, and has in the past owned or
leased, numerous properties that for many years have been used for the
measurement, gathering, field compression and processing of natural gas and
NGLs. Although Energy Transfer used operating and disposal practices that were
standard in the industry at the time, hydrocarbons or wastes may have been
disposed of or released on or under the properties owned or leased by Energy
Transfer or on or under other locations where such wastes have been taken for
disposal. In addition, some of these properties have been operated by third
parties whose treatment and disposal or release of hydrocarbons or wastes was
not under Energy Transfer's control. These properties and the substances
disposed or released on them may be subject to CERCLA, RCRA and analogous state
laws. Under such laws, Energy Transfer could be required to remove or remediate
previously disposed wastes (including waste disposed of or released by prior
owners or operators) or property contamination (including groundwater
contamination, whether from prior owners or operators or other historic
activities or spills) or to perform remedial plugging or pit closure operations
to prevent future contamination, in some instances regardless of fault or the
amount of waste Energy Transfer sent to the site. For example, Energy Transfer
is currently involved in several remediation operations in which Energy
Transfer's cost for cleanup and related liabilities is estimated to be between
$1.1 million and $1.8 million in the aggregate. However, with respect to one of
the remedial projects, Energy Transfer expects to recover approximately $500,000
to $850,000 of these estimated cleanup costs pursuant to a
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contractual requirement that makes a predecessor owner responsible for
environmental liabilities. Energy Transfer has established environmental
accruals totaling approximately $930,000 to address environmental conditions and
related liabilities including costs for cleanup and remediation of properties.
Energy Transfer's operations can result in discharges of pollutants to
waters. The Federal Water Pollution Control Act of 1972, as amended ("FWPCA"),
also known as the Clean Water Act, and analogous state laws impose restrictions
and strict controls regarding the discharge of pollutants into state waters or
waters of the United States. The unpermitted discharge of pollutants such as
from spill or leak incidents is prohibited. The FWPCA and regulations
implemented thereunder also prohibit discharges of fill material and certain
other activities in wetlands unless authorized by an appropriately issued
permit. Any unpermitted release of pollutants, including NGLs or condensates,
from Energy Transfer's systems or facilities could result in fines or penalties
as well as significant remedial obligations. Energy Transfer currently expects
to incur costs of approximately $100,000 over the next year to make spill
prevention upgrades or modifications at certain of its facilities as required
under its recently updated spill prevention controls and countermeasures or
"SPCC" plans.
Energy Transfer's pipelines are subject to regulation by the U.S.
Department of Transportation (the "DOT") under the Hazardous Liquid Pipeline
Safety Act, or HLPSA, pursuant to which the DOT has established requirements
relating to the design, installation, testing, construction, operation,
replacement and management of pipeline facilities. The HLPSA covers crude oil,
carbon dioxide, NGL and petroleum products pipelines and requires any entity
which owns or operates pipeline facilities to comply with the regulations under
the HLPSA, to permit access to and allow copying of records and to make certain
reports and provide information as required by the Secretary of Transportation.
Energy Transfer believes that its pipeline operations are in substantial
compliance with applicable HLPSA requirements; however, due to the possibility
of new or amended laws and regulations or reinterpretation of existing laws and
regulations, there can be no assurance that future compliance with the HLPSA
will not have a material adverse effect on Energy Transfer's results of
operations or financial positions.
Currently, the Department of Transportation, through the Office of Pipeline
Safety, is in the midst of promulgating a series of rules intended to require
pipeline operators to develop integrity management programs for gas transmission
pipelines that, in the event of a failure, could impact "high consequence
areas". "High consequence areas" are currently defined as areas with specified
population densities, buildings containing populations of limited mobility and
areas where people gather that occur along the route of a pipeline. Similar
rules are already in place for operators of hazardous liquid pipelines, which
are also applicable to Energy Transfer's pipelines in certain instances. The
Office of Pipeline Safety has yet to publish a final rule requiring gas pipeline
operators to develop integrity management plans, but it is expected that a rule
will eventually be finalized. Compliance with such rule, or rules, when
finalized, could result in increased operating costs that, at this time, cannot
reasonably be quantified.
Energy Transfer is subject to the requirements of the Occupational Safety
and Health Act, referred to as OSHA, and comparable state laws that regulate the
protection of the health and safety of workers. In addition, the OSHA hazard
communication standard requires that information be maintained about hazardous
materials used or produced in Energy Transfer's operations and that this
information be provided to employees, state and local government authorities and
citizens. Energy Transfer believes that its operations are in substantial
compliance with the OSHA requirements, including general industry standards,
record keeping requirements and monitoring of occupational exposure to regulated
substances.
Energy Transfer does not believe that compliance with federal, state or
local environmental laws and regulations will have a material adverse effect on
its business, financial position or results of operations. In addition, Energy
Transfer believes that the various environmental activities in which it does
presently engaged are not expected to materially interrupt or diminish its
operational ability to gather, compress, treat, process and transport natural
gas and NGLs. We cannot assure you, however, that future events, such as changes
in existing laws, the promulgation of new laws, or the development or discovery
of new facts or conditions will not cause Energy Transfer to incur significant
costs.
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TITLE TO PROPERTIES
Substantially all of Energy Transfer's pipelines are constructed on
rights-of-way granted by the apparent record owners of the property. Lands over
which pipeline rights-of-way have been obtained may be subject to prior liens
that have not been subordinated to the right-of-way grants. Energy Transfer has
obtained, where necessary, easement agreements from public authorities and
railroad companies to cross over or under, or to lay facilities in or along,
watercourses, county roads, municipal streets, railroad properties and state
highways, as applicable. In some cases, property on which Energy Transfer's
pipeline was built was purchased in fee.
Some of the leases, easements, rights-of-way, permits, licenses and
franchise ordinances that will be transferred to Energy Transfer will require
the consent of the current landowner to transfer these rights, which in some
instances is a governmental entity. We believe that Energy Transfer has obtained
or will obtain sufficient third-party consents, permits and authorizations for
the transfer of the assets necessary for Energy Transfer to operate its business
in all material respects as described in this prospectus supplement. With
respect to any consents, permits or authorizations that have not been obtained,
we believe that these consents, permits or authorizations will be obtained after
the closing of this offering, or that the failure to obtain these consents,
permits or authorizations will have no material adverse effect on the operation
of Energy Transfer's business.
We believe that Energy Transfer has satisfactory title to all of its
assets. Record title to some of its assets may continue to be held by affiliates
of Energy Transfer's predecessor until Energy Transfer has made the appropriate
filings in the jurisdictions in which such assets are located and obtained any
consents and approvals that are not obtained prior to transfer. Title to
property may be subject to encumbrances. We believe that none of such
encumbrances should materially detract from the value of Energy Transfer's
properties or from its interest in these properties or should materially
interfere with their use in the operation of its business.
OFFICE FACILITIES
In addition to Energy Transfer's gathering and treating facilities
discussed above, Energy Transfer leases approximately 7,500 square feet of space
for Energy Transfer's executive offices in Dallas, Texas. Energy Transfer also
leases office facilities in San Antonio, Texas and Tulsa, Oklahoma, which
consist of 39,235 square feet and 1,240 square feet, respectively. While Energy
Transfer may require additional office space as its business expands, it
believes that its existing facilities are adequate to meet its needs for the
immediate future and that additional facilities will be available on
commercially reasonable terms as needed.
EMPLOYEES
To carry out its operations, Energy Transfer and its affiliates employs
approximately 230 people. Energy Transfer is not party to any collective
bargaining agreements. Energy Transfer considers its employee relations to be
good.
LEGAL PROCEEDINGS
On June 16, 2003, Guadalupe Power Partners, L.P. sought and obtained a
Temporary Restraining Order that prevents Oasis Pipe Line from taking action to
restrict Guadalupe Power Partners' ability to deliver and receive natural gas
under its contract with Oasis Pipe Line at rates of its choice. In their
pleadings, Guadalupe Power Partners alleged unspecified monetary damages for the
period from February 25, 2003 to June 16, 2003 and sought to prevent Oasis Pipe
Line from implementing flow control measures to reduce the flow of gas to their
power plant at varying hourly rates. Oasis Pipe Line filed a counterclaim
against Guadalupe Power Partners and asked for damages and a declaration that
the contract was terminated as a result of the breach by Guadalupe Power
Partners. Oasis Pipe Line and Guadalupe Power Partners agreed to a "stand still"
order and referred this dispute to binding arbitration.
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Although Energy Transfer may, from time to time, be involved in litigation
and claims arising out of its operations in the normal course of business,
Energy Transfer is not currently a party to any material legal proceedings. In
addition, Energy Transfer is not aware of any material legal or governmental
proceedings against Energy Transfer, or contemplated to be brought against
Energy Transfer, under the various environmental protection statutes to which
Energy Transfer is subject.
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MANAGEMENT
The following table sets forth certain information with respect to the
executive officers and members of the Board of Directors as of October 31, 2003.
Executive officers and directors are elected for one-year terms.
<Table>
<Caption>
NAME AGE POSITION WITH GENERAL PARTNER
- ---- --- -----------------------------
H. Michael Krimbill(1).................... 50 President and Chief Executive Officer, and
Director
James E. Bertelsmeyer..................... 61 Chairman of the Board and Director
R.C. Mills................................ 66 Executive Vice President and Chief
Operating Officer
Michael L. Greenwood(2)................... 48 Vice President and Chief Financial Officer
Bradley K. Atkinson....................... 48 Vice President of Corporate Development
Mark A. Darr(3)........................... 43 Vice President -- Southern Operations
Thomas H. Rose(3)......................... 59 Vice President -- Northern Operations
Curtis L. Weishahn(3)..................... 50 Vice President -- Western Operations
Bill W. Byrne............................. 73 Director of the General Partner
J. Charles Sawyer......................... 67 Director of the General Partner
Stephen L. Cropper(4)..................... 53 Director of the General Partner
J. Patrick Reddy(1)....................... 50 Director of the General Partner
Royston K. Eustace(1)..................... 62 Director of the General Partner
William N. Cantrell(1).................... 51 Director of the General Partner
David J. Dzuricky(1)...................... 52 Director of the General Partner
JD Woodward III(5)........................ 53 Director of the General Partner
Richard T. O'Brien(5)..................... 49 Director of the General Partner
Kevin M. O'Hara(6)........................ 45 Director of the General Partner
Andrew W. Evans(7)........................ 37 Director of the General Partner
</Table>
- ---------------
(1) Elected to the Board of Directors August 2000.
(2) Elected Vice President and Chief Financial Officer July 2002.
(3) Elected an Executive Officer July 2000.
(4) Elected to the Board of Directors April 2000.
(5) Elected to the Board of Directors October 2001.
(6) Elected to the Board of Directors April 2002.
(7) Elected to the Board of Directors October 2002.
Set forth below is biographical information regarding the foregoing
officers and directors of our general partner:
H. Michael Krimbill. Mr. Krimbill joined Heritage as Vice President and
Chief Financial Officer in 1990 and was previously Treasurer of a publicly
traded, fully integrated oil company. Mr. Krimbill was promoted to President of
Heritage in April 1999 and to Chief Executive Officer in March 2000.
James E. Bertelsmeyer. Mr. Bertelsmeyer has over 28 years of experience in
the propane industry, including six years as President of Buckeye Gas Products
Company, at the time the nation's largest retail propane marketer. Mr.
Bertelsmeyer founded Heritage and served as Chief Executive Officer of Heritage
since its formation until the election of H. Michael Krimbill in March 2000. Mr.
Bertelsmeyer began his career with Conoco Inc. where he spent ten years in
positions of increasing responsibility in the pipeline and gas products
departments. Mr. Bertelsmeyer has been a director of the NPGA for the past 28
years, and is a former president of the NPGA.
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R.C. Mills. Mr. Mills has over 40 years of experience in the propane
industry. Mr. Mills joined Heritage in 1991 as Executive Vice President and
Chief Operating Officer. Before coming to Heritage, Mr. Mills spent 25 years
with Texgas Corporation and its successor, Suburban Propane, Inc. At the time he
left Suburban in 1991, Mr. Mills was Vice President of Supply and Wholesale.
Michael L. Greenwood. Mr. Greenwood became Heritage's Vice President and
Chief Financial Officer, on July 1, 2002. Prior to joining Heritage, Mr.
Greenwood was Senior Vice President, Chief Financial Officer and Treasurer for
Alliance Resource Partners, L.P., a publicly traded master limited partnership
involved in the production and marketing of coal. Mr. Greenwood brings to
Heritage over 20 years of diverse financial and management experience in the
energy industry during his career with several major public energy companies
including MAPCO Inc., Penn Central Corporation, and The Williams Companies.
Bradley K. Atkinson. Mr. Atkinson joined Heritage on April 16, 1998 as
Vice President of Administration. Prior to joining Heritage, Mr. Atkinson spent
twelve years with MAPCO/Thermogas, eight of which were spent in the acquisitions
and business development of Thermogas. Mr. Atkinson was promoted to Vice
President of Corporate Development in August 2000.
Mark A. Darr. Mr. Darr has 18 years in the propane industry. Mr. Darr
joined Heritage in 1991 and has held various positions including District
Manager and Vice President and Regional Manager before his election to Vice
President -- Southern Operations, in July 2000. Prior to joining Heritage, Mr.
Darr held various positions with Texgas Corporation, and its successor, Suburban
Propane. He is a past President of the Florida Propane Gas Association, the
Florida Director of the NPGA, and a member of the LP Gas Bureau State Advisory
Council.
Thomas H. Rose. Mr. Rose has 27 years of experience in the propane
industry. Mr. Rose joined Heritage in November 1994 as Vice President and
Regional Manager. Prior to joining Heritage, Mr. Rose held Regional Manager
positions with Texgas Corporation, its successor, Suburban Propane, and later
Vision Energy of Florida. Mr. Rose was appointed Vice President -- Northern
Operations in July 2000.
Curtis L. Weishahn. Mr. Weishahn has 25 years experience in the propane
industry. Mr. Weishahn joined Heritage in 1995 as Vice President and Regional
Manager and was elected Vice President -- Western Operations in July 2000. Prior
to joining Heritage, Mr. Weishahn owned his own propane business, which was
acquired by Heritage. Prior to that time, Mr. Weishahn spent twelve years with
Amerigas/CalGas where, at the time of departing, he was Director of
Marketing/Strategic Development for the Western United States.
Bill W. Byrne. Mr. Byrne is the principal of Byrne & Associates, LLC, a
gas liquids consulting group based in Tulsa, Oklahoma, and has held that
position since 1992. Prior to that time, he served as Vice President of Warren
Petroleum Company, the gas liquids division of Chevron Corporation, from
1982-1992. Mr. Byrne has served as a director of Heritage since 1992, is a
member of both the Independent Committee and the Compensation Committee, and is
Chairman of the Audit Committee. Mr. Byrne is a former president and director of
the NPGA.
J. Charles Sawyer. Mr. Sawyer is the President and Chief Executive Officer
of Sawyer Cellars. Mr. Sawyer is also the President and Chief Executive Officer
of Computer Energy, Inc., a provider of computer software to the propane
industry since 1981. Mr. Sawyer was Chief Executive Officer of Sawyer Gas Co., a
regional propane distributor, until it was purchased by Heritage in 1991. Mr.
Sawyer has served as a director of Heritage since 1991 and is a member of both
the Independent Committee and the Audit Committee. Mr. Sawyer is a former
president and director of the NPGA.
Stephen L. Cropper. Mr. Cropper spent 25 years with The Williams Companies
before retiring in 1998, as President and Chief Executive Officer of Williams
Energy Services. Mr. Cropper is a director of Rental Car Finance Corporation, a
subsidiary of Dollar Thrifty Automotive Group. He is a director and serves as
the audit committee financial expert of Berry Petroleum Company. Mr. Cropper
also serves as a director, chairman of the audit committee and member of the
compensation committee of Sun Logistics Partners L.P. Mr. Cropper is a director
and serves as the chairman of the compensation committee of
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QuikTrip Corporation. Mr. Cropper has served as a director of Heritage since
April 2000 and is a member of both the Independent Committee and the Audit
Committee.
J. Patrick Reddy. Mr. Reddy is the Senior Vice President and Chief
Financial Officer of Atmos Energy and has held that position since October 2000.
Prior to being named to that position, Mr. Reddy served as Atmos Energy's Senior
Vice President, Chief Financial Officer and Treasurer from March 2000 to
September 2000, and its Vice President of Corporate Development and Treasurer
during the period from December 1998 to April 2000. Prior to joining Atmos
Energy in August 1998 as Vice President, Corporate Development, Mr. Reddy held a
number of management positions with Pacific Enterprises, Inc. during the period
from 1980 to 1998, including Vice President, Planning & Advisory Services from
1995 to August 1998. Mr. Reddy has served as a director of Heritage since August
2000 and is a member of the Compensation Committee.
Royston K. Eustace. Mr. Eustace is the Senior Vice President of Business
Development for TECO, and has held that position since 1998. Mr. Eustace has
also served as the President of TECO Coalbed Methane since 1991 and as the
President of TECO Oil & Gas since 1995. Mr. Eustace joined TECO in 1987 as its
Vice President of Strategic Planning and Business Development. Mr. Eustace has
served as a director of Heritage since August 2000 and is Chairman of the
Compensation Committee.
William N. Cantrell. Mr. Cantrell currently serves as President of Tampa
Electric Company, the largest TECO subsidiary, engaged in the regulated electric
and gas industry. Mr. Cantrell has been employed with TECO since 1975. At the
time of the formation of U.S. Propane, Mr. Cantrell was the President of Peoples
Gas Company, a regional propane distributor serving the Florida market. Mr.
Cantrell has served as a director of Heritage since August 2000.
David J. Dzuricky. Mr. Dzuricky is the Senior Vice President and Chief
Financial Officer of Piedmont Natural Gas and has served in that capacity since
May 1995. Prior to being named to that position, Mr. Dzuricky held a variety of
executive officer positions with Consolidated Natural Gas Company during the
period from 1982 to 1995. Mr. Dzuricky has served as a director of Heritage
since August 2000.
JD Woodward III. Mr. Woodward has served as Senior Vice President of
Non-Utility Operations of Atmos Energy since April 2001, and is responsible for
Atmos Energy's non-regulated business activities. Prior to being named to that
position, Mr. Woodward held the position of President of Woodward Marketing,
L.L.C., in Houston, Texas from January 1995 to March 2001. Mr. Woodward was
named a director of Heritage in October 2001.
Richard T. O'Brien. Mr. O'Brien is Executive Vice President and Chief
Financial Officer of AGL Resources and has held that position since May 2001.
Prior to being named to that position, he was Vice President of Mirant (formerly
Southern Energy) and President of Mirant Capital Management, LLC from March 2000
to April 2001 in Atlanta, Georgia. Prior to that time, Mr. O'Brien held various
executive positions with Pacificorp in Portland, Oregon during the period from
1983 to 2000. Mr. O'Brien was named a director of Heritage October 2001.
Kevin M. O'Hara. Mr. O'Hara is Vice President of Corporate Planning for
Charlotte-based Piedmont Natural Gas. Mr. O'Hara joined Piedmont Natural Gas in
1987 and his current responsibilities include the development and implementation
of corporate strategies related to system expansion and organization
development. In addition, Mr. O'Hara has responsibility for non-regulated
business activities of Piedmont Natural Gas. His prior work experience was with
Andersen Consulting (now Accenture) where he started his career in their Chicago
office. Mr. O'Hara was elected a director of Heritage in April 2002.
Andrew W. Evans. Mr. Evans is the Vice President of Finance and Treasurer
of AGL Resources. He has held that position since May 2002. Prior thereto Mr.
Evans was with Mirant Corporation where he served as Vice President of Corporate
Development for Mirant Americas business unit, and prior to that Vice President
and Treasurer for Mirant Americas. During his tenure with Mirant, he oversaw
market analysis and structured product development for the energy marketing
business. He also served as Director
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of Finance for Mirant's trading business, Mirant Americas Energy Marketing.
Prior to Mirant, Evans was employed by the Cambridge, MA office of National
Economic Research Associates and the Federal Reserve Bank of Boston. Mr. Evans
was named a director of Heritage in October 2002.
MANAGEMENT FOLLOWING COMPLETION OF ENERGY TRANSFER TRANSACTION
In connection with the Energy Transfer transaction, La Grange Energy will
purchase all of the partnership interests of U.S. Propane, L.P., our general
partner, and all of the member interests of U.S. Propane, L.L.C., the general
partner of U.S. Propane, L.P. As a result of this purchase, it is contemplated
that the new owners of our general partner will make various changes to our
management structure. The following table sets forth certain information with
respect to the executive officers and members of the Board of Directors who are
expected to hold management positions immediately following the closing of the
Energy Transfer transaction:
<Table>
<Caption>
NAME AGE POSITION WITH GENERAL PARTNER
- ---- --- -----------------------------
Ray C. Davis.............................. 61 Co-Chief Executive Officer and Co-Chairman
of the Board
Kelcy L. Warren........................... 48 Co-Chief Executive Officer and Co-Chairman
of the Board
H. Michael Krimbill....................... 50 President and Director
R.C. Mills................................ 66 Executive Vice President and Chief Operating
Officer
A. Dean Fuller............................ 56 Senior Vice President -- Operations
Mackie McCrea............................. 44 Senior Vice President -- Commercial
Development
Bradley K. Atkinson....................... 48 Vice President -- Corporate Development
Lon C. Kile............................... 48 Vice President -- Finance
Michael L. Greenwood...................... 48 Vice President -- Finance
Stephen L. Cropper........................ 53 Director of the General Partner
Richard T. O'Brien........................ 49 Director of the General Partner
J. Charles Sawyer......................... 67 Director of the General Partner
Bill W. Byrne............................. 73 Director of the General Partner
David R. Albin............................ 44 Director of the General Partner
Kenneth A. Hersh.......................... 40 Director of the General Partner
</Table>
We expect that Mr. Darr, Mr. Rose and Mr. Weishahn, currently executive
officers of our general partner, will hold positions with Heritage Propane
Partners or Heritage Operating following the closing of the Energy Transfer
transaction similar to their current positions. We also expect that current
management personnel for Energy Transfer that are not named in the table above
will continue to hold similar positions with Energy Transfer following the
closing of the Energy Transfer transaction. We have been advised by La Grange
Energy that, following the closing of the Energy Transfer transaction, our
general partner will select a chief financial officer after evaluating
candidates for the position, who may be officers of our general partner
following the closing of the Energy Transfer transaction as well as other
potential candidates. Following the purchase of our general partner by La Grange
Energy, La Grange Energy will have the ability, without any approval of our
unitholders, to remove any of the directors of the general partner, as well as
to add one or more new directors.
Set forth below is biographical information regarding the additional
persons who are expected to become officers and directors of our general partner
following the closing of the Energy Transfer transaction.
Ray C. Davis will be Co-Chief Executive Officer and Co-Chairman of the
Board of Directors of our general partner following the closing of the Energy
Transfer transaction. He has served as Co-Chief
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Executive Officer of the general partner of La Grange Acquisition since it was
formed in 2002. He is Co-Chief Executive Officer and Co-Chairman of the Board of
the general partner of La Grange Energy and has served in that capacity since it
was formed in 2002. He is also Vice President of the general partner of ET
Company I, Ltd., the entity that operated Energy Transfer's midstream assets
before it acquired Aquila, Inc.'s midstream assets, and has served in that
capacity since 1996. From 1996 to 2000, he served as Director of Crosstex
Energy, Inc. From 1993 to 1996, he served as Chairman of the board of directors
and Chief Executive Officer of Cornerstone Natural Gas, Inc. Mr. Davis has more
than 31 years of business experience in the energy industry.
Kelcy L. Warren will be the Co-Chief Executive Officer and Co-Chairman of
the Board of our general partner following the closing of the Energy Transfer
transaction. He has served as Co-Chief Executive Officer of the general partner
of La Grange Acquisition since it was formed in 2002. He is Co-Chief Executive
Officer and Co-Chairman of the Board of the general partner of La Grange Energy
and has served in that capacity since it was formed in 2002. He is also
President of the general partner of ET Company I, Ltd., and has served in that
capacity since 1996. From 1996 to 2000, he served as Director of Crosstex
Energy, Inc. From 1993 to 1996, he served as President, Chief Operating Officer
and a director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 20
years of business experience in the energy industry.
A. Dean Fuller will be a Senior Vice President -- Operations of our general
partner following the closing of the Energy Transfer transaction. He has served
as a Senior Vice President and General Manager of the general partner of La
Grange Acquisition since it was formed in 2002. From 2000 to 2002, he served as
Senior Vice President and General Manager of the midstream business of Aquila,
Inc. From 1996 to 2000, he managed the fuel and gas trading operations of
Central and South West Corporation, a large electric utility holding company.
Mackie McCrea will be Senior Vice President -- Commercial Development of
our general partner following the closing of the Energy Transfer transaction. He
has served as Senior Vice President -- Business Development and Producer
Services of the general partner of La Grange Acquisition and ET Company I, Ltd.
since 1997.
Lon C. Kile will be a Vice President -- Finance of our general partner
following the closing of the Energy Transfer transaction. He has served in the
capacity of Chief Financial Officer for the general partner of La Grange
Acquisition since it was formed in 2002. From 1999 to 2002, he served as
President, Chief Operating Officer and a director of Prize Energy Corporation, a
publicly-traded independent exploration and production company. From 1997 to
1999, he served as Executive Vice President of Pioneer Natural Resources
Company, an independent oil and gas company.
David R. Albin will be a director of our general partner following the
closing of the Energy Transfer transaction. He is a managing partner of Natural
Gas Partners, L.L.C. and has served in that capacity or similar capacities since
1988. Prior to his participation as a founding member of Natural Gas Partners,
L.P. in 1988, he was a partner in the $600 million Bass Investment Limited
Partnership. Prior to joining Bass Investment Limited Partnership, he was a
member of the oil and gas group in the investment banking division of Goldman,
Sachs & Co.
Kenneth A. Hersh will be a director of our general partner following the
closing of the Energy Transfer transaction. He is a managing partner of Natural
Gas Partners, L.L.C. and has served in that capacity or similar capacities since
1989. Prior to joining Natural Gas Partners, L.P. in 1989, he was a member of
the energy group in the investment banking division of Morgan Stanley & Co.
Mr. Davis and Mr. Warren own, directly and indirectly, equity interests in
La Grange Energy, the entity that will purchase all of the limited partnership
interests in our general partner, U.S. Propane, L.P., and all of the member
interests in the general partner of our general partner, U.S. Propane, L.L.C. In
addition, it is anticipated that several members of the existing management of
our general partner will be offered the opportunity to acquire equity interests
in La Grange Energy or a related entity, either before or after the closing of
the Energy Transfer transaction.
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RELATED PARTY TRANSACTIONS
HERITAGE PROPANE PARTNERS
The following updates information previously provided in our Annual Report
on Form 10-K for the year ended August 31, 2003.
We have entered into an agreement with TECO Partners, Inc. ("TECO
Partners") whereby TECO Partners will provide services relating to the securing
of new propane customers in our Florida regional operations area. TECO Partners
is an affiliated company of TECO Propane Ventures, L.L.C., one of the companies
owning limited partner interests in our general partner, U.S. Propane, L.P., and
member interests in U.S. Propane, L.L.C., the general partner of U.S. Propane,
L.P. Under the agreement, TECO Partners receives commissions upon the procuring
of new propane customers for us. The terms of the agreement are no less
favorable to us than those available from other parties providing similar
services. During fiscal year 2003, TECO Partners received commissions of less
than $200,000. In connection with the transaction with Energy Transfer, TECO
Propane Ventures, L.L.C. will dispose of its interests in our general partner
and, as a result, at the closing of this offering, there will no longer be a
related party relationship.
ENERGY TRANSFER
The following is a summary of certain transactions between Energy Transfer
and certain of its other affiliates.
Beginning in 2003 and after the contribution by an affiliate of La Grange
Energy of ET Company I to Energy Transfer, Energy Transfer has been charged rent
by an affiliate for office space in Dallas, which is shared with La Grange
Energy and ETC Holdings, L.P., an affiliate of La Grange Energy. For the 11
months ended August 31, 2003, the rent charged to Energy Transfer was $90,000.
This office building will be contributed to Energy Transfer in connection with
the Energy Transfer transaction.
Prior to the Oasis Pipe Line stock redemption and the contribution of ET
Company I to Energy Transfer, Energy Transfer had purchases and sales of natural
gas with Oasis Pipe Line and ET Company I in the normal course of business. The
following table summarizes these transactions:
<Table>
<Caption>
OCTOBER 1, 2002 (INCEPTION)
THROUGH DECEMBER 31, 2002
---------------------------
(IN THOUSANDS)
Sales of natural gas to affiliated companies................ $4,488
Purchases of natural gas from affiliated companies.......... $3,989
Transportation expenses..................................... $ 922
</Table>
During 2003, ETC Texas Pipeline, Ltd, one of Energy Transfer's operating
partnerships, purchased a compressor, initially ordered by Energy Transfer
Group, L.L.C. for $799,000. Energy Transfer Group is a 66% owned subsidiary of
ETC Holdings, L.P. Energy Transfer Group has a contract to provide compression
services to a third party for a fixed monthly fee. Proceeds from the contract
will be remitted by Energy Transfer Group to ETC Texas Pipeline, Ltd. to provide
a 14.6% return on investment for the capital investment made by ETC Texas
Pipeline, Ltd. As of August 31, 2003, no fees had been remitted, but income of
$7,000 has been accrued under the contract. In addition, a $200,000 deposit was
made to a third party vendor by ETC Texas Pipeline, Ltd. on behalf of Energy
Transfer Group.
Energy Transfer also provides payroll services to Energy Transfer Group. As
of August 31, 2003, the receivable due from Energy Transfer Group for payroll
services was $146,141.
Energy Transfer has advanced working capital of $303,000 to a joint venture
partially owned by Energy Transfer, affiliates of ETC Holdings, L.P. and others.
ET GP, LLC, the general partner of ETC Holdings, L.P., has a general and
administrative services contract to act as an advisor and provide certain
general and administrative services to La Grange Energy
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and its affiliates, including Energy Transfer. The general and administrative
services that ET GP, LLC provides La Grange Energy and its subsidiaries under
this contract include:
- General oversight and direction of engineering, accounting, legal and
other professional and operational services required for the support,
maintenance and operation of the assets used in the Midstream operations;
and
- The administration, maintenance and compliance with contractual and
regulatory requirements.
In exchange for these services, La Grange Energy and its affiliates are
required to pay ET GP, LLC a $500,000 annual fee payable quarterly and pro-rated
for any portion of a calendar year. Pursuant to this contract, La Grange Energy
and its affiliates were also required to reimburse ET GP, LLC for expenses
associated with formation of La Grange Energy and its affiliates and are
required to indemnify ET GP, LLC, its affiliates, officers and employees for
liabilities associated with the actions of ET GP, LLC, its affiliates, officers,
and employees. As a result of the reimbursement provision, La Grange Energy
charged Energy Transfer $449,000 for expenses associated with its formation. For
the 11 months ended August 31, 2003, Energy Transfer was charged $375,000 under
this contract.
This general and administrative services contract will be terminated upon
the closing of the Energy Transfer transaction.
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DESCRIPTION OF UNITS
COMMON UNITS
Our common units are registered under the Securities Exchange Act of 1934
and are listed for trading on the New York Stock Exchange. Each holder of a
common unit is entitled to one vote per unit on all matters presented to the
limited partners for a vote except that holders of common units acquired by La
Grange Energy in connection with the Energy Transfer transaction will be
entitled to vote upon the proposal to change the terms of the class D units and
special units in the same proportion as the votes cast by the holders of the
common units other than La Grange Energy with respect to this proposal. In
addition, if at any time any person or group (other than our general partner and
its affiliates) owns beneficially 20% or more of all common units, any common
units owned by that person or group may not be voted on any matter and are not
considered to be outstanding when sending notices of a meeting of unitholders
(unless otherwise required by law), calculating required votes, determining the
presence of a quorum or for other similar purposes under our partnership
agreement. The common units are entitled to distributions of available cash as
described below under "Cash Distribution Policy." For a more detailed
description of the common units, please read "Description of the Common Units"
in the accompanying prospectus.
CLASS C UNITS
In conjunction with the transaction with U.S. Propane and the change of
control of our general partner in August 2000, we issued 1,000,000 newly created
class C units to Heritage Holdings in conversion of that portion of its
incentive distribution rights that entitled it to receive any distribution
attributable to the net amount received by us in connection with the settlement,
judgment, award or other final nonappealable resolution of specified litigation
filed by us prior to the transaction with U.S. Propane, which we refer to as the
"SCANA litigation." The class C units have a zero initial capital account
balance and were distributed by Heritage Holdings to its former stockholders in
connection with the transaction with U.S. Propane. Thus, U.S. Propane will not
receive any distributions made with respect to the SCANA litigation.
All decisions of our general partner relating to the SCANA litigation are
determined by a special litigation committee consisting of one or more
independent directors of our general partner. As soon as practicable after the
time that we receive any final cash payment as a result of the resolution of the
SCANA litigation, the special litigation committee will determine the aggregate
net amount of these proceeds distributable by us by deducting from the amounts
received all costs and expenses incurred by us and our affiliates in connection
with the SCANA litigation and any cash reserves necessary or appropriate to
provide for operating expenditures. Until the special litigation committee
decides to make this distribution, none of the distributable proceeds will be
deemed to be "available cash" under our partnership agreement. Please read "Cash
Distribution Policy" below for a discussion of available cash. When the special
litigation committee decides to distribute the distributable proceeds, the
amount of the distribution will be deemed to be available cash and will be
distributed as described below under "Cash Distribution Policy." The amount of
distributable proceeds that would be distributed to holders of incentive
distribution rights will instead be distributed to the holders of the class C
units, pro rata. We cannot predict whether we will receive any cash payments as
a result of the SCANA litigation and, if so, when these distributions might be
received.
The class C units do not have any rights to share in any of our assets or
distributions upon dissolution and liquidation of our partnership, except to the
extent that any such distributions consist of proceeds from the SCANA litigation
to which the class C unitholders would have otherwise been entitled. The class C
units do not have the privilege of conversion into any other unit and do not
have any voting rights except to the extent provided by law, in which case the
class C units will be entitled to one vote.
The amount of cash distributions to which the incentive distribution rights
are entitled was not increased by the creation of the class C units; rather, the
class C units are a mechanism for dividing the
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incentive distribution rights that Heritage Holdings and its former stockholders
would have been entitled to.
CLASS D UNITS
The class D units generally have voting rights that are identical to the
voting rights of the common units, and the class D units vote with the common
units as a single class on each matter with respect to which the common units
are entitled to vote. Each class D unit will initially be entitled to receive
100% of the quarterly amount distributed on each common unit, for each quarter,
provided that the class D units will be subordinated to the common units with
respect to the payment of the minimum quarterly distribution for such quarter
(and any arrearage in the payment of the minimum quarterly distribution for all
prior quarters). We are required, as promptly as practicable following the
issuance of the class D units, to submit to a vote of our unitholders a change
in the terms of the class D units to provide that each class D unit is
convertible into one common unit immediately upon such approval. Holders of the
class D units will be entitled to vote upon the proposal to change the terms of
the class D units and the special units in the same proportion as the votes cast
by the holders of the common units (other than the common units issued to La
Grange Energy in connection with the Energy Transfer transaction) with respect
to this proposal. If our unitholders do not approve this change in the terms of
the class D units within six months following the closing of the acquisition of
Energy Transfer, then each class D unit will be entitled to receive 115% of the
quarterly amount distributed on each common unit on a pari passu basis with
distributions on the common units.
Upon our dissolution and liquidation, each class D unit will initially be
entitled to receive 100% of the amount distributed on each common unit, but only
after each common unit has received an amount equal to its capital account, plus
the minimum quarterly distribution for the quarter, plus any arrearages in the
minimum quarterly distribution with respect to prior quarters. If, however, our
unitholders do not approve the change in the class D units to make them
convertible, then each class D unit will be entitled upon liquidation to receive
115% of the amount distributed to each common unit on a pari passu basis with
liquidating distributions on the common units.
CLASS E UNITS
In conjunction with our purchase of the capital stock of Heritage Holdings,
the 4,426,916 common units held by Heritage Holdings will be converted into
4,426,916 class E units. The class E units generally do not have any voting
rights but are entitled to vote on the proposals to make class D units and
special units convertible into common units. These class E units will be
entitled to aggregate cash distributions equal to 11.1% of the total amount of
cash distributed to all unitholders, including the class E unitholders, up to
$2.82 per unit per year. The class E units will be pledged to secure the $50
million promissory note payable to the Previous Owners. Upon a default under
this note, the class E units will be convertible into common units with a market
value of $100 million at the time of such default. Upon our full payment of the
promissory note, we plan to leave the class E units in the form described here
indefinitely. In the event of our termination and liquidation, the class E units
will be allocated 1% of any gain upon liquidation and will be allocated any loss
upon liquidation to the same extent as the common units. After the allocation of
such amounts, the class E units will be entitled to the balance in their capital
accounts, as adjusted for such termination and liquidation. The terms of the
class E units were determined in order to provide us with the opportunity to
minimize the impact to us of our ownership of Heritage Holdings, including the
$104 million in deferred tax liabilities of Heritage Holdings that we inherited
in connection with our purchase of Heritage Holdings. The class E units will be
treated as treasury stock for accounting purposes because they will be owned by
our wholly-owned subsidiary, Heritage Holdings. Due to the ownership of the
class E units by this corporate subsidiary, the payment of distributions on the
class E units will result in annual tax payments by Heritage Holdings at
corporate federal income tax rates, which tax payments will reduce the amount of
cash that would otherwise be available for distribution to us, as the owners of
Heritage Holdings. Because distributions on the class E units will be available
to us as the owner of Heritage Holdings, those funds will be available, after
payment of taxes, for our general partnership
S-89
purposes, including to satisfy working capital requirements, for the repayment
of outstanding debt and to make distributions to our unitholders. Although the
class E units are pledged to secure the $50 million promissory note payable to
the Previous Owners, distributions payable on the class E units are not required
to be used to retire such note. Because the class E units are not entitled to
receive any allocation of Partnership income, gain, loss, deduction or credit
that is attributable to our ownership of Heritage Holdings, such amounts will
instead be allocated to our general partner in accordance with its respective
interest and the remainder to all unitholders other than the holders of class E
units pro rata. In the event that Partnership distributions exceed $2.82 per
unit annually, all such amounts in excess thereof will be available for
distribution to unitholders other than the holders of class E units in
proportion to their respective interests.
SPECIAL UNITS
The special units are being issued by us as consideration for the Bossier
Pipeline (as described under "Business -- Overview -- Energy Transfer"). The
special units generally do not have any voting rights but are entitled to vote
on the proposal to change the terms of the special units in the same proportion
as the votes cast by the holders of the common units (other than the common
units issued to La Grange Energy in connection with the Energy Transfer
transaction) with respect to this proposal, and will not be entitled to share in
partnership distributions. We are required, as promptly as practicable following
the issuance of the special units, to submit to a vote of our unitholders the
approval of the conversion of the special units into common units in accordance
with the terms of the special units. Following unitholder approval and upon the
Bossier Pipeline becoming commercially operational, which we expect to occur in
mid-2004, each special unit will be immediately convertible into one common unit
upon the request of the holder. If the Bossier Pipeline does not become
operational by December 1, 2004 and, as a result, XTO Energy exercises rights to
acquire the Bossier Pipeline under its transportation contract, the special
units will no longer be considered outstanding and will not be entitled to any
rights afforded any other of our units. If our unitholders do not approve the
conversion of the special units in accordance with their terms prior to the time
the Bossier Pipeline becomes commercially operational, then each special unit
will be entitled to receive 115% of the quarterly amount distributed on each
common unit on a pari passu basis with distributions on common units, unless
subsequently converted into common units. Upon our dissolution and liquidation,
the special units will be entitled to receive an assignment of the three
contracts described in "Business -- Overview -- Energy Transfer" relating to the
Bossier Pipeline. If, however, our unitholders do not approve the conversion of
the special units into common units prior to the time the Bossier Pipeline
becomes commercially operational, then each special unit will be entitled to
receive 100% of the amount distributed on each common unit on a pari passu basis
with liquidating distributions on the common units.
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CASH DISTRIBUTION POLICY
Our partnership agreement requires us to distribute all of our "available
cash" to our unitholders and our general partner within 45 days following the
end of each fiscal quarter. The term "available cash" generally means, with
respect to any fiscal quarter of our partnership, all of our cash on hand at the
end of each quarter, plus working capital borrowings after the end of the
quarter, less reserves established by our general partner in its sole discretion
to provide for the proper conduct of our business, to comply with applicable law
or agreements, or to provide funds for future distributions to partners.
Immediately following the closing of the Energy Transfer transaction, we
will distribute at the end of each fiscal quarter available cash, excluding any
available cash to be distributed to our class C unitholders, as follows:
-- First, 98% to the common, class D and class E unitholders in
accordance with their percentage interests, and 2% to our general
partner, until each common unit has received $0.50 for that
quarter;
-- Second, 98% to all common, class D and class E unitholders in
accordance with their percentage interests, and 2% to our general
partner, until each common unit has received $0.55 for that
quarter;
-- Third, 85% to all common, class D and class E unitholders in
accordance with their percentage interests, and 15% to our general
partner, until each common unit has received $0.635 for that
quarter;
-- Fourth, 75% to all common, class D and class E unitholders in
accordance with their percentage interests, and 25% to our general
partner, until each common unit has received $0.825 for that
quarter;
-- Thereafter, 50% to all common, class D and class E unitholders in
accordance with their percentage interests, and 50% to our general
partner.
Notwithstanding the foregoing, the class D units will be subordinated to
the common units with respect to the payment of the minimum quarterly
distribution and any arrearage in the payment of the minimum quarterly
distribution for all prior quarters and the distributions on each class E unit
may not exceed $2.82 per year. Please read "Description of Units" for a
discussion of the class C units and the percentage interests in distributions of
the different classes of units.
If the unitholders do not approve changing the terms of the class D units
and special units within six months of the closing of the Energy Transfer
transaction to provide that these units are convertible into common units and
the Bossier Pipeline is commercially operational, then we will distribute
available cash, excluding any available cash to be distributed to our class C
unitholders, as follows:
-- First, 98% to the common, class D, class E and special unitholders
in accordance with their percentage interests, and 2% to our
general partner, with each class D and special unit receiving 115%
of the amount distributed on each common unit, until each common
unit has received $0.50 for that quarter;
-- Second, 98% to all common, class D, class E and special unitholders
in accordance with their percentage interests, and 2% to our
general partner, with each class D and special unit receiving 115%
of the amount distributed on each common unit, until each common
unit has received $0.55 for that quarter;
-- Third, 85% to all common, class D, class E and special unitholders
in accordance with their percentage interests, and 15% to our
general partner, with each class D and special unit receiving 115%
of the amount distributed on each common unit, until each common
unit has received $0.635 for that quarter;
S-91
-- Fourth, 75% to all common, class D, class E and special unitholders
in accordance with their percentage interests, and 25% to our
general partner, with each class D and special unit receiving 115%
of the amount distributed on each common unit, until each common
unit has received $0.825 for that quarter;
-- Thereafter, 50% to all common, class D, class E and special
unitholders in accordance with their percentage interests, with
each class D and special unit receiving 115% of the amount
distributed on each common unit, and 50% to our general partner.
Notwithstanding the foregoing, the distributions to the class E unitholders
may not exceed $2.82 per year. Please read "Description of Units" for a
discussion of the class C units and the percentage interests in distributions of
the different classes of units and "Cash Distribution Policy" in the
accompanying prospectus for a more detailed description of our cash distribution
policy. The form of amendment to our partnership agreement that creates the
class D units, class E units and special units is filed as an exhibit to the
registration statement of which this prospectus supplement is a part.
S-92
TAX CONSIDERATIONS
The tax consequences to you of an investment in our common units will
depend in part on your own tax circumstances. For a discussion of the principal
federal income tax considerations associated with our operations and the
purchase, ownership and disposition of our common units, see "Material Tax
Considerations" in the accompanying prospectus. You may wish to consult with
your own tax advisor about the federal, state, local and foreign tax
consequences peculiar to your circumstances.
We estimate that if you purchase common units in this offering and own them
through December 31, 2006 then you will be allocated, on a cumulative basis, an
amount of federal taxable income for such period that will be less than 20% of
the cash distributed with respect to that period. These estimates are based upon
the assumption that our available cash for distribution will approximate the
amount required to distribute cash to the holders of the common units in an
amount equal to the current quarterly distribution of $0.65 per unit and other
assumptions with respect to capital expenditures, cash flow and anticipated cash
distributions. These estimates and assumptions are subject to, among other
things, numerous business, economic, regulatory, competitive and political
uncertainties beyond our control. Further, the estimates are based on current
tax law and certain tax reporting positions that we have adopted with which the
IRS could disagree. Accordingly, we cannot assure you that the estimates will be
correct. The actual percentage of distributions that will constitute taxable
income could be higher or lower, and any differences could be material and could
materially affect the value of the common units. See "Material Tax
Considerations" in the prospectus accompanying this prospectus supplement.
Section 7704 of the Internal Revenue Code provides that publicly-traded
partnerships will, as a general rule, be taxed as corporations. However, an
exception, referred to as the "Qualifying Income Exception," exists with respect
to publicly traded partnerships whose gross income for every taxable year
consists of at least 90% "qualifying income." Qualifying income includes income
and gains derived from the processing, transportation and marketing of crude
oil, natural gas and products thereof, including the retail and wholesale
marketing of propane, certain hedging activities and the transportation of
propane and natural gas liquids. Other types of qualifying income include
interest other than from a financial business, dividends, gain on the sale of
real property and gains from the sale or other disposition of assets held for
the production of income that otherwise constitutes qualifying income. We
estimate that after the combination of our operations with those of Energy
Transfer approximately eight percent of our current gross income is not
qualifying income; however, this estimate could change from time to time. Based
upon and subject to this estimate, the factual representations made by us and
the general partner and a review of the applicable legal authorities, Vinson &
Elkins L.L.P. is of the opinion that at least 90% of our current gross income
after the combination of our operations with those of Energy Transfer
constitutes qualifying income.
S-93
UNDERWRITING
Subject to the terms and conditions stated in the underwriting agreement
dated the date of this prospectus supplement, which we will file as an exhibit
to the registration statement of which this prospectus supplement is a part,
each underwriter named below has agreed to purchase from us the number of common
units set forth opposite the underwriter's name.
<Table>
<Caption>
NUMBER OF
NAME OF UNDERWRITERS COMMON UNITS
- -------------------- ------------
Citigroup Global Markets Inc................................
Lehman Brothers Inc. .......................................
UBS Securities LLC..........................................
A.G. Edwards & Sons, Inc. ..................................
Wachovia Capital Markets, LLC...............................
Credit Suisse First Boston LLC..............................
RBC Dain Rauscher Inc. .....................................
Raymond James & Associates, Inc. ...........................
Stephens Inc. ..............................................
Total..................................................... 7,000,000
</Table>
The underwriting agreement provides that the underwriters' obligations to
purchase the common units depend on the satisfaction of the conditions contained
in the underwriting agreement, and that if any of the common units are purchased
by the underwriters, all of the common units must be purchased. The conditions
contained in the underwriting agreement include the condition that all the
representations and warranties made by us to the underwriters are true, that
there has been no material adverse change in the condition of us or in the
financial markets and that we deliver to the underwriters customary closing
documents. The underwriting agreement also provides that the underwriters'
obligations to purchase the common units depend upon the transactions associated
with our acquisition of Energy Transfer being consummated concurrently with this
offering.
COMMISSION AND EXPENSES
The following table shows the underwriting fees to be paid to the
underwriters by us in connection with this offering. These amounts are shown
assuming both no exercise and full exercise of the underwriters' option to
purchase additional common units. This underwriting fee is the difference
between the offering price to the public and the amount the underwriters pay to
us to purchase the common units.
<Table>
<Caption>
PAID BY US
---------------------------
NO EXERCISE FULL EXERCISE
----------- -------------
Per common unit............................................. $ $
Total..................................................... $ $
</Table>
We have been advised by the underwriters that the underwriters propose to
offer the common units directly to the public at the offering price to the
public set forth on the cover page of this prospectus supplement and to dealers
(who may include the underwriters) at this price to the public less a concession
not in excess of $ per unit. The underwriters may allow, and the dealers may
reallow, a concession not in excess of $ per unit to certain brokers and
dealers. After the offering, the underwriters may change the offering price and
other selling terms.
We estimate that total expenses of the offering, other than underwriting
discounts and commissions, will be approximately $4.5 million.
S-94
INDEMNIFICATION
We, our general partner and our operating partnerships have agreed to
indemnify the underwriters against certain liabilities, including liabilities
under the Securities Act of 1933, or to contribute to payments that may be
required to be made in respect of these liabilities.
OVER-ALLOTMENT OPTION
We have granted to the underwriters an option to purchase up to an
aggregate of 1,050,000 additional common units at the offering price to the
public less the underwriting discount set forth on the cover page of this
prospectus supplement exercisable to cover over-allotments. Such option may be
exercised in whole or in part at any time until 30 days after the date of this
prospectus supplement. If this option is exercised, each underwriter will be
committed, subject to satisfaction of the conditions specified in the
underwriting agreement, to purchase a number of additional common units
proportionate to the underwriter's initial commitment as indicated in the
preceding table, and we will be obligated, pursuant to the option, to sell these
common units to the underwriters. We will use the net proceeds from any exercise
of the underwriters' over-allotment option for general partnership purposes.
LOCK-UP AGREEMENTS
We, La Grange Energy, our general partner, the operating partnerships and
their general partners and the directors and executive officers of our general
partner have agreed that we and they will not, directly or indirectly, sell,
offer, pledge or otherwise dispose of any common units or enter into any
derivative transaction with similar effect as a sale of common units for a
period of 90 days after the date of this prospectus supplement without the prior
written consent of Citigroup Global Markets Inc. and Lehman Brothers Inc. The
restrictions described in this paragraph do not apply to:
- the issuance and sale of common units to the underwriters pursuant to the
underwriting agreement;
- the issuance of common units, class D units and special units to La
Grange Energy pursuant to the contribution agreement;
- the conversion of the common units held by Heritage Holdings into class E
units;
- the issuance of such limited partner interests and general partner
interests in us and Heritage Operating as may be required by Amendment
No. 3 to the Amended and Restated Agreement of Limited Partnership of
Heritage Operating and Amendment No. 5 to our partnership agreement;
- the issuance of common units pursuant to our Second Amended and Restated
Restricted Unit Plan dated as of February 4, 2002, our Long-Term
Incentive Compensation Plan dated as of September 1, 2000 and the
Employment Agreement of Michael L. Greenwood dated as of July 1, 2002;
- the issuance and sale of common units in a transaction not involving a
public offering to purchasers who enter into a similar agreement with the
underwriters; or
- the issuance of common units in one or more transactions from and after
30 days from the date of this prospectus supplement, utilizing our Form
S-4 registration statement for the contribution of assets to us or our
affiliates in exchange for common units, but not to exceed an aggregate
of 100,000 common units.
Citigroup Global Markets Inc. and Lehman Brothers Inc., in their sole
discretion, may release the units subject to lock-up agreements in whole or in
part at any time with or without notice. When determining whether or not to
release units from lock-up agreements, Citigroup Global Markets Inc. and Lehman
Brothers Inc. will consider, among other factors, our unitholders' reasons for
requesting the release, the number of units for which the release is being
requested and market conditions at the time.
S-95
STABILIZATION, SHORT POSITIONS AND PENALTY BIDS
In connection with this offering, the underwriters may engage in
stabilizing transactions, overallotment transactions, syndicate covering
transactions and penalty bids in accordance with Regulation M under the
Securities Exchange Act of 1934.
- Stabilizing transactions permit bids to purchase the underlying security
so long as the stabilizing bids do not exceed a specified maximum.
- Over-allotment transactions involve sales by the underwriters of the
common units in excess of the number of units the underwriters are
obligated to purchase, which creates a syndicate short position. The
short position may be either a covered short position or a naked short
position. In a covered short position, the number of units over-allotted
by the underwriters is not greater than the number of units they may
purchase in the over-allotment option. In a naked short position, the
number of units involved is greater than the number of units in the
over-allotment option. The underwriters may close out any short position
by either exercising their over-allotment option and/or purchasing common
units in the open market.
- Syndicate covering transactions involve purchases of the common units in
the open market after the distribution has been completed in order to
cover syndicate short positions. In determining the source of the common
units to close out the short position, the underwriters will consider,
among other things, the price of common units available for purchase in
the open market as compared to the price at which they may purchase
common units through the over-allotment option. If the underwriters sell
more common units than could be covered by the over-allotment option, a
naked short position, the position can only be closed out by buying
common units in the open market. A naked short position is more likely to
be created if the underwriters are concerned that there could be downward
pressure on the price of the common units in the open market after
pricing that could adversely affect investors who purchase in the
offering.
- Penalty bids permit the representatives to reclaim a selling concession
from a syndicate member when the common units originally sold by the
syndicate member are purchased in a stabilizing or syndicate covering
transaction to cover syndicate short positions.
These stabilizing transactions, over-allotment transactions, syndicate
covering transactions and penalty bids may have the effect of raising or
maintaining the market price of the common units or preventing or retarding a
decline in the market price of the common units. As a result, the price of the
common units may be higher than the price that might otherwise exist in the open
market. These transactions may be effected on the New York Stock Exchange or
otherwise and, if commenced, may be discontinued at any time.
Neither we nor any of the underwriters make any representation or
prediction as to the direction or magnitude of any effect that the transactions
described above may have on the price of the common units. In addition, neither
we nor any of the underwriters make any representation that the underwriters
will engage in these stabilizing transactions or that any transaction, if
commenced, will not be discontinued without notice.
LISTING
Our common units are traded on the New York Stock Exchange under the symbol
"HPG".
AFFILIATIONS
Some of the underwriters and their affiliates may in the future perform
various financial advisory, investment banking and other commercial banking
services in the ordinary course of business for us for which they will receive
customary compensation. Certain underwriters and their affiliates have performed
various financial advisory, investment banking and other commercial banking
services in the ordinary course of business with Heritage Propane Partners and
its other affiliates, including affiliates of its general
S-96
partner, for which they received customary compensation. Wachovia Capital
Markets, LLC, is a lender under the new Energy Transfer credit facility.
NASD CONDUCT RULES
The National Association of Securities Dealers, Inc. views the common units
offered hereby as interests in a direct participation program because of the
flow-through tax consequences to our limited partners. As a result, this
offering is being made in compliance with Rule 2810 of the NASD's Conduct Rules,
which imposes specific requirements on NASD members participating in an offering
relating to suitability standards for an investment in common units, due
diligence, disclosure in the prospectus and underwriters' compensation. These
requirements as applied to this offering are similar to those imposed on members
participating in public offerings of other securities that are listed on a
national securities exchange.
ELECTRONIC DISTRIBUTION
Lehman Brothers Inc., UBS Securities LLC, Credit Suisse First Boston LLC,
RBC Dain Rauscher Inc. and Raymond James & Associates, Inc. intend to e-mail
preliminary prospectus supplements in electronic format to certain of their
customers, but will not accept indications of interest, offers to purchase or
confirm sales electronically.
STAMP TAXES
Purchasers of the common units offered by this prospectus supplement may be
required to pay stamp taxes and other charges under the laws and practices of
the country of purchase, in addition to the offering price listed on the cover
of this prospectus supplement. Accordingly, we urge you to consult a tax advisor
with respect to whether you may be required to pay those taxes or charges, as
well as any other tax consequences that may arise under the laws of the country
of purchase.
VALIDITY OF THE COMMON UNITS
The validity of the common units will be passed upon for us by Vinson &
Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the
common units offered hereby will be passed upon for the underwriters by Baker
Botts L.L.P., Houston, Texas.
EXPERTS
The consolidated financial statements of Heritage Propane Partners, L.P.,
as of August 31, 2003 and 2002, and for each of the three years in the period
ended August 31, 2003, the financial statements of Bi-State Propane as of August
31, 2002 and for the year then ended, the consolidated balance sheet of U.S.
Propane, L.P., as of August 31, 2003, and the consolidated balance sheet of U.S.
Propane L.L.C., as of August 31, 2003, incorporated by reference in the
prospectus and elsewhere in the registration statement of which the prospectus
is a part, have been audited by Grant Thornton LLP, independent certified public
accountants, as indicated in their reports with respect thereto, and are
incorporated by reference in the prospectus in reliance upon the authority of
said firm as experts in giving such reports.
The combined financial statements of V-1 Oil Co. and V-1 Gas Co. as of
December 31, 2001 and 2000, and for each of the three years in the period ended
December 31, 2001, incorporated by reference in this prospectus and elsewhere in
the registration statement of which the prospectus is a part, have been audited
by Grant Thornton LLP, independent certified public accountants, as indicated in
their report with respect thereto, and are incorporated by reference in the
prospectus in reliance upon the authority of said firm as experts in giving such
reports.
The consolidated financial statements of Aquila Gas Pipeline Corporation
and Subsidiaries as of September 30, 2002 and December 31, 2001 and for the
periods ended September 30, 2002 and December 31, 2001 and 2000; and the
consolidated financial statements of Oasis Pipe Line Company as of
S-97
December 27, 2002 and the period then ended; and the combined financial
statements of Energy Transfer Company as of August 31, 2003 and for the eleven
months then ended, appearing in this prospectus supplement have been audited by
Ernst & Young LLP, independent auditors, as set forth in their reports thereon
appearing elsewhere herein, and are included in reliance upon such reports given
on the authority of such firm as experts in accounting and auditing. The audit
report covering the consolidated financial statements of Aquila Gas Pipeline
Corporation and Subsidiaries as of September 30, 2002 and December 31, 2001, and
for the periods ended September 30, 2002 and December 31, 2001 and 2000 refers
to a change in accounting for goodwill and other intangible assets.
The consolidated financial statements of Oasis Pipe Line Company and
subsidiaries as of December 31, 2001 and for the years ended December 31, 2001
and 2000 included in this prospectus supplement have been audited by Deloitte &
Touche LLP, independent auditors, as stated in their report appearing herein,
and are included in reliance upon the report of such firm given upon their
authority as experts in accounting and auditing.
S-98
INFORMATION REGARDING FORWARD LOOKING STATEMENTS
Certain matters discussed in this prospectus supplement, excluding
historical information, include certain "forward-looking" statements within the
meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Statements using words such as "anticipate,"
"believe," "intend," "project," "plan," "continue," "estimate," "forecast,"
"may," "will" or similar expressions help identify forward-looking statements.
Although we believe such forward-looking statements are based on reasonable
assumptions and current expectations and projections about future events, no
assurance can be given that every objective will be reached.
Actual results may differ materially from any results projected,
forecasted, estimated or expressed in forward-looking statements since many of
the factors that determine these results are subject to uncertainties and risks,
difficult to predict, and beyond management's control. Such factors include:
- the general economic conditions in the United States of America as well
as the general economic conditions and currencies in foreign countries;
- the political and economic stability of petroleum producing nations;
- the effect of weather conditions on demand for propane;
- the effectiveness of risk-management policies and procedures and the
ability of our liquids marketing counterparties to satisfy their
financial commitments;
- energy prices generally and specifically, the price of natural gas, the
price of NGLs, and the price of propane to the consumer compared to the
price of alternative and competing fuels;
- the relationship between natural gas and NGL prices;
- the general level of petroleum product demand and the availability and
price of propane supplies;
- our ability to obtain adequate supplies of propane for retail sale in the
event of an interruption in supply or transportation and the availability
of capacity to transport propane to market areas;
- hazards or operating risks incidental to midstream operations and to
transporting, storing and distributing propane that may not be fully
covered by insurance;
- the maturity of the propane industry and competition from other propane
distributors;
- the level of competition from other energy providers;
- energy efficiencies and technological trends;
- loss of key personnel;
- the availability and cost of capital and our ability to access certain
capital sources;
- changes in laws and regulations to which we are subject, including tax,
environmental, transportation and employment regulations;
- the costs and effects of legal and administrative proceedings; and
- our ability to successfully identify and consummate strategic
acquisitions at purchase prices that are accretive to our financial
results.
S-99
INDEX TO FINANCIAL STATEMENTS
<Table>
<Caption>
PAGE
----
Heritage Propane Partners, L.P. Unaudited Pro Forma Combined
Financial Statements:
Introduction.............................................. F-2
Pro Forma Combined Balance Sheet as of August 31, 2003.... F-4
Pro Forma Combined Statement of Operations for the Year
Ended August 31, 2003.................................. F-5
Notes to Unaudited Pro Forma Combined Financial
Statements............................................. F-6
Summary of La Grange Transaction and Related Pro Forma
Financial Statements................................... F-11
Energy Transfer Company Unaudited Pro Forma Combined
Statement of Operations for the Year Ended August 31,
2003................................................... F-12
Energy Transfer Company Notes to Unaudited Pro Forma
Combined Statement of Operations for the Year Ended
August 31, 2003........................................ F-13
Energy Transfer Company
Report of Independent Auditors............................ F-15
Combined Balance sheet as of August 31, 2003.............. F-16
Combined Income Statement for the period from October 1,
2002 Through August 31, 2003........................... F-17
Combined Statement of Partners' Capital for the period
from October 1, 2002 Through August 31, 2003........... F-18
Combined Statement of Cash Flows for the Period from
October 1, 2002 Through August 31, 2003................ F-19
Notes to Combined Financial Statements.................... F-20
Aquila Gas Pipeline Corporation:
Report of Independent Auditors............................ F-34
Consolidated Balance Sheets as of September 30, 2002 and
December 31, 2001...................................... F-35
Consolidated Statements of Income for the Nine Months
Ended September 30, 2002 and the years ended December
31, 2001 and 2000...................................... F-36
Consolidated Statements of Stockholder's Equity for the
Nine Months Ended September 30, 2002 and the Years
ended December 31, 2001 and 2000....................... F-37
Consolidated Statements of Cash Flows for the Nine Months
ended September 30, 2002 and the Years Ended December
31, 2001 and 2000...................................... F-38
Notes to Consolidated Financial Statements................ F-39
Oasis Pipe Line Company:
Report of Independent Auditors............................ F-53
Independent Auditors' Report.............................. F-54
Consolidated Balance Sheets as of December 27, 2002 and
December 31, 2001...................................... F-55
Consolidated Statements of Income for the Period from
January 1, 2002 Through December 27, 2002 and the Years
Ended December 31, 2001 and 2000....................... F-56
Consolidated Statements of Changes in Shareholders' Equity
for the Period From January 1, 2002 Through December
27, 2002 and the Years ended December 31, 2001 and
2000................................................... F-57
Consolidated Statements of Cash Flows for the Period From
January 1, 2002 Through December 27, 2002 and the Years
Ended December 31, 2001 and 2000....................... F-58
Notes to Consolidated Financial Statements................ F-59
</Table>
F-1
HERITAGE PROPANE PARTNERS, L.P.
UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS
INTRODUCTION
The pro forma financial statements are based upon the combined historical
financial position and results of operations of Heritage Propane Partners, L.P.
("Heritage") and La Grange Acquisition, L.P. which conducts business under the
name Energy Transfer Company ("Energy Transfer"). The pro forma financial
statements give effect to the following transactions:
- In November 2003, Heritage signed a definitive agreement with La Grange
Energy, L.P. ("La Grange Energy") pursuant to which La Grange Energy will
contribute its subsidiary Energy Transfer to Heritage in exchange for
cash, the assumption of debt and accounts payable and other specified
liabilities, Common Units, Class D Units and Special Units of Heritage.
Energy Transfer will distribute its cash and accounts receivable to La
Grange Energy and an affiliate of La Grange Energy will contribute an
office building to Energy Transfer, in each case prior to the
contribution of Energy Transfer to Heritage. Simultaneously with this
acquisition, La Grange Energy will obtain control of Heritage by
acquiring all of the interest in U.S. Propane, L.P., the general partner
of Heritage, and U.S. Propane, L.L.C., the general partner of U.S.
Propane L.P., from subsidiaries of AGL Resources, Inc., Atmos Energy
Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc.
(the "Utilities"). Heritage will also acquire all of the common stock of
Heritage Holdings, Inc. ("Heritage Holdings") from the Utilities. The
transactions described in this paragraph are collectively referred to as
the "Energy Transfer Transaction."
- Energy Transfer was formed on October 1, 2002, and is owned by its
limited partner, La Grange Energy, and its general partner, LA GP, LLC.
La Grange Acquisition, L.P. (La Grange Acquisition) is the limited
partner of ETC Gas Company, Ltd., ETC Texas Pipeline, Ltd., ETC
Processing, Ltd., ETC Marketing, Ltd., ETC Oasis Pipe Line, L.P. and ET
Company I, Ltd. (collectively, the "Operating Partnerships"). La Grange
Acquisition and the Operating Partnerships collectively form Energy
Transfer Company. In October 2002, Energy Transfer acquired the Texas and
Oklahoma natural gas gathering and gas processing assets of Aquila Gas
Pipeline Corporation, a subsidiary of Aquila, Inc., including 50% of the
capital stock of Oasis Pipe Line Company ("Oasis Pipe Line"), and a 20%
ownership interest in the Nustar Joint Venture. On December 27, 2002,
Oasis Pipe Line redeemed the remaining 50% of its capital stock and
cancelled the stock, resulting in Energy Transfer owning 100% of Oasis
Pipe Line. Energy Transfer contributed the assets acquired from Aquila
Gas Pipeline to the Operating Partnerships in return for its limited
partner interests in the Operating Partnerships. These transactions are
collectively referred to as the "La Grange Transactions."
The following pro forma combined financial statements include the
following:
- the unaudited pro forma balance sheet of Heritage, which gives pro forma
effect to the Energy Transfer Transaction as if such transaction occurred
on August 31, 2003;
- the unaudited pro forma statement of operations of Heritage, which
adjusts the pro forma statement of operations of Energy Transfer
described below to give pro forma effect to the Energy Transfer
Transaction as if such transaction occurred on September 1, 2002; and
- the unaudited pro forma statement of operations of Energy Transfer, which
gives pro forma effect to the La Grange Transactions as if such
transactions occurred on September 1, 2002.
SUMMARY OF ENERGY TRANSFER TRANSACTION AND RELATED PRO FORMA FINANCIAL
STATEMENTS
The following unaudited pro forma combined financial statements present (i)
unaudited pro forma balance sheet data at August 31, 2003, giving effect to the
Energy Transfer Transaction as if the Energy Transfer Transaction had been
consummated on that date and (ii) unaudited pro forma operating data for
F-2
the year ended August 31, 2003, giving effect to the Energy Transfer Transaction
and the La Grange Transactions as if such transactions had been consummated on
September 1, 2002. The unaudited pro forma combined balance sheet data combines
the August 31, 2003 balance sheets of Energy Transfer, which is contained
elsewhere in this prospectus supplement, Heritage, which is incorporated herein
by reference, and Heritage Holdings after giving effect to pro forma
adjustments. The unaudited pro forma combined statement of operations for the
year ended August 31, 2003, combines the pro forma results of operations for
Energy Transfer for the 12 months ended August 31, 2003, contained elsewhere in
this prospectus supplement, and the results of operations for Heritage for the
12 months ended August 31, 2003, incorporated herein by reference, and the
results of operations for Heritage Holdings after giving effect to pro forma
adjustments.
The Energy Transfer Transaction will be accounted for as a reverse
acquisition in accordance with Statement of Financial Accounting Standard No.
141. Although Heritage is the surviving parent entity for legal purposes, Energy
Transfer will be the acquiror for accounting purposes. The assets and
liabilities of Heritage will be reflected at fair value to the extent acquired
by Energy Transfer in accordance with EITF 90-13. The assets and liabilities of
Energy Transfer will be reflected at historical cost. A final determination of
the purchase accounting adjustments, including the allocation of the purchase
price to the assets acquired and liabilities assumed based on their respective
fair values, has not been made. Accordingly, the purchase accounting adjustments
made in connection with the development of the following summary pro forma
combined financial statements are preliminary and have been made solely for
purposes of developing such pro forma combined financial statements. However,
management does not believe that final adjustments will be materially different
from the amounts presented herein.
The following unaudited pro forma combined financial statements are
provided for informational purposes only and should be read in conjunction with
the separate audited combined financial statements of Energy Transfer (which are
included elsewhere in this prospectus supplement) and Heritage (which are filed
with Heritage's Annual Report filed on Form 10-K with the Securities and
Exchange Commission on November 26, 2003 and incorporated herein by reference).
The following unaudited pro forma combined financial statements are based on
certain assumptions and do not purport to be indicative of the results which
actually would have been achieved if the Energy Transfer Transaction and the La
Grange Transactions had been consummated on the dates indicated or which may be
achieved in the future.
F-3
HERITAGE PROPANE PARTNERS, L.P.
UNAUDITED PRO FORMA COMBINED BALANCE SHEET
AUGUST 31, 2003
<Table>
<Caption>
ENERGY HERITAGE HERITAGE PRO FORMA PRO FORMA
TRANSFER PROPANE HOLDINGS ADJUSTMENTS COMBINED
-------- -------- -------- ----------- ----------
(IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents.................................. $ 53,122 $ 7,117 $ 38 $ (53,122)(a) $ 43,081
271,500(b)
262,616(c)
(369,220)(d)
(4,500)(e)
(50,000)(h)
13,951(j)
(86,780)(k)
(1,641)(l)
Accounts receivable........................................ 105,987 35,879 -- (105,987)(a) 35,879
Inventories and exchanges.................................. 3,910 45,274 -- -- 49,184
Marketable securities and investments...................... -- 3,044 913 -- 3,957
Prepaid expenses and other current assets.................. 20,751 2,824 4,865 -- 28,440
-------- -------- -------- --------- ----------
Total current assets..................................... 183,770 94,138 5,816 (123,183) 160,541
PROPERTY, PLANT AND EQUIPMENT, net.......................... 393,025 426,588 -- 1,500(a) 863,160
5,000(d)
37,047(f)
INVESTMENT IN AFFILIATES.................................... 6,844 8,694 -- 2,403(f) 17,941
NOTE RECEIVABLE............................................. -- -- 11,539 (11,539)(g) --
INVESTMENT IN HERITAGE PROPANE.............................. -- -- 168,273 (168,273)(h) --
GOODWILL, net............................................... 13,409 156,595 -- 167,904(f) 278,245
(59,663)(m)
INTANGIBLES AND OTHER ASSETS, net........................... 3,645 52,824 -- 3,500(b) 86,884
15,758(f)
11,157(f)
-------- -------- -------- --------- ----------
Total assets............................................. $600,693 $738,839 $185,628 $(118,389) $1,406,771
======== ======== ======== ========= ==========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Working capital facility................................... $ -- $ 26,700 $ -- $ -- $ 26,700
Accounts payable........................................... 114,198 43,690 767 (114,198)(d) 44,457
Accrued and other current liabilities...................... 23,865 36,073 -- (23,865)(d) 36,073
Payable to associated companies, net....................... -- 6,255 1,505 -- 7,760
Current maturities of long-term debt....................... 30,000 38,309 -- (30,000)(d) 38,309
-------- -------- -------- --------- ----------
Total current liabilities............................... 168,063 151,027 2,272 (168,063) 153,299
LONG-TERM DEBT, less current maturities..................... 196,000 360,762 -- 275,000(b) 685,762
(196,000)(d)
50,000(h)
MINORITY INTERESTS AND OTHER................................ 157 4,002 -- (157)(d) 647
(3,355)(i)
DEFERRED INCOME TAXES....................................... 55,385 -- 103,930 -- 159,315
-------- -------- -------- --------- ----------
419,605 515,791 106,202 (42,575) 999,023
-------- -------- -------- --------- ----------
PARTNERS' CAPITAL:
General partner's capital.................................. -- 2,190 -- (90)(e) 14,476
4,685(f)
3,355(i)
15,507(j)
(9,944)(k)
(33)(l)
(1,194)(m)
Limited partners' capital, 24,915 issued and outstanding... 181,088 221,207 -- (157,609)(a) 385,782
262,616(c)
(3,336)(e)
173,665(f)
(1,175)(j)
147,183(k)
(392,064)(k)
(1,216)(l)
(44,228)(m)
(349)(n)
Common stock............................................... -- -- 5 (5)(h) --
Additional paid-in capital................................. -- -- 96,446 (11,539)(g) --
(84,907)(h)
Retained earnings.......................................... -- -- (16,973) 16,973(h) --
Class C limited partners capital, 1,000 authorized, issued
and outstanding.......................................... -- -- -- -- --
Class D limited partners' capital, 8,023 authorized, issued
and outstanding.......................................... -- -- -- (1,074)(e) 207,876
55,919(f)
(381)(j)
286,726(k)
(118,681)(k)
(392)(l)
(14,241)(m)
Treasury units -- class E units, 4,427 authorized, issued
and outstanding.......................................... -- -- -- (200,386)(h) (200,386)
Other comprehensive income (loss).......................... -- (349) (52) 52(h) --
349(n)
-------- -------- -------- --------- ----------
Total partners' capital................................. 181,088 223,048 79,426 (75,814) 407,748
-------- -------- -------- --------- ----------
Total liabilities and partners' capital................. $600,693 $738,839 $185,628 $(118,389) $1,406,771
======== ======== ======== ========= ==========
</Table>
See accompanying notes.
F-4
HERITAGE PROPANE PARTNERS, L.P.
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
YEAR ENDED AUGUST 31, 2003
<Table>
<Caption>
ENERGY
TRANSFER
PRO FORMA HERITAGE HERITAGE PRO FORMA PRO FORMA
COMBINED PROPANE HOLDINGS ADJUSTMENTS COMBINED
---------- -------- -------- ----------- ----------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
REVENUES.......................... $1,142,964 $571,476 $ -- $ -- $1,714,440
COSTS AND EXPENSES:
Cost of products sold........... 1,012,341 297,156 -- -- 1,309,497
Operating expenses.............. 22,735 152,131 435 -- 175,301
Depreciation and amortization... 15,996 37,959 -- 1,235(o) 56,342
1,051(p)
101(q)
Selling, general and
administrative............... 17,842 14,037 -- (90)(q) 31,789
---------- -------- ------- -------- ----------
Total costs and expenses..... 1,068,914 501,283 435 2,297 1,572,929
---------- -------- ------- -------- ----------
OPERATING INCOME (LOSS)........... 74,050 70,193 (435) (2,297) 141,511
OTHER INCOME (EXPENSE):
Interest expense................ (13,770) (35,740) (80) (4,355)(r) (53,945)
Equity in earnings (losses) of
affiliates................... (251) 1,371 8,251 (8,251)(s) 1,120
Gain on disposal of assets...... -- 430 -- (164)(t) 266
Other........................... (302) (3,213) 1,295 (692)(u) (2,912)
---------- -------- ------- -------- ----------
INCOME BEFORE MINORITY INTEREST
AND INCOME TAXES................ 59,727 33,041 9,031 (15,759) 86,040
MINORITY INTERESTS................ -- 876 -- (318)(v) 558
---------- -------- ------- -------- ----------
INCOME BEFORE INCOME TAXES........ 59,727 32,165 9,031 (15,441) 85,482
INCOME TAXES...................... 6,015 1,023 3,886 -- 10,924
---------- -------- ------- -------- ----------
NET INCOME........................ $ 53,712 $ 31,142 $ 5,145 $(15,441) 74,558
========== ======== ======= ========
GENERAL PARTNER'S INTEREST IN NET
INCOME.......................... 1,491
----------
LIMITED PARTNERS' INTEREST IN NET
INCOME.......................... $ 73,067
==========
BASIC AND DILUTED NET INCOME PER
LIMITED PARTNER UNIT............ $ 2.32
==========
BASIC AND DILUTED WEIGHTED AVERAGE
NUMBER OF UNITS OUTSTANDING..... 31,546
==========
</Table>
See accompanying notes.
F-5
HERITAGE PROPANE PARTNERS, L.P.
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
1. BASIS OF PRESENTATION AND OTHER TRANSACTIONS
The unaudited pro forma combined financial statements do not give any
effect to any restructuring cost, potential cost savings, or other operating
efficiencies that are expected to result from the Energy Transfer Transaction.
The unaudited pro forma combined financial statements are based on certain
assumptions and do not purport to be indicative of the results which actually
would have been achieved if the Energy Transfer Transaction had been consummated
on the dates indicated or which may be achieved in the future. The purchase
accounting adjustments made in connection with the development of the unaudited
pro forma combined financial statements are preliminary and have been made
solely for purposes of presenting such pro forma financial information.
It has been assumed that for purposes of the unaudited pro forma combined
balance sheet, the following transactions occurred on August 31, 2003, and for
purposes of the unaudited pro forma combined statement of operations, the
following transactions occurred on September 1, 2002. The unaudited pro forma
combined balance sheet data combines the August 31, 2003 balance sheets of
Energy Transfer, Heritage, and Heritage Holdings, after giving effect to pro
forma adjustments. The unaudited pro forma combined statement of operations for
the year ended August 31, 2003, combines the pro forma results of operations for
the year ended August 31, 2003 of Energy Transfer, with the results of
operations for the year ended August 31, 2003 of Heritage and Heritage Holdings,
after giving effect to pro forma adjustments.
In November 2003, Heritage signed a definitive agreement with La Grange
Energy pursuant to which La Grange Energy will contribute its subsidiary Energy
Transfer to Heritage in exchange for cash of $300,000, less the amount of Energy
Transfer debt in excess of $151,500, which will be repaid as part of the
transaction, and less Energy Transfer's accounts payable and other specified
liabilities plus any agreed upon capital expenditures paid by La Grange Energy
relating to the Energy Transfer business prior to closing, and $433,909 of
Common Units and Class D Units of Heritage. For purposes of these unaudited pro
forma combined financial statements, agreed upon capital expenditures of $5,000
have been assumed and the units are valued at $35.74, the average closing price
of Heritage's common units on the New York Stock Exchange for the period three
days before and three days after the signing of the definitive agreement on
November 6, 2003. In conjunction with the Energy Transfer Transaction, Energy
Transfer will distribute its cash and accounts receivables to La Grange Energy
and an affiliate of La Grange Energy will contribute an office building to
Energy Transfer, in each case prior to the contribution of Energy Transfer to
Heritage. La Grange Energy will also receive 3,742,515 Special Units as
contingent consideration for completing the Bossier Pipeline. If the Bossier
Pipeline does not become commercially operational by December 1, 2004 and, as a
result, XTO Energy, Inc. exercises rights to acquire the Bossier Pipeline
pursuant to its transportation contract, the Special Units will no longer be
considered outstanding and will not be entitled to any rights afforded any other
of our units. The Special Units will convert to Common Units upon the Bossier
Pipeline becoming commercially operational and such conversion being approved by
Heritage's unitholders. In accordance with Statement of Financial Accounting
Standards (SFAS) No. 141, the Special Units have not been recorded in the
following pro forma balance sheet.
Simultaneously with this acquisition, La Grange Energy will obtain control
of Heritage by acquiring all of the interest in U.S. Propane, L.P., the general
partner of Heritage, and U.S. Propane, L.L.C., the general partner of U.S.
Propane L.P., from the Utilities for $30,000. U.S. Propane, L.P. will contribute
its 1.0101% general partner interest in Heritage Operating, L.P. ("Heritage
Operating") to Heritage in exchange for an additional 1% general partner
interest in Heritage. Heritage will also buy the outstanding stock of Heritage
Holdings for $100,000 funded with $50,000 of cash and a $50,000 note payable to
the Utilities.
F-6
HERITAGE PROPANE PARTNERS, L.P.
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
These pro forma combined financial statements assume that concurrent with
the Energy Transfer Transaction, Energy Transfer will borrow $275,000 from
financial institutions, and Heritage Propane will raise $277,900 of gross
proceeds through the sale of 7,000,000 Common Units at an assumed offering price
of $39.70 per unit. The total of the proceeds will be used to finance the
transaction.
The Energy Transfer Transaction will be accounted for as a reverse
acquisition in accordance with SFAS No. 141. Although Heritage is the surviving
parent entity for legal purposes, Energy Transfer will be the acquiror for
accounting purposes. The assets and liabilities of Heritage Propane will be
reflected at fair value to the extent acquired by Energy Transfer, which will be
approximately 38.1%, determined in accordance with EITF 90-13. The assets and
liabilities of Energy Transfer will be reflected at historical cost. The
acquisition of Heritage Holdings by Heritage Propane will be accounted for as a
capital transaction as the primary asset held by Heritage Holdings is 4,426,916
Common Units of Heritage Propane. Following the acquisition of Heritage Holdings
by Heritage Propane, these Common Units will be converted to Class E Units. The
Class E Units will be recorded as treasury units in the unaudited pro forma
combined balance sheet.
If the Bossier Pipeline extension contingency described above occurs and
the Special Units convert to Common Units, the Common Units will be valued at
$35.74 per unit for total consideration of approximately $134 million. The
Bossier Pipeline will be recorded at its historical cost. The issuance of the
additional Common Units upon the conversion of the special units will adjust the
percent of Heritage Propane acquired in the Energy Transfer Transaction and will
result in an additional step-up being recorded in accordance with EITF 90-13. If
the Special Units were converted to Common Units in the pro forma balance sheet,
Energy Transfer would have acquired approximately 44.4% of Heritage Propane and
recorded approximately $39 million as an additional step-up in the assets and
liabilities of Heritage Propane.
The historical financial statements of Energy Transfer will become the
historical financial statements of the registrant. The results of operations of
Heritage Propane will be included with the results of Energy Transfer after
completion of the Energy Transfer Transaction. Energy Transfer was formed on
October 1, 2002 and will have an August 31 year-end. Accordingly, Energy
Transfer's 11-month period ended August 31, 2003, will be treated as a
transition period under the rules of the Securities and Exchange Commission.
The excess purchase price over predecessor cost was determined as follows:
<Table>
Net book value of Heritage Propane at August 31, 2003....... $ 223,048
Historical goodwill at August 31, 2003...................... (156,595)
Equity investment from public offering...................... 277,900
Treasury class E unit purchase.............................. (200,386)
---------
143,967
Percent of Heritage Propane acquired by La Grange Energy.... 38.1%
---------
Equity interest acquired.................................... $ 54,851
=========
Fair market value of limited partner units.................. $ 651,331
Purchase price of general partner interest.................. 30,000
Equity investment from public offering...................... 277,900
Treasury class E unit purchase.............................. (200,386)
---------
758,845
Percent of Heritage Propane acquired by La Grange Energy.... 38.1%
---------
</Table>
F-7
HERITAGE PROPANE PARTNERS, L.P.
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
Fair value of equity acquired............................... 289,120
Net book value of equity acquired........................... 54,851
---------
Excess purchase price over predecessor cost................. $ 234,269
=========
</Table>
For purposes of the pro forma balance sheet, the excess of purchase price
over predecessor costs have been allocated using the acquisition methodology
used by Heritage Propane when evaluating potential acquisitions. Following the
consummation of the Energy Transfer Transaction, an appraisal will be obtained
to record the final asset valuations. Management of Heritage Propane is in the
process of engaging an appraisal firm to perform the asset appraisal, however
management does not anticipate that the final valuation will be materially
different than the preliminary allocation. The preliminary allocation used in
the pro forma balance sheet is as follows:
<Table>
Property, plant and equipment (30 year life)................ $ 37,047
Investment in affiliate..................................... 2,403
Customer lists (15 year life)............................... 15,758
Trademarks.................................................. 11,157
Goodwill.................................................... 167,904
--------
$234,269
========
</Table>
For purposes of the pro forma statement of operations, pro forma basic and
diluted earnings per limited partner unit is calculated as follows:
<Table>
Basic pro forma net income per limited partner unit:
Limited partners' interest in pro forma net income.......... $73,067
=======
Historical weighted average limited partner units........... 16,636
Conversion of phantom units to common units upon change in
control................................................... 196
Units issued in this offering............................... 7,000
Common units and class D units issued in conjunction with
the Energy Transfer Transaction........................... 12,141
Common units converted to class E units and recorded as
treasury units............................................ (4,427)
-------
Weighted average limited partner units...................... 31,546
=======
Basic pro forma net income per limited partner unit......... $ 2.32
=======
Diluted pro forma net income per limited partner unit:
Limited partners' interest in pro forma net income.......... $73,067
=======
Historical weighted average limited partner units, assuming
dilutive effect of phantom units.......................... 16,694
Less weighted average phantom units outstanding............. (58)
Conversion of phantom units to common units upon change in
control................................................... 196
Units issued in this offering............................... 7,000
</Table>
F-8
HERITAGE PROPANE PARTNERS, L.P.
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
Common units and class D units issued in conjunction with
the Energy Transfer Transaction........................... 12,141
Common units converted to class E units and recorded as
treasury units............................................ (4,427)
-------
Weighted average limited partner units...................... 31,546
=======
Diluted pro forma net income per limited partner unit....... $ 2.32
=======
</Table>
2. PRO FORMA ADJUSTMENTS
(a) Reflects the distribution of cash and accounts receivable of Energy
Transfer to La Grange Energy and the contribution of an office building owned by
an affiliate of La Grange Energy to Energy Transfer.
(b) Reflects borrowing of $275,000 under the new Energy Transfer credit
facility, net of loan origination fees of $3,500. The borrowing is assumed to
have a fixed average interest rate of 5%.
(c) Reflects the net proceeds received from this offering assuming
7,000,000 Common Units of Heritage are sold at an offering price of $39.70 per
unit, net of underwriting discount of approximately $15,284.
(d) Reflects the repayment of Energy Transfer's existing debt, accounts
payable and other specified liabilities of Energy Transfer that were outstanding
immediately prior to the Energy Transfer Transaction and the reimbursement of
certain capital expenditures.
(e) Reflects cash used to pay offering and other transaction costs of
$4,500, allocated to the partners' capital accounts based on their ownership
percentages.
(f) Reflects the allocation of the excess purchase price over predecessor
costs to property, plant and equipment of $37,047, investment in affiliate of
$2,403, customer lists of $15,758, trademarks of $11,157 and goodwill of
$167,904, and the allocation to partners' capital based on their ownership
percentages.
(g) Reflects the elimination of a note receivable held by Heritage Holdings
that is to be distributed to the Utilities that own U.S. Propane, L.P.
(h) Represents cash paid of $50,000 and the issuance of a $50,000 7% note
payable to the Utilities for all of the common stock of Heritage Holdings and
the assumption of liabilities of Heritage Holdings of $104,697. The purchase
price is allocated as follows:
<Table>
Cash paid to the Utilities.................................. $ 50,000
Note payable to the Utilities............................... 50,000
Assumption of liabilities................................... 104,697
--------
$204,697
========
Allocated to assets as follows:
Current assets............................................ $ 4,311
Investment in Heritage Propane............................ 200,386
--------
$204,697
========
</Table>
The investment in Heritage Holdings is recorded as Treasury Units in the
unaudited pro forma combined balance sheet as Heritage Holdings becomes a
wholly-owned subsidiary of Heritage Propane as part of the Energy Transfer
Transaction.
(i) Reflects the contribution of U.S. Propane, L.P.'s 1.0101% general
partner interest in Heritage Operating to Heritage for an additional 1% general
partner interest in Heritage.
F-9
HERITAGE PROPANE PARTNERS, L.P.
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
(j) Reflects the contribution from U.S. Propane, L.P. to Heritage of cash
of $13,951 and an interest in Energy Transfer valued at $1,556 in connection
with this offering and the Energy Transfer Transaction in order to maintain its
2% general partner interest in Heritage.
(k) Reflects the payment of cash to La Grange Energy of $86,780 and the
issuance to La Grange Energy of 4,118,162 Common Units, representing 19.99% of
the number of Common Units assumed to be outstanding immediately prior to the
closing of the Energy Transfer Transaction (excluding the 4,426,916 common units
held by Heritage Holdings) after giving effect to the offering and 8,022,557
Class D Units of Heritage, representing the difference between 12,140,719 and
the assumed number of Common Units being issued to La Grange Energy. Also
reflects the allocation of such amounts to partners' capital based on their
ownership percentages.
<Table>
Cash paid to La Grange Energy for Energy Transfer........... $ 86,780
Issuance of 4,118,162 Common Units of Heritage.............. 147,183
Issuance of 8,022,557 Class D Units of Heritage............. 286,726
--------
$520,689
========
</Table>
(l) Reflects the payment of compensation to the executive officers of
Heritage Propane under the change of control provisions contained in the
executive officers' employment agreements, allocated to partners' capital based
on their ownership percentages.
(m) Reflects elimination of goodwill of Heritage Propane to the extent
Heritage Propane was acquired by Energy Transfer, and the allocation of such
amount to partners' capital based on their ownership interests.
(n) Reflects the elimination of accumulated other comprehensive income.
(o) Reflects the additional depreciation related to the step-up of net book
value of property, plant and equipment having 30-year lives.
(p) Reflects the additional amortization related to the step-up of net book
value of customer lists having lives of 15 years. Trademarks and goodwill are
indefinite-lived assets subject to annual tests for impairment.
(q) Reflects the effect on depreciation of the contribution of the Dallas
office building from an affiliate of La Grange Energy to Energy Transfer and the
reversal of rent previously paid.
(r) Allocation of additional interest expense of $13,250 related to the
$275,000 of borrowings under the term loan at an assumed average interest rate
of 5%, amortization of loan origination fees of $875 and $3,500 of additional
interest expense related to the issuance of a $50,000 note payable to the
Utilities at an average interest rate of 7%. This additional expense is offset
by the elimination of $13,770 of interest on the repayment of the Energy
Transfer debt of $226,000. A 1/8% change in the interest rate on the $275,000 of
borrowings under the term loan would change interest expense by approximately
$344.
(s) Reflects elimination of Heritage Holding's equity in earnings of
Heritage.
(t) Reflects the elimination of the gain on sale of assets as the assets
are recorded at fair market value.
(u) Reflects elimination of interest income from the note receivable of
$11,539 which was retained by the Utilities. The note receivable had an interest
rate of 6%.
(v) Reflects the elimination of minority interest expense for the 1.0101%
general partner's interest in Heritage Operating contributed to Heritage for an
additional 1% general partner interest in Heritage.
F-10
SUMMARY OF LA GRANGE TRANSACTIONS AND RELATED PRO FORMA FINANCIAL STATEMENTS
The following is Energy Transfer's unaudited pro forma combined statement
of operations for the year ended August 31, 2003.
The unaudited pro forma combined statement of operations gives pro forma
effect to the following transactions as if they had occurred on September 1,
2002.
- The October 1, 2002 purchase of the operating assets of Aquila Gas
Pipeline Corporation by Energy Transfer.
- The December 27, 2002 redemption by Oasis Pipe Line Company of the 50% of
its common stock held by Dow Hydrocarbons Resources, Inc., resulting in
Energy Transfer's becoming the 100% owner of Oasis Pipe Line Company.
- The December 27, 2002 contribution of other assets and a marketing
operation by ETC Holdings L.P. to Energy Transfer.
The Energy Transfer unaudited pro forma amounts are included in the pro
forma statements of Heritage, included on pages F-2 through F-9 elsewhere in the
prospectus supplement, which reflect the pro forma effects of the combination of
Heritage and Energy Transfer and the offering and related transactions as
contemplated in this prospectus supplement.
These transaction adjustments are presented in the notes to the Energy
Transfer unaudited pro forma combined statement of operations. The unaudited pro
forma combined statement of operations and accompanying notes should be read
together with the financial statements and related notes included elsewhere in
the prospectus.
The Energy Transfer unaudited pro forma combined statement of operations
was derived by adjusting the historical financial statements of Aquila Gas
Pipeline, Energy Transfer and Oasis Pipe Line Company. However, management
believes that the adjustments provide a reasonable basis for presenting the
significant effects of the transactions described above. The unaudited pro forma
combined statement of operations does not purport to present the results of
operations of Energy Transfer had the transactions above actually been completed
as of the dates indicated. Moreover, the unaudited pro forma combined statement
of operations does not project the results of operations of Energy Transfer for
any future date or period.
F-11
ENERGY TRANSFER COMPANY
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED AUGUST 31, 2003
<Table>
<Caption>
OASIS PIPE
ENERGY TRANSFER AQUILA GAS LINE FOUR ET COMPANY I
ELEVEN MONTHS PIPELINE ONE MONTHS FOUR MONTHS
ENDED MONTH ENDED ENDED ENDED
AUGUST 31, SEPTEMBER 30, DECEMBER 27, DECEMBER 27,
2003 2002 2002 2002 ADJUSTMENTS PRO FORMA
--------------- ------------- ------------ ------------ ----------- ----------
(IN THOUSANDS)
OPERATING REVENUES........... $1,008,723 $66,563 $11,532 $57,409 (1,263)(a) $1,142,964
COSTS AND EXPENSES:
Cost of sales.............. 899,539 59,691 283 55,003 (1,263)(a) 1,013,253
Operating.................. 19,081 1,669 1,424 561 -- 22,735
General and
administrative.......... 15,965 3 1,215 659 -- 17,842
Depreciation and
amortization............ 13,461 2,226 701 -- (1,241)(b) 15,996
849(c)
Unrealized (gain) on
derivatives............. (912) -- -- -- -- (912)
---------- ------- ------- ------- ------- ----------
Total costs and
expenses.............. 947,134 63,589 3,623 56,223 (1,655) 1,068,914
INCOME FROM OPERATIONS....... 61,589 2,974 7,909 1,186 392 74,050
OTHER INCOME (EXPENSE)....... 102 4 (408) -- -- (302)
EQUITY IN NET INCOME OF
AFFILIATE.................. 1,423 850 -- (94) (2,430)(d) (251)
INTEREST AND DEBT EXPENSES,
net........................ 12,057 393 (33) -- 1,353(e) 13,770
---------- ------- ------- ------- ------- ----------
INCOME BEFORE INCOME TAXES... 51,057 3,435 7,534 1,092 (3,391) 59,727
INCOME TAX EXPENSE........... 4,432 879 2,639 -- (1,056)(f) 6,015
(879)(g)
---------- ------- ------- ------- ------- ----------
NET INCOME................... $ 46,625 $ 2,556 $ 4,895 $ 1,092 $(1,456) $ 53,712
========== ======= ======= ======= ======= ==========
</Table>
F-12
ENERGY TRANSFER COMPANY
NOTES TO UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
1. BASIS OF PRESENTATION AND OTHER TRANSACTIONS
The historical financial information is derived from the historical
financial statements of our predecessor company, Aquila Gas Pipeline and
subsidiaries ("Aquila Gas Pipeline") as well as the financial statements of
Energy Transfer and Oasis Pipe Line Company ("Oasis") and ET Company I.
The pro forma statement of operations reflects the closing of the following
transactions as if they occurred on September 1, 2002:
- The October 1, 2002 purchase of the operating assets of Aquila Gas
Pipeline by Energy Transfer.
- The December 27, 2002 redemption by Oasis of the 50% of its common stock
held by Dow Hydrocarbons Resources, Inc, resulting in Energy Transfer
being the 100% owner of Oasis.
- The December 27, 2002 contribution of ET Company I, consisting of other
assets and a marketing operation, by ETC Holdings, L.P. to Energy
Transfer.
The following describes where each of the columns on the unaudited pro
forma combined statement of operations was derived:
Energy Transfer -- This column was derived from the audited financial
statements of Energy Transfer for the eleven months ended August 31, 2003.
Aquila Gas Pipeline -- Energy Transfer purchased the assets and operations
of Aquila Gas Pipeline effective October 1, 2002. After this date, the
operations are included in the Energy Transfer financial statements. This column
was derived from the unaudited financial statements of Aquila Gas Pipeline for
the one-month ended September 30, 2002.
Oasis Pipe Line -- Prior to December 27, 2002, Energy Transfer and its
predecessor, Aquila Gas Pipeline, owned 50% of Oasis and accounted for Oasis
under the equity method. On December 27, 2002 the remaining 50% of Oasis was
purchased. After this date, the results of Oasis's operations are consolidated
into the results of Energy Transfer. This column was derived from the unaudited
financial statements of Oasis for the four months ended December 27, 2002.
ET Company I -- ETC Holdings, L.P. contributed ET Company I to Energy
Transfer on December 27, 2002. After this date, ET Company I's results of
operations are included in the financial statements of Energy Transfer. This
column was derived from the unaudited financial statements of ET Company I for
the four month period ended December 27, 2002.
2. PRO FORMA ADJUSTMENTS
(a) Reflects the elimination of transportation revenue of Oasis for
services provided to Energy Transfer and Aquila Gas Pipeline for the four months
ended December 27, 2002.
(b) Reflects the decrease to depreciation expense resulting from the change
in carrying value of the basis in property plant and equipment as a result of
the acquisition of Aquila Gas Pipeline's assets.
(c) Reflects the increase to depreciation expense resulting from the change
in carrying value of Oasis's assets as a result of Oasis's redemption of the
equity interest held by Dow Hydrocarbons Resources, Inc. and the contribution of
other assets and marketing operations to Energy Transfer from ETC Holdings, L.P.
(d) Reflects the elimination of the equity method income derived from Oasis
prior to its becoming a wholly owned subsidiary.
(e) Reflects the adjustment to interest expense as a result of the
assumption of a September 1, 2002 purchase transaction date for the assets of
Aquila Gas Pipeline and the redemption of the Oasis equity
F-13
interests. In addition, this adjustment reflects the change in amortization of
the deferred financing costs as though these costs were incurred as of September
1, 2002.
(f) Reflects the reduction in income tax expense at Oasis as a result of an
intercompany note between Energy Transfer and Oasis. The proceeds from the note
were used to redeem the equity interest in Oasis held by Dow Hydrocarbons
Resources, Inc. It also reflects the tax effects of the change in depreciation
expense related to Oasis as described in (d).
(g) Reflects the elimination of income tax expense of Aquila Gas Pipeline.
Aquila was taxed as a "C" corporation as opposed to Energy Transfer's limited
partnership structure.
F-14
REPORT OF INDEPENDENT AUDITORS
To the Partners of
Energy Transfer Company
We have audited the accompanying combined balance sheet of Energy Transfer
Company as of August 31, 2003, and the related combined statements of income,
partners' capital, and cash flows for the eleven month period ended August 31,
2003. These financial statements are the responsibility of the Partnership's
management. Our responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit 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 audit provides a reasonable basis for our
opinion.
In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the combined financial position of Energy
Transfer Company as of August 31, 2003, and the combined results of their
operations and their cash flows for the eleven month period ended August 31,
2003 in conformity with accounting principles generally accepted in the United
States.
/s/ ERNST & YOUNG LLP
--------------------------------------
San Antonio, Texas
December 5, 2003
F-15
ENERGY TRANSFER COMPANY
COMBINED BALANCE SHEETS
<Table>
<Caption>
AUGUST 31,
2003
-------------
IN THOUSANDS
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 53,122
Accounts receivable....................................... 105,987
Deposits paid to vendors.................................. 19,053
Materials and supplies.................................... 2,071
Inventories and exchanges, net............................ 1,839
Price risk management asset............................... 928
Other current assets...................................... 770
--------
Total current assets........................................ 183,770
Equity method investments................................... 6,844
Property, plant and equipment............................... 406,697
Less -- Accumulated depreciation.......................... (13,672)
--------
Property, Plant and equipment, net.......................... 393,025
Goodwill.................................................... 13,409
Intangibles (net of $2,556 in amortization)................. 3,645
--------
Total assets................................................ $600,693
========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accounts payable.......................................... $114,198
Accounts payable to related parties....................... 820
Current maturities of long-term debt...................... 30,000
Deposits from customers................................... 11,600
Accrued expenses.......................................... 7,041
Price risk management liabilities......................... 823
Income taxes payable...................................... 2,567
Accrued interest.......................................... 1,014
--------
Total current liabilities.............................. 168,063
Long term debt.............................................. 196,000
Deferred income taxes....................................... 55,385
Other non-current liabilities............................... 157
Commitments and contingencies............................... --
Partners' capital........................................... 181,088
--------
Total liabilities and partners' capital..................... $600,693
========
</Table>
See accompanying notes.
F-16
ENERGY TRANSFER COMPANY
COMBINED INCOME STATEMENTS
<Table>
<Caption>
ELEVEN MONTHS ENDED
AUGUST 31, 2003
-------------------
IN THOUSANDS
OPERATING REVENUES
Third Party............................................... $1,008,014
Affiliated................................................ 709
----------
$1,008,723
COSTS AND EXPENSES:
Cost of sales............................................. 899,539
Operating................................................. 19,081
General and administrative................................ 15,965
Depreciation and amortization............................. 13,461
Unrealized (gain) on derivatives.......................... (912)
----------
Total costs and expenses............................... 947,134
----------
INCOME FROM OPERATIONS...................................... 61,589
OTHER INCOME................................................ 102
EQUITY IN NET INCOME OF AFFILIATE........................... 1,423
INTEREST AND DEBT EXPENSES, net............................. (12,057)
----------
INCOME BEFORE INCOME TAXES.................................. 51,057
INCOME TAX EXPENSE.......................................... (4,432)
----------
NET INCOME.................................................. $ 46,625
==========
</Table>
See accompanying notes.
F-17
ENERGY TRANSFER COMPANY
COMBINED STATEMENT OF PARTNERS' CAPITAL
FOR THE ELEVEN MONTHS ENDED AUGUST 31, 2003
<Table>
<Caption>
OPERATING
LAGRANGE ACQUISITION, LP PARTNERSHIPS'
------------------------- -------------
LIMITED GENERAL GENERAL TOTAL
PARTNER'S PARTNER'S PARTNER'S PARTNERS'
CAPITAL CAPITAL CAPITAL CAPITAL
---------- ---------- ------------- ---------
IN THOUSANDS
Capital contribution............................. $108,163 $108 $-- $108,271
ET Company 1 capital contribution................ 31,017 -- -- $ 31,017
Distribution to partners'........................ (4,815) (5) (5) (4,825)
Net income....................................... 46,531 47 47 46,625
-------- ---- --- --------
Balance August 31, 2003.......................... $180,896 $150 $42 $181,088
======== ==== === ========
</Table>
See accompanying notes.
F-18
ENERGY TRANSFER COMPANY
COMBINED STATEMENTS OF CASH FLOWS
IN THOUSANDS
<Table>
<Caption>
ELEVEN MONTHS ENDED
AUGUST 31, 2003
-------------------
OPERATING ACTIVITIES
Net income.................................................. $ 46,625
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization, including interest......... 15,772
Deferred income taxes..................................... (1,116)
Dividend from Oasis....................................... 1,000
Equity method income...................................... (1,423)
Other, net................................................ (40)
Changes in operating assets and liabilities
Accounts receivable.................................... (83,964)
Deposits to customers.................................. (16,962)
Materials and supplies................................. 526
Inventories and exchanges.............................. (627)
Price risk management liabilities, net................. (105)
Other current assets................................... (1,809)
Accounts payable....................................... 93,761
Accounts payable related party......................... 820
Accrued expenses....................................... 3,202
Deposits from customers................................ 11,600
Other long-term liabilities............................ 157
Income taxes payable................................... 2,567
Accrued interest....................................... 932
---------
Net cash provided by operating activities................... 70,916
INVESTING ACTIVITIES
Business acquisition........................................ (337,148)
Additions to property, plant and equipment.................. (13,872)
Proceeds from sale of assets................................ 9,843
---------
Net cash used in investing activities....................... (341,177)
FINANCING ACTIVITIES
Capital contribution........................................ 108,723
Distributions to partners................................... (4,825)
Borrowings under credit facility............................ 246,000
Principal payments under credit facility.................... (20,000)
Deferred financing fees..................................... (6,515)
---------
Net cash provided in financing activities................... 323,383
---------
Net increase in cash and cash equivalents................... 53,122
Cash and cash equivalents, beginning of period.............. --
---------
Cash and cash equivalents, end of period.................... $ 53,122
=========
</Table>
See accompanying notes.
F-19
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS
ELEVEN MONTHS ENDED AUGUST 31, 2003
1. SUMMARY OF BUSINESS, BASIS OF PRESENTATION, AND SIGNIFICANT ACCOUNTING
POLICIES
ORGANIZATION AND BUSINESS
Energy Transfer Company is a group of partnerships under common control and
consists of La Grange Acquisition, L.P. (La Grange Acquisition) and a series of
its limited partner investees. La Grange Acquisition, L.P. is a Texas limited
partnership formed on October 1, 2002 and is 99.9% owned by its limited partner,
La Grange Energy, L.P. (La Grange Energy), and 0.1% owned by its general
partner, LA GP, LLC. La Grange Acquisition is the 99.9% limited partner of ETC
Gas Company, Ltd., ETC Texas Pipeline, Ltd., ETC Processing, Ltd., and ETC
Marketing, Ltd. and a 99% limited partner of ETC Oasis Pipe Line, L.P. and ET
Company I, Ltd. (collectively, the "Operating Partnerships"). The general
partners of La Grange Acquisition, La Grange Energy, and the Operating
Partnerships are ultimately owned and controlled by members of management and a
private equity investor group. La Grange Acquisition and the Operating
Partnerships conduct business under the name Energy Transfer Company. These
financial statements present the accounts of La Grange Acquisition and the
Operating Partnerships (collectively, the "Partnership" or "Energy Transfer") on
a combined basis as entities under common control.
Under state law and the terms of various partnership agreements, the
limited partners' potential liability is limited to their investment in the
various partnerships. The general partners of the various partnerships manage
and control the business and affairs of each partnership. The limited partners
are not involved in the management and control of the Partnership. Since all of
the general partners in the various partnerships are ultimately owned and
controlled by members of management and a private equity investor group, all of
the entities that form Energy Transfer, as defined above, are managed and are
under the common control of this control group.
In October 2002, La Grange Acquisition acquired the Texas and Oklahoma
natural gas gathering and gas processing assets of Aquila Gas Pipeline
Corporation (Aquila Gas Pipeline), a subsidiary of Aquila, Inc. for $264
million, including 50% of the capital stock of Oasis Pipe Line Company, a
Delaware Corporation, ("Oasis Pipe Line"), 20% ownership interest in the Nustar
Joint Venture, and an interest in another immaterial venture. On December 27,
2002, Oasis Pipe Line redeemed the remaining 50% of its capital stock owned by
Dow Hydrocarbons Resources, Inc. for $87 million, and cancelled the stock. Thus,
Energy Transfer now owns 100% of the outstanding capital stock of Oasis Pipe
Line. La Grange Acquisition contributed the assets acquired from Aquila, Inc. to
the Operating Partnerships in return for its limited partner interests in the
Operating Partnerships.
The Partnership owns and operates natural gas gathering, natural gas
intrastate pipeline systems, and gas processing plants and is in the business of
purchasing, gathering, compressing, transporting, processing, and marketing
natural gas and natural gas liquids (NGLs) in the states of Texas, Oklahoma, and
Louisiana.
COMBINATION
The accompanying combined financial statements include the accounts of La
Grange Acquisition and the Operating Partnerships after the elimination of
significant intercompany balances and transactions. Further, La Grange
Acquisition's limited partner investments in each of the Operating Partnerships
have been eliminated against the Operating Partnerships' limited partners'
capital.
USE OF ESTIMATES
The preparation of financial statements in conformity with Generally
Accepted Accounting Principles (GAAP) in the United States requires management
to make estimates and assumptions that affect the
F-20
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
reported amounts of assets and liabilities, the disclosure of contingent assets
and liabilities at the date of the financial statements, and the reported
amounts of revenues and expenses during the reporting period. The more
significant areas requiring the use of estimates relate to the fair value of
financial instruments and useful lives for depreciation. Actual results may
differ from those estimates.
CASH AND CASH EQUIVALENTS
All highly liquid investments with an original maturity of three months or
less are considered to be cash equivalents. The Partnership's carrying amounts
for cash and cash equivalents, other current assets and other current
liabilities approximate fair value.
ACCOUNTS RECEIVABLE
Energy Transfer deals with counter parties that are typically either
investment grade (Standard & Poors BBB- or higher) or are otherwise secured with
a letter of credit or other form of security (corporate guaranty or prepayment).
The credit committee reviews accounts receivable balances each week. Credit
limits are assigned and monitored for all counter parties. The majority of
payments are due on the 25th of the month following delivery.
Management closely monitors credit exposure for potential doubtful
accounts. Management believes that an occurrence of bad debt is unlikely;
therefore an allowance for doubtful accounts is not included on the balance
sheet. Bad debt expense is recognized at the time the bad debt occurs. An
accounts receivable will be written off when the counter party files for
bankruptcy protection or the account is turned over for collection and the
collector deems the account uncollectible. We did not record any bad debt
expense during the 11 months ended August 31, 2003.
DEPOSITS
Deposits are paid to vendors as pre-payments for gas deliveries in the
following month. Pre-payments are required when the volume of business with the
vendor exceeds the Partnership's credit limit. Deposits with vendors for gas
purchases are $17.0 million at August 31, 2003. The Partnership also has
deposits with derivative counterparties at August 31, 2003 of $2.1 million.
Deposits are received from customers as pre-payments for gas deliveries in
the following month. Pre-payments are required when customers exceed their
credit limit or do not qualify for open credit. Deposits received from customers
for gas sales are $11.6 million at August 31, 2003.
MATERIALS AND SUPPLIES
Materials and supplies are stated at the lower of cost (determined on a
first-in, first-out basis) or market value.
INVENTORIES AND EXCHANGES
Inventories and exchanges consist of NGLs on hand or natural gas and NGL
delivery imbalances with others and are presented net by customer/supplier on
the accompanying combined balance sheet. These amounts turn over monthly and
management believes the cost approximates market value. Accordingly, these
volumes are valued at market prices on the combined balance sheet.
PRICE RISK MANAGEMENT ASSETS AND LIABILITIES
The Partnership follows FASB Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities," (Statement No. 133) as amended by FASB
Statement No. 138, "Accounting for
F-21
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Certain Derivative Activities and Certain Hedging Activities" (Statement No.
138). These statements establish accounting and reporting standards for
derivative instruments and hedging activities. They require that every
derivative instrument (including certain derivative instrument embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair market value. The statements require that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge criteria are met.
Special accounting for qualifying hedges allows a derivative's gain and
loss 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. Energy Transfer
believes that some of its derivative contracts could qualify as hedges under
Statement No. 133; however, at August 31, 2003 no positions have been formally
designated as hedges.
Energy Transfer utilizes various exchange-traded and over-the-counter
commodity financial instrument contracts to limit its exposure to margin
fluctuations in natural gas and NGLs prices. These contracts consist primarily
of futures and swaps. The net gain or loss arising from marking to market those
derivative instruments is currently recognized in earnings. In the course of
normal operations, Energy Transfer also routinely enters into forward physical
contracts for the purchase and sale of natural gas and NGLs along various points
of its system. These positions require physical delivery and are treated as
normal purchase and sales contracts under Statement No. 133. Accordingly, these
contracts are not marked to market on the accompanying combined balance sheets.
Unrealized gains and losses on commodity derivatives are classified as such on
the combined statement of income. Realized gains and losses on commodity
derivatives are included in operating revenues, while realized and unrealized
gains and losses on interest rate swaps are included in interest expense.
The market prices used to value the financial derivative transactions
reflect management's estimates considering various factors including closing
exchange and over-the-counter quotations, and the time value of the underlying
commitments. The values are adjusted to reflect the potential impact of
liquidating a position in an orderly manner over a reasonable period of time
under present market conditions.
DEFERRED FINANCING FEES
Deferred financing fees, included in other assets, are amortized using the
effective interest method.
INVESTMENTS
From October through December 2002, the Partnership owned a 20% interest in
the Nustar Joint Venture. Effective December 27, 2002, the Partnership owned a
50% interest in Vantex Gas Pipeline Company, LLC, and a 49% interest in Vantex
Energy Services, Ltd. The Partnership also owns an interest in an immaterial
venture. The Partnership accounts for these investments under the equity method
of accounting. The Nustar Joint Venture, located in West Texas, is composed of
approximately 290 miles of pipeline and the Benedum processing facility. The
Vantex system is located in East Texas and is composed of approximately 250
miles of pipeline. Vantex Energy Services provides energy related marketing
services to small and medium sized producers and end users on the Vantex Gas
Pipeline system.
Prior to December 27, 2002, when the remaining 50% of Oasis Pipe Line
capital stock was redeemed, the Partnership accounted for its initial 50%
ownership in Oasis Pipe Line under the equity method. During the three month
period ended December 31, 2002, the Partnership recognized $1.6 million of
equity method income from the investment in Oasis Pipe Line prior to the
redemption of the remaining 50% of the capital stock. Oasis results from
operations are recognized on a consolidated basis effective January 1, 2003.
F-22
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Effective January 1, 2003, Energy Transfer sold its interest in the Nustar
Joint Venture for $9.6 million. No gain or loss was recognized, as the proceeds
equaled the value assigned to the joint venture in the October 2002 purchase
allocation.
PROPERTY, PLANT, AND EQUIPMENT
Pipeline, property, plant, and equipment are stated at cost. Additions and
improvements that add to the productive capacity or extend the useful life of
the asset are capitalized. Expenditures for maintenance and repairs that do not
add capacity or extend the useful life are charged to expense as incurred. Upon
disposition or retirement of pipeline components or gas plant components, any
gain or loss is recorded to accumulated depreciation. When entire pipeline
systems, gas plants or other property and equipment are retired or sold, any
gain or loss in included in operations.
Depreciation of the gathering pipeline systems, gas plants, and processing
equipment is provided using the straight-line method based on an estimated
useful life of primarily 20 years. The transportation pipeline is depreciated
using the straight-line method based on an estimated useful life of primarily 65
years. There was no interest cost capitalized for the period ended August 31,
2003.
Energy Transfer reviews its tangible and finite life intangible assets for
impairment whenever facts and circumstances indicate impairment may be present.
When impairment indicators are present, the Partnership evaluates whether the
assets in question are able to generate sufficient cash flows to recover their
carrying value on an undiscounted basis. If not, the Partnership impairs the
assets to their fair value, which may be determined based on discounted cash
flows. To date no impairments have been recognized.
GOODWILL
The goodwill represents the fair value of the partnership interests granted
to ETC Holdings, L.P. on the contribution of ET Company I in excess of the fair
value of the tangible assets contributed. ET Company I included a gas marketing
operation, which has no significant assets other than an assembled workforce and
marketing expertise. The goodwill is principally the value assigned to the
marketing operation of ET Company I. The goodwill is included in our Midstream
segment and will be reviewed annually for impairment.
FEDERAL AND STATE INCOME TAXES
La Grange Acquisition and the Operating Partnerships are organized under
the provisions of the Texas Revised Limited Partnership Act. Therefore, the
payment and recognition of income taxes are the responsibility of the partners,
except as noted below.
Energy Transfer owns Oasis Pipe Line, a corporation and tax-paying entity,
which provides for income taxes currently payable and for deferred income taxes
in accordance with Financial Accounting Standards Board (FASB) Statement No.
109, "Accounting for Income Taxes" (Statement No. 109). Statement No. 109
requires that deferred tax assets and liabilities be established for the basis
differences between the reported amounts of assets and liabilities for financial
reporting purposes and income tax purposes.
CASH PAID FOR INTEREST AND INCOME TAXES
The following provides information related to cash paid for interest and
income taxes by the Partnership for the eleven months ended August 31, 2003.
<Table>
<Caption>
(IN THOUSANDS)
Interest.................................................... $8,486
Income Taxes................................................ $2,935
</Table>
F-23
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
REVENUE RECOGNITION
We recognize revenue for sales of natural gas and NGLs upon delivery.
Service revenues, including transportation, treating, compression, and gas
processing, are recognized at the time service is preformed. Transportation
capacity payments are recognized when earned in the period the capacity was made
available.
SHIPPING AND HANDLING COSTS
In accordance with the Emerging Issues Task Force Issue 00-10, "Accounting
for Shipping and Handling Fees and Costs", the Partnership has classified all
deductions from producer payments for fuel, compression and treating, which can
be considered handling costs, as revenue. The fuel costs are included in costs
of sales, while the remaining costs are included in operating costs.
2. ACQUISITIONS AND SALES
As previously discussed, on October 1, 2002, La Grange Acquisition
purchased certain operating assets from Aquila Gas Pipeline, primarily natural
gas gathering, treating and processing assets in Texas and Oklahoma. The assets
acquired and preliminary purchase price allocation were as follows:
<Table>
<Caption>
(IN THOUSANDS)
Materials and supplies...................................... $ 2,596
Other assets................................................ 179
Property, plant, and equipment.............................. 211,783
Investment in Oasis......................................... 41,670
Investment in the Nustar Joint Venture...................... 9,600
Accrued expenses............................................ (1,753)
--------
$264,075
========
</Table>
At the closing of the acquisition of Aquila Gas Pipeline's assets, $5
million was put into escrow until such time that proper consents and conveyance
could be achieved related to a sales contract. It was later determined that it
was unlikely that a proper conveyance could be achieved which resulted in the
escrowed amount of $5 million being returned to La Grange Acquisition during the
eight months ended August 31, 2003. The return of the $5 million purchase price
reduced La Grange Acquisition's basis in property, plant and equipment.
On December 27, 2002, Oasis Pipe Line purchased the remaining 50% of its
capital stock owned by Dow Hydrocarbons resources, Inc. for $87 million, and
cancelled the stock. Energy Transfer now owns 100% of the capital stock of Oasis
Pipe Line.
Also, on December 27, 2002, ETC Holdings, LP, a limited partner of La
Grange Energy, contributed ET Company I to the Partnership. The investment in
the Vantex system was included in the assets contributed.
F-24
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The following unaudited pro forma financial information for the period
ended August 31, 2003 assumes that both Oasis Pipe Line and ET Company I were
wholly owned as of October 1, 2002 (Inception).
<Table>
<Caption>
(IN THOUSANDS)
PRO FORMA FINANCIAL INFORMATION
Operating Revenues.......................................... $1,063,729
Total Costs and Expenses.................................... $ 983,128
Income from Operations...................................... $ 69,314
Net income.................................................. $ 48,739
</Table>
3. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment, at cost, consisted of the following:
<Table>
<Caption>
ESTIMATED USEFUL BALANCE AT
LIVES (YEARS) AUGUST 31, 2003
---------------- ---------------
(IN THOUSANDS)
Land.................................................... N/A $ 992
Midstream buildings..................................... 15 798
Midstream pipelines and equipment....................... 20 215,099
Midstream right of way.................................. 20 336
Transportation pipeline................................. 65 126,526
Transportation right of way............................. 65 3,721
Transportation buildings................................ 20 189
Transportation equipment................................ 10-20 42,771
Linepack................................................ N/A 5,176
Construction in progress................................ N/A 7,414
Other................................................... 5 3,675
--------
Total................................................. 406,697
Accumulated depreciation and amortization............. (13,672)
--------
Property, plant and equipment, net.................... $393,025
========
</Table>
4. INTANGIBLE ASSETS
As of August 31, 2003, intangibles, at cost, consisted of the following:
<Table>
<Caption>
(IN THOUSANDS)
Deferred financing fees..................................... $ 5,724
Amortization................................................ (2,464)
-------
3,260
Other intangibles........................................... 477
Amortization................................................ (92)
-------
385
-------
Total intangibles........................................... $ 3,645
=======
</Table>
F-25
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Deferred financing fees relate to the Term Note (See Note 7 -- Debt) and
are being amortized over the life of the note using the interest rate method.
Other intangibles include a land use lease, which is being amortized over
the life of the lease.
The following is the scheduled amortization of intangibles for the next
five years:
<Table>
<Caption>
IN THOUSANDS
2004........................................................ $2,404
2005........................................................ $ 918
2006........................................................ $ 82
2007........................................................ $ 48
2008........................................................ $ 48
Thereafter.................................................. $ 145
</Table>
5. INVESTMENTS
NUSTAR JOINT VENTURE
At December 31, 2002, the Partnership owned a 20% interest in the Nustar
Joint Venture, which was accounted for under the equity method. The Nustar Joint
Venture, located in West Texas, was composed of approximately 290 miles of
pipeline and the Benedum processing facility. In January 2003, the Partnership
sold its 20% interest for $9.6 million resulting in no gain or loss.
VANTEX
At August 31, 2003, ET Company I owned a 50% interest in Vantex Gas
Pipeline Company and a 49% interest in Vantex Energy Services, Ltd., with both
interests accounted for under the equity method. The Partnership's equity
investment value in the Vantex System at August 31, 2003 was $7.2 million. The
Vantex System interests were owned ET Company I and were contributed to the
Partnership on December 27, 2002 by ETC Holdings, LP. The $7.2 million
investment at August 31, 2003 exceeds ET Company I's historical underlying
equity in the Vantex System by $336,000.
The following presents financial information related to the Vantex
investments for the 11 months ended August 31, 2003.
<Table>
<Caption>
(IN THOUSANDS)
STATEMENT OF INCOME INFORMATION
Revenues.................................................... $13,116
Income before income tax expense............................ $ 333
The Partnership's share of net income....................... $ 165
The Partnership's share of distributions.................... --
</Table>
Total earnings from equity method investments for the 11 months ended
August 31, 2003, excluding Oasis Pipe Line, was a loss of $149,000. This
includes the Partnership's share of net income from Vantex of $165,000 and the
Partnership's share of equity method loss of $314,000 from its other joint
venture investments, including a loss from the Nustar Joint Venture prior to its
sales.
6. RELATED-PARTY TRANSACTIONS
Beginning in 2003 and after the contribution of ET Company I to Energy
Transfer, the Partnership is charged rent by an affiliate for office space in
Dallas, which is shared with La Grange Energy and ETC
F-26
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Holdings, L.P. For the 11 months ended August 31, 2003, the rent charged to the
Partnership was $90,000.
Prior to the Oasis Pipe Line stock redemption and the contribution of ET
Company I, Energy Transfer had purchases and sales of natural gas with Oasis
Pipe Line and ET Company I in the normal course of business. The following table
summarizes these transactions:
<Table>
<Caption>
OCTOBER 1, 2002 (INCEPTION)
THROUGH DECEMBER 31, 2002
---------------------------
(IN THOUSANDS)
Sales of natural gas to affiliated companies................ $4,488
Purchases of natural gas from affiliated companies.......... $3,989
Transportation expenses..................................... $ 922
</Table>
During 2003, ETC Texas Pipeline, Ltd, one of the Operating Partnerships,
purchased a compressor, initially ordered by Energy Transfer Group, L.L.C. (ETG)
for $799,000. ETG is a 66% owned subsidiary of ETC Holdings, L.P. ETG has a
contract to provide compression services to a third party for a fixed monthly
fee. Proceeds from the contract will be remitted by ETG to ETC Texas Pipeline,
Ltd. to provide a 14.6% return on investment for the capital investment made by
ETC Texas Pipeline, Ltd. As of August 31, 2003, no fees had been remitted, but
income of $7,000 has been accrued under the contract. In addition, a $200,000
deposit was made to a third party vendor by ETC Texas Pipeline, Ltd. on behalf
of ETG.
Energy Transfer also provides payroll services to ETG. As of August 31,
2003, the receivable due from ETG for payroll services was $146,141.
Energy Transfer has advanced working capital of $303,000 to a joint venture
partially owned by Energy Transfer, affiliates of ETC Holdings, L.P. and others.
ET GP, LLC, the general partner of ETC Holdings, L.P., has a general and
administrative services contract to act as an advisor and provide certain
general and administrative services to La Grange Energy and its affiliates,
including Energy Transfer. The general and administrative services that ET GP,
LLC provides La Grange Energy and its subsidiaries under this contract include:
- General oversight and direction of engineering, accounting, legal and
other professional and operational services required for the support,
maintenance and operation of the assets used in the Midstream operations;
and
- The administration, maintenance and compliance with contractual and
regulatory requirements.
In exchange for these services, La Grange Energy and its affiliates are
required to pay ET GP, LLC a $500,000 annual fee payable quarterly and pro-rated
for any portion of a calendar year. Pursuant to this contract, La Grange Energy
and its affiliates were also required to reimburse ET GP, LLC for expenses
associated with formation of La Grange Energy and its affiliates and are
required to indemnify ET GP, LLC, its affiliates, officers and employees for
liabilities associated with the actions of ET GP, LLC, its affiliates, officers,
and employees. As a result of the reimbursement provision, La Grange Energy
charged Energy Transfer $449,000 for expenses associated with its formation. For
the 11 months ended August 31, 2003, Energy Transfer was charged $375,000 under
this contract.
F-27
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
7. DEBT
Long-term debt consisted of the following as of August 31, 2003:
<Table>
<Caption>
AUGUST 31,
2003
--------------
(IN THOUSANDS)
Term notes.................................................. $226,000
Revolving credit facility................................... --
--------
Total debt.................................................. 226,000
Less current portion........................................ 30,000
--------
Total long-term debt........................................ $196,000
========
</Table>
The scheduled maturities of long-term debt are as follows:
<Table>
<Caption>
AUGUST 31,
2003
--------------
(IN THOUSANDS)
2004........................................................ $ 30,000
2005........................................................ 196,000
2006 and thereafter......................................... --
--------
Total....................................................... $226,000
========
</Table>
TERM NOTE FACILITY
La Grange Acquisition entered into a term note agreement (the Term Note)
with a financial institution in the amount of $246 million. The Term Note is
secured by substantially all of the Partnership's assets and bears interest at a
LIBOR based rate, which was 4.69% at August 31, 2003. Principal payment of $7.5
million are due quarterly until final maturity in September 2005, when the
remaining outstanding principal balance is due. Upon issuance of the Term Note,
the Partnership deferred approximately $5.7 million of initial fees and expenses
and is amortizing such deferred costs over the life of the note.
In January 2003, February 2003, and June 2003, the Partnership paid $5
million, $7.5 million, and $7.5 million, respectively, on the outstanding Term
Note balance.
The Term Note requires the Partnership to comply with certain financial
covenants as well as limits the activities of the Partnership in other ways. At
August 31, 2003, the Partnership was in compliance with such covenants.
REVOLVING CREDIT FACILITY
The Partnership has a $40 million revolving credit facility with a
financial institution that expires September 30, 2005. The revolving credit
facility includes a variable rate line of credit facility and a letter of credit
facility. Amounts borrowed under the credit facility bear interest at a rate
based on either a Eurodollar base rate for Eurodollar Loans, or a base rate
currently designated as a LIBOR base rate at the option of the Administrative
Agent for Base Rate Loans. The revolving credit facility requires the payment of
commitment fees of 1/2 of 1 percent and is secured by substantially all of the
Partnership's assets. Letters of credit reduce the amount available under the
credit facility.
At August 31, 2003, there were $565,000 of letters of credit outstanding
and no amounts outstanding under the revolving credit facility.
F-28
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The carrying value of the Partnership's debt obligations approximates their
fair value. This determination is based on management's estimate of the fair
value at which such instruments could be obtained in an unrelated third-party
transaction.
8. INCOME TAXES
As previously disclosed, other than taxes resulting from income of Oasis
Pipe Line, income taxes are the responsibility of the partners. The following
reconciles net income to the taxable income to be reported directly to the
partners for the period ended August 31, 2003:
<Table>
<Caption>
(IN THOUSANDS)
Income before tax........................................... $ 51,057
Reconciling items:
Oasis Pipe Line -- taxed separately....................... (12,638)
Depreciation.............................................. (35,143)
Other..................................................... 790
--------
Taxable income reported to partners......................... $ 4,066
========
</Table>
Components of Oasis Pipe Line's income tax provision/(benefit) attributable
to income before taxes, as of August 31, 2003, are as follows:
<Table>
<Caption>
(IN THOUSANDS)
Current..................................................... $ 5,548
Deferred.................................................... (1,116)
-------
Total income tax expense.................................... $ 4,432
=======
</Table>
Deferred tax liabilities of Oasis Pipe Line, as of August 31, 2003, consist
of the following:
<Table>
<Caption>
(IN THOUSANDS)
Property, plant and equipment............................... $55,736
Other....................................................... (351)
-------
Net deferred tax liabilities................................ $55,385
=======
</Table>
9. MAJOR CUSTOMERS
The Partnership had gross sales as a percentage of total revenues to
nonaffiliated major customers as follows:
<Table>
<Caption>
ELEVEN MONTHS
ENDED
AUGUST 31,
2003 S&P RATING
------------- ----------
Customer A.................................................. 18.85% A-
Customer B.................................................. 11.26% BBB
</Table>
The Partnership's natural gas operations have a concentration of customers
in natural gas transmission, distribution, and marketing, as well as industrial
end-users while its NGL operations have a concentration of customers in the
refining and petrochemical industries. These concentrations of customers may
impact the Partnership's overall exposure to credit risk, either positively or
negatively. However, management believes that the Partnership's portfolio of
accounts receivable is sufficiently diversified to minimize any potential credit
risk. Historically, the Partnership has not incurred losses in collecting its
F-29
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
accounts receivable and, as such, no allowance for doubtful accounts has been
provided in the accompanying combined financial statements.
10. RETIREMENT AND BENEFIT PLANS
Energy Transfer has a defined contribution plan for virtually all
employees. Pursuant to the plan, employees of the Partnership can defer a
portion of their compensation and contribute it to a deferred account. The
Partnership did not elect to match contributions to this plan through August 31,
2003.
11. COMMITMENTS AND CONTINGENCIES
LEASE OBLIGATIONS
The Partnership has operating leases for office space and compressors under
noncancelable agreements. The following are the future annual minimum lease
payments for each of the next five years as of August 31, 2003:
<Table>
<Caption>
IN THOUSANDS
2004........................................................ $920
2005........................................................ $927
2006........................................................ $390
2007........................................................ $ 6
2008........................................................ $ 1
thereafter.................................................. $ --
</Table>
Rental expense for the 11 months ended August 31, 2003 relating to
operating leases was $662,000.
PHYSICAL FORWARD COMMODITY COMMITMENTS
The Partnership has forward commodity contracts, which will be settled by
physical delivery. Short-term contracts, which expire in less than one year,
require delivery up to 54 million British thermal units per pay (MMBtu/d).
Long-term contracts require delivery of up to 156 MMBtu/d. The long-term
contracts run through July 2013.
BOSSIER PIPELINE EXTENSION
XTO has signed a long-term agreement to deliver 200 million cubic feet per
day (MMcfd) natural gas volumes into a new pipeline system, which is currently
under construction. The pipeline will connect East Texas production into the
Katy hub near Houston. The term of the XTO agreements runs nine years, through
July 2012. The Bossier Pipeline Extension is scheduled to be operational by
mid-2004.
Energy Transfer in the normal course of business, purchases, processes and
sells natural gas pursuant to long-term contracts. Such contracts contain terms
that are customary in the industry.
The Partnership believes that such terms are commercially reasonable and
will not have a material adverse effect on the Partnership's financial position
or results of operations.
LITIGATION
On June 16, 2003, Guadalupe Power Partners, L.P. (GPP) sought and obtained
a Temporary Restraining Order against Oasis Pipe Line. In their pleadings, GPP
alleged unspecified monetary damages for the period from February 25, 2003 to
June 16, 2003 and sought to prevent Oasis Pipe Line from implementing flow
control measures to reduce the flow of gas to their power plant at varying
hourly rates.
F-30
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Oasis Pipe Line filed a counterclaim against GPP asking for damages and a
declaration that the contract was terminated as a result of the breach by GPP.
Oasis Pipe Line and GPP agreed to a "stand still" order and referred this
dispute to binding arbitration. Oasis Pipe Line has retained trial counsel to
defend this matter and is proceeding with the preparation of its case in the
arbitration.
The Partnership is involved in various lawsuits, claims, and/or regulatory
proceedings incidental to its business. In the opinion of management, the
outcome of such matters will not have a material adverse effect on the
Partnership's financial position or results of operations.
ENVIRONMENTAL
The Partnership's operations are subject to extensive federal, state and
local environmental laws and regulations that require expenditures for
remediation at operating facilities and waste disposal sites. Although the
Partnership believes its operations are in substantial compliance with
applicable environmental laws and regulations, risks of additional costs and
liabilities are inherent in the natural gas pipeline and processing business,
and there can be no assurance that significant costs and liabilities will not be
incurred. Moreover, it is possible that other developments, such as increasingly
stringent environmental laws, regulations and enforcement policies thereunder,
and claims for damages to property or persons resulting from the operations,
could result in substantial costs and liabilities. Accordingly, the Partnership
has adopted policies, practices, and procedures in the areas of pollution
control, product safety, occupational health, and the handling, storage, use,
and disposal of hazardous materials to prevent material environmental or other
damage, and to limit the financial liability, which could result from such
events. However, some risk of environmental or other damage is inherent in the
natural gas pipeline and processing business, as it is with other entities
engaged in similar businesses.
In conjunction with the acquisition of the Texas and Oklahoma natural gas
gathering and gas processing assets from Aquila Gas Pipeline, Aquila, Inc.
agreed to indemnify Energy Transfer for any environmental liabilities that arose
from operations of the assets purchased prior to October 1, 2002. Aquila also
agreed to indemnify the Partnership for 50% of any environmental liabilities
that arose from operations of the Oasis Pipe Line assets purchased prior to
October 1, 2002.
Environmental exposures and liabilities are difficult to assess and
estimate due to unknown factors such as the magnitude of possible contamination,
the timing and extent of remediation, the determination of the Partnership's
liability in proportion to other parties, improvements in cleanup technologies
and the extent to which environmental laws and regulations may change in the
future. Although environmental costs may have a significant impact on the
results of operations for any single period, the Partnership believes that such
costs will not have a material adverse effect on its financial position. As of
August 31, 2003, the Partnership has $633,000 accrued to cover any material
environmental liabilities that were not covered by the environmental
indemnifications.
12. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES
COMMODITY PRICE RISK
The Partnership is exposed to market risks related to the volatility of
natural gas and NGL prices. To reduce the impact of this price volatility,
Energy Transfer primarily uses derivative commodity instruments (futures and
swaps) to manage its exposures to fluctuations in margins. However, during the
11 months ended August 31, 2003, management has generally elected not to
designate its commodity derivatives as hedges for accounting purposes.
F-31
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The following summarizes Energy Transfer's commodity derivative positions
at August 31, 2003:
<Table>
<Caption>
NOTIONAL
BASIS VOLUME ENERGY TRANSFER ENERGY TRANSFER
SWAPS COMMODITY MMBTU MATURITY PAYS RECEIVES FAIR VALUE
- ----- --------- ---------- -------- --------------- --------------- ----------
HSC Gas 6,865,000 2003 Nymex IFERC $ (250,650)
Gas 14,870,000 2003 IFERC Nymex 1,000,713
HSC Gas 900,000 2004 Nymex IFERC 2,250
Gas 450,000 2004 IFERC Nymex (1,125)
Waha Gas 2,400,000 2003 Nymex IFERC 64,200
Gas 7,230,000 2003 IFERC Nymex (325,525)
Waha Gas -- 2004 Nymex IFERC --
Gas 1,780,000 2004 IFERC Nymex (62,300)
----------
$ 427,563
==========
</Table>
<Table>
<Caption>
NOTIONAL AVERAGE
LONG/ VOLUME STRIKE
FUTURES COMMODITY SHORT MMBTU MATURITY PRICE FAIR VALUE
- ------- --------- ----- --------- -------- ------- ----------
Gas Long 3,085,000 2003 $4.979 $(52,970)
Gas Short 5,910,000 2003 $5.039 533,865
Gas Short 60,000 2004 $5.285 7,480
Gas Long 30,000 2004 $5.257 (2,890)
--------
$485,485
========
</Table>
INTEREST RATE RISK
Energy Transfer is exposed to market risk for changes in interest rates
related to its term note. An interest rate swap agreement is used to manage a
portion of the exposure to changing interest rates by converting floating rate
debt to fixed-rate debt. On October 9, 2002, Energy Transfer entered into an
interest rate swap agreement to manage its exposure to changes in interest
rates. The interest rate swap has a notional value of $75 million and is tied to
the maturity of the term note. Under the terms of the interest rate swap
agreement, Energy Transfer pays a fixed rate of 2.76% and receives three-month
LIBOR with quarterly settlement commencing on January 9, 2003. Management has
elected not to designate the swap as a hedge for accounting purposes. The fair
value of the interest rate swap at August 31, 2003 is a liability of $807,000
and has been recognized as a component of interest.
Unrealized gains recognized in earnings related to Energy Transfer's
commodity derivative activities were $912,000 for the 11 months ended August 31,
2003. The realized losses on commodity derivatives, which were included in
revenue, for the 11 months ended August 31, 2003, were $2,001,000. Realized
losses on the interest rate swap included in interest expense were $312,000.
Management believes that many of its derivatives positions would qualify as
hedges if management had designated them as such for accounting purposes. Had
Energy Transfer designated its derivatives as hedges for accounting purposes, a
substantial portion of the fair value of its derivatives at August 31, 2003
would not have been recognized through earnings.
F-32
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
13. SEGMENT DISCLOSURES
Prior to December 27, 2002, Energy Transfer operated in only one segment,
the Midstream segment, consisting of the natural gas gathering, processing and
transportation operations. Effective January 1, 2003, upon completion of the
Oasis Pipe Line stock redemption, the Partnership operates in two segments, the
Midstream segment and the Transportation segment, consisting of Oasis Pipe Line.
The Midstream segment, which focuses on the gathering, compression,
treating, processing, transportation and marketing of natural gas, primarily at
our Southeast Texas System and our Elk City Systems, generates revenue primarily
by the volumes of natural gas gathered, compressed, treated, processed,
transported, purchased and sold through our pipeline (excluding Oasis Pipe Line)
and gathering systems and the level of natural gas and NGL prices. In 2003, the
Partnership's equity method investments are included in the Midstream segment.
In addition, the Partnership's two largest customers' revenues are included in
the Midstream segment's revenues.
The Transportation Segment, which focuses on the transportation of natural
gas through our Oasis Pipe Line, generates revenue from the fees charged to
customers to transport gas through or reserve capacity on our pipeline.
For the 11 months ended August 31, 2003:
<Table>
<Caption>
INTERSEGMENT
MIDSTREAM TRANSPORTATION ELIMINATIONS TOTAL
--------- -------------- ------------ ----------
(IN THOUSANDS)
Revenue.............................. $988,587 $ 30,617 $(10,481) $1,008,723
Cost of sales........................ $909,901 $ 119 $(10,481) $ 899,539
Depreciation and amortization........ $ 10,647 $ 2,814 $ 13,461
Income from operations............... $ 43,900 $ 17,689 $ 61,589
Interest, expense, net............... $ 11,526 $ 5,096 $ (4,565) $ 12,057
Income tax........................... $ -- $ 4,432 $ 4,432
Net Income........................... $ 38,419 $ 8,206 $ 46,625
Capital expenditures................. $ 13,306 $ 566 $ 13,872
Total assets......................... $414,552 $189,007 $ (2,866) $ 600,693
</Table>
14. SUBSEQUENT EVENT
On November 6, 2003, we publicly announced the signing of definitive
agreements to combine our operations with those of Heritage Propane Partners,
L.P. ("Heritage"), which is engaged in the retail propane business. The
transaction will create a combined entity with substantially greater scale and
scope of operations. We believe our larger size and our entry into the propane
business will provide us with substantial internal and external growth
opportunities. The value of the consideration payable in this transaction is
approximately $987 million based on the average market price of Heritage common
units for the 45 trading days prior to the time we signed these agreements.
F-33
REPORT OF INDEPENDENT AUDITORS
To the Partners of
La Grange Acquisition, LP and Affiliates
We have audited the accompanying consolidated balance sheets of Aquila Gas
Pipeline Corporation and Subsidiaries as of September 30, 2002 and December 31,
2001, and the related consolidated statements of income, stockholder's equity
and cash flows for the period ended September 30, 2002 and the years ended
December 31, 2001 and 2000. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audit.
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 consolidated financial position of Aquila Gas
Pipeline Corporation and Subsidiaries as of September 30, 2002 and December 31,
2001, and the results of their operations and their cash flows for the period
ended September 30, 2002 and the years ended December 31, 2001 and 2000 in
conformity with accounting principles generally accepted in the United States.
As discussed in the Note 1 to the consolidated financial statements,
effective January 1, 2002, Aquila Gas Pipeline Corporation and Subsidiaries
adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other
Intangible Assets.
/s/ ERNST & YOUNG LLP
San Antonio, Texas
July 17, 2003
F-34
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- --------------
(IN THOUSANDS)
ASSETS
Current assets:
Cash and cash equivalents................................. $ -- $ --
Accounts receivable....................................... 72,154 121,093
Inventories and exchanges, net............................ -- 1,189
Materials and supplies.................................... 2,622 2,917
Price risk management assets.............................. 18,100 8,581
Other current assets...................................... 66 226
Receivable due from affiliated companies.................. 23,889 10,390
-------- --------
Total current assets........................................ 116,831 144,396
Pipeline, property, plant and equipment, at cost:
Natural gas pipelines..................................... 465,441 468,115
Plants and processing equipment........................... 93,872 93,724
Other..................................................... 12,425 12,097
-------- --------
571,738 573,936
Less accumulated depreciation............................. (210,399) (193,750)
-------- --------
361,339 380,186
Intangible assets, net...................................... 5,218 8,384
Investment in Oasis Pipe Line............................... 100,748 99,322
Other, net.................................................. 475 972
Price risk management assets................................ 16,917 --
-------- --------
Total assets................................................ $601,528 $633,260
======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Accounts payable.......................................... $ 71,981 $131,118
Accrued expenses.......................................... 3,938 8,469
Current maturities of long-term debt...................... -- 12,500
Accrued interest.......................................... 975 269
Exchanges payable......................................... 784 --
Price risk management liabilities......................... 19,334 955
Payable to affiliated companies........................... 47,064 41,505
-------- --------
Total current liabilities................................... 144,076 194,816
Long-term debt.............................................. 66,250 66,250
Deferred income taxes....................................... 121,718 122,674
Price risk management liabilities........................... 15,225 --
Commitments and contingencies...............................
Stockholder's equity:
Common stock, $1.00 par value, 1,000 shares authorized and
10 shares issued....................................... -- --
Additional paid-in capital................................ 90,591 90,591
Retained earnings......................................... 163,668 158,929
-------- --------
Total stockholder's equity.................................. 254,259 249,520
-------- --------
Total liabilities and stockholder's equity.................. $601,528 $633,260
======== ========
</Table>
See accompanying notes.
F-35
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<Table>
<Caption>
NINE MONTHS
ENDED YEAR ENDED DECEMBER 31,
SEPTEMBER 30, ------------------------
2002 2001 2000
------------- ---------- ----------
(IN THOUSANDS)
Operating revenues....................................... $933,099 $1,813,850 $1,758,530
Costs and expenses:
Cost of sales.......................................... 880,064 1,715,261 1,640,867
Operating.............................................. 12,717 18,126 19,983
General and administrative............................. 9,575 19,949 21,290
Depreciation and amortization.......................... 22,915 30,779 30,049
Asset impairment....................................... -- -- 7,800
Unrealized loss (gain) on derivatives.................. 4,966 (13,255) 7,517
-------- ---------- ----------
Total costs and expenses............................ 930,237 1,770,860 1,727,506
Income from operations................................... 2,862 42,990 31,024
Other income (expense)................................... (84) 1,901 (20)
Equity in net income of Oasis Pipe Line.................. 5,425 3,128 (14)
Interest and debt expenses, net.......................... (3,931) (6,858) (12,098)
-------- ---------- ----------
Income before income taxes............................... 4,272 41,161 18,892
Income tax (benefit) expense............................. (467) 15,403 7,657
-------- ---------- ----------
Net income............................................... $ 4,739 $ 25,758 $ 11,235
======== ========== ==========
</Table>
See accompanying notes.
F-36
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
NINE MONTHS ENDED SEPTEMBER 30, 2002, AND
YEARS ENDED DECEMBER 31, 2001 AND 2000
<Table>
<Caption>
ADDITIONAL TOTAL
COMMON STOCK PAID-IN RETAINED STOCKHOLDER'S
SHARES AMOUNT CAPITAL EARNINGS EQUITY
------------ ------ ---------- -------- -------------
(IN THOUSANDS)
Balance, December 31, 1999.............. -- $ -- $90,591 $121,936 $212,527
Net income............................ -- -- -- 11,235 11,235
---- ----- ------- -------- --------
Balance, December 31, 2000.............. -- -- 90,591 133,171 223,762
Net income............................ -- -- -- 25,758 25,758
---- ----- ------- -------- --------
Balance, December 31, 2001.............. -- -- 90,591 158,929 249,520
Net income............................ -- -- -- 4,739 4,739
---- ----- ------- -------- --------
Balance, September 30, 2002............. -- $ -- $90,591 $163,668 $254,259
==== ===== ======= ======== ========
</Table>
See accompanying notes.
F-37
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<Table>
<Caption>
NINE MONTHS
ENDED YEAR ENDED DECEMBER 31,
SEPTEMBER 30, -----------------------
2002 2001 2000
------------- --------- ----------
(IN THOUSANDS)
OPERATING ACTIVITIES
Net income................................................. $ 4,739 $ 25,758 $ 11,235
Adjustments to reconcile net (loss) income to net cash
provided by operating activities:
Depreciation and amortization, including interest..... 22,935 30,827 30,135
Equity in (income) loss of Oasis Pipe Line............ (5,425) (3,128) 14
Dividend from Oasis................................... 4,000 1,500 --
Deferred income taxes................................. (956) 9,843 (3,686)
Gain or loss on sale of assets........................ 61 (3,838) 134
Asset impairment...................................... -- -- 7,800
Changes in operating assets and liabilities:
Accounts receivable................................. 48,939 102,688 (122,921)
Inventories and exchanges, net...................... 1,973 925 1,636
Net change in price risk management assets and
liabilities...................................... 7,168 (7,056) (570)
Receivable due from affiliated companies............ (13,499) (10,390) --
Other assets........................................ 455 (171) 988
Accounts payable.................................... (59,137) (98,802) 127,671
Accrued expenses.................................... (4,531) (1,739) 3,453
Accrued interest.................................... 706 (812) (1,057)
Payable to affiliated companies..................... 5,559 19,593 21,179
-------- -------- ---------
Net cash provided by operating activities.................. 12,987 65,198 76,011
INVESTING ACTIVITIES
Additions to pipeline, property, plant and equipment....... (5,486) (26,866) (23,944)
Proceeds from asset dispositions........................... 4,999 6,139 485
-------- -------- ---------
Net cash used in investing activities...................... (487) (20,727) (23,459)
FINANCING ACTIVITIES
(Payments) borrowings under revolving credit agreement,
net...................................................... -- (31,971) (40,052)
Principal payments of debt................................. (12,500) (12,500) (12,500)
-------- -------- ---------
Net cash used in investing activities...................... (12,500) (44,471) (52,552)
-------- -------- ---------
Net (decrease) increase in cash and cash equivalents....... -- -- --
Cash and cash equivalents, beginning of year............... -- -- --
-------- -------- ---------
Cash and cash equivalents, end of year..................... $ -- $ -- $ --
======== ======== =========
</Table>
See accompanying notes.
F-38
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2002,
YEARS ENDED DECEMBER 31, 2001 AND 2000
(IN THOUSANDS)
1. SUMMARY OF BUSINESS, BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING
POLICIES
BUSINESS
Aquila Gas Pipeline Corporation (Aquila Gas Pipeline or the Company) and
subsidiaries owned and operated natural gas gathering and pipeline systems and
gas processing plants and was engaged in the business of purchasing, gathering,
transporting, processing and marketing natural gas and natural gas liquids
(NGLs) in the States of Texas and Oklahoma.
Effective October 1, 2002, substantially all of the operating assets of
Aquila Gas Pipeline were sold for $264 million to La Grange Acquisition, LP (La
Grange Acquisition). La Grange Acquisition did not assume Pipeline's derivative
positions or its liabilities, except for certain payables.
PRINCIPLES OF CONSOLIDATION AND BASIS OF PRESENTATION
Aquila Gas Pipeline was a wholly owned subsidiary of Aquila Merchant
Services. Aquila Merchant Services was wholly owned by Aquila, Inc. (Aquila),
formerly UtiliCorp United Inc.
The accompanying consolidated financial statements include the accounts of
Aquila Gas Pipeline after the elimination of significant intercompany balances
and transactions with subsidiaries. Unless otherwise indicated, all amounts
included in the notes to the consolidated financial statements are expressed in
thousands.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. The more significant areas requiring the use of estimates
relate to the fair value of financial instruments and useful lives for
depreciation. Actual results may differ from those estimates.
The Company was subject to a number of risks inherent in the industry in
which it operated, primarily fluctuating prices and gas supply. The Company's
financial condition and results of operations depended significantly upon the
prices received for natural gas and NGLs. These prices were subject to wide
fluctuations due to a variety of factors that were beyond the control of the
Company. In addition, the Company had to continually connect new wells to its
gathering systems in order to maintain or increase throughput levels to offset
natural declines in dedicated volumes. The number of new wells drilled depended
on a variety of factors that were beyond the control of the Company.
CASH PAID FOR INTEREST
The following provides information related to cash paid for interest. No
cash was paid for income taxes as taxes were settled through intercompany
accounts with Aquila:
<Table>
<Caption>
DECEMBER 31,
SEPTEMBER 30, -----------------
2002 2001 2000
------------- ------ -------
(IN THOUSANDS)
Interest, net of amount capitalized.................... $3,308 $6,219 $10,511
</Table>
F-39
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
REVENUE RECOGNITION
Operating revenues were recognized upon the delivery of natural gas or NGLs
to the buyer of the related product or services.
INVENTORIES AND EXCHANGES
Inventories and exchanges consisted of NGLs on hand or natural gas and NGLs
delivery imbalances with others and were presented net by customer/supplier on
the consolidated balance sheet. These amounts turned over monthly, and
management believed that cost approximated market value. Accordingly, these
volumes were valued at market prices on the consolidated balance sheet.
MATERIALS AND SUPPLIES
Materials and supplies were stated at the lower of cost (determined on a
first-in, first-out basis) or market.
SHIPPING AND HANDLING COSTS
In accordance with the Emerging Issues Task Force Issue 00-10, "Accounting
for Shipping and Handling Fees and Costs", the Company classified all deductions
from producer payments for fuel, compression and treating that can be considered
handling costs as revenue. The associated fuel costs were included in cost of
sales, while the remaining costs were included in operating costs.
COMMODITY RISK MANAGEMENT
In 1999, Aquila Gas Pipeline transferred all of its energy trading
operations and management thereof to Aquila Energy Marketing (AEM), a wholly
owned subsidiary of Aquila. AEM entered into forward physical contracts with
third parties for the benefit of Aquila Gas Pipeline and where deemed necessary
entered into intercompany financial derivative positions (e.g., swaps, futures
and options) with Aquila Gas Pipeline and other affiliates to assist them in
managing their exposures. Thus, Aquila Gas Pipeline had forward physical
contracts with third parties and financial derivative positions with AEM and
affiliates. The Company received all gross margins associated with these
transactions, and AEM charged Aquila Gas Pipeline for its share of AEM's costs
to manage Aquila Gas Pipeline's positions.
The Company accounted for its derivative positions, both speculative
forward positions and financial derivatives, under Emerging Issues Task Force
Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" (EITF 98-10). Under EITF 98-10, the Company valued the
derivative positions at market value with all changes being recognized in
earnings. Realized gains and losses were included in revenues, while unrealized
gains and losses were classified as such on the consolidated statements of
income. Aquila Gas Pipeline's derivative positions were classified as current or
long-term price risk management assets and liabilities based on their maturity.
The market prices used to value these transactions reflected management's
estimates considering various factors, including closing exchange and
over-the-counter quotations, time value and volatility factors of the underlying
commitments. The values were adjusted to reflect the potential impact of
liquidating a position in an orderly manner over a reasonable period of time
under market conditions.
Although La Grange Acquisition is also involved in energy marketing and
uses derivatives to manage its exposures, La Grange Acquisition did not purchase
Aquila Gas Pipeline's derivative positions when it purchased its assets.
Emerging Issues Task Force Issue 02-03, "Issues Involved in Accounting for
Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities" was issued in the fourth quarter of 2002
and rescinded the provisions of
F-40
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
EITF 98-10. As such all energy trading derivative transactions are now governed
by Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (Statement No. 133). Under
Statement No. 133, La Grange Acquisition will continue to account for its
financial derivative positions as mark to market instruments. However, as
permitted under Statement No. 133, La Grange Acquisition has adopted a policy of
treating all forward physical contracts that require physical delivery as normal
purchases and sales contracts. As such, these contracts will not be marked to
market and will be accounted for when delivery occurs. Had Aquila Gas Pipeline
adopted this policy, it would have reversed unrealized mark to market gains of
$1,938 at September 30, 2002.
PIPELINE, PROPERTY, PLANT AND EQUIPMENT
Pipeline, property, plant and equipment were stated at cost. Additions and
improvements that added to the productive capacity or extended the useful life
of the asset were capitalized. Expenditures for maintenance and repairs that did
not add capacity or extended the useful life were charged to expense as
incurred. Upon disposition or retirement of pipeline components or gas plant
components, any gain or loss was recorded to accumulated depreciation. When
entire pipeline systems, gas plants or other property and equipment were retired
or sold, any gain or loss was included in operations.
Depreciation of the pipeline systems, gas plants and processing equipment
was calculated using the straight-line method based on an estimated useful life
of primarily 25 years. Interest cost on funds used to finance major pipeline
projects during their construction period was also capitalized. Capitalized
interest cost was $35, $86 and $70 for the periods ending September 30, 2002 and
December 31, 2001 and 2000, respectively.
The Company reviewed its long-lived assets, including finite lived
intangibles, for impairment whenever facts and circumstances indicated
impairment was potentially present. When impairment indicators were present,
Aquila Gas Pipeline evaluated whether the assets in question were able to
generate sufficient cash flows to recover their carrying value on an
undiscounted basis. If not, the Company impaired the assets to their fair value,
which was determined based on discounted cash flows or estimated salvage value.
In 2000, as a result of volume declines at some of Aquila Gas Pipeline's smaller
gathering and treating facilities, an impairment charge of $7.8 million was
recognized to reduce the carrying value of these systems to the present value of
the future cash flows or salvage value, if greater. The present value of future
cash flows was computed assuming a 12% discount rate.
Construction work in progress at September 30, 2002 and December 31, 2001
was $669 and $4,484, respectively.
STOCK COMPENSATION
Some of Aquila Gas Pipeline's employees received stock options in Aquila.
As permitted under generally accepted accounting principles, Aquila elected to
account for the options under Accounting Principles Board Opinion No. 25, and
because the options strike price was equal to or greater than the fair value at
the date of grant, no compensation expense was recognized. See Note 6, for a
summary of the options granted. As these were Aquila options, Aquila Gas
Pipeline does not have full access to the information necessary to disclose what
compensation expense would have been, had Aquila accounted for the options under
Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation", which requires compensation expense be recognized for the fair
value of the options at the date of grant. La Grange Acquisition does not have a
stock option plan in place for its employees.
F-41
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
INCOME TAXES
Aquila Gas Pipeline was included in the consolidated federal income tax
returns filed by Aquila. Accordingly, all tax balances were ultimately settled
through Aquila. Aquila Gas Pipeline had generally accounted for its taxes on a
stand-alone or separate return basis (see Note 4). Periodically, taxes payable
were settled through the intercompany accounts with Aquila and were not funded
in cash.
The Company provides for income taxes in accordance with Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes" (Statement
No. 109). Statement No. 109 requires that deferred tax assets and liabilities be
established for the basis differences between the reported amounts of assets and
liabilities for financial reporting purposes and income tax purposes.
EQUITY METHOD INVESTMENTS
Aquila Gas Pipeline had a 50% investment in Oasis Pipe Line Company. Aquila
Gas Pipeline accounted for this investment using the equity method.
ADOPTION OF NEW ACCOUNTING STANDARD
On January 1, 2002, Aquila Gas Pipeline adopted Statement of Financial
Accounting Standards No. 141, "Business Combinations" (Statement No. 141).
Statement No. 141 addresses financial accounting and reporting for business
combinations and supersedes APB Opinion No. 16, "Business Combinations", and
FASB Statement 38, "Accounting for Preacquisition Contingencies of Purchased
Enterprises." Statement No. 141 was effective for all business combinations
initiated after June 30, 2001. Statement No. 141 eliminated the
pooling-of-interest method of accounting for business combinations. Statement
No. 141 also changed the criteria to recognize intangible assets apart from
goodwill. As the Company has historically used the purchase method to account
for all business combinations, adoption of this statement did not have a
material impact on the Aquila Gas Pipeline's financial position or results of
operations.
In June 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets"
(Statement No. 142). Statement No. 142 addresses financial accounting and
reporting for acquired goodwill and other intangible assets and superseded APB
Opinion No. 17, "Intangible Assets." Statement No. 142 was effective for fiscal
years beginning after December 15, 2001. This statement established new
accounting for goodwill and other intangible assets recorded in business
combinations. Under the new rules, goodwill and intangible assets deemed to have
indefinite lives are no longer amortized but are be subjected to annual
impairment tests in accordance with the statement. Other intangible assets
continue to be amortized over their useful lives. Aquila Gas Pipeline adopted
this standard on January 1, 2002. As amortization of goodwill was a significant
non-cash expense, Statement No. 142 had a material impact on the Company's
financial statements. The table below summarizes the financial results as if
adoption had occurred on January 1, 2000.
<Table>
<Caption>
2001 2000
------- -------
(IN THOUSANDS)
Reported net income......................................... $25,758 $11,235
Add back: Goodwill amortization............................. 900 1,147
Add back: Oasis excess basis amortization................... 1,650 1,650
Taxes....................................................... (365) (465)
------- -------
Adjusted net income......................................... $27,943 $13,567
======= =======
</Table>
F-42
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2. RELATED-PARTY TRANSACTIONS
Aquila Gas Pipeline entered into various types of transactions with Aquila
and its affiliates. Aquila Gas Pipeline sold natural gas to Aquila and its
affiliates and purchased natural gas and NGLs from Aquila. Additionally,
Pipeline reimbursed Aquila for the direct and indirect costs of certain Aquila
employees who provided services to the Company and for other costs (primarily
general and administrative expenses) related to the Company's operations. Aquila
also provided Aquila Gas Pipeline with a revolving credit agreement, as
described in Note 3.
In addition, Aquila Gas Pipeline transported gas on Oasis Pipe Line
Company's (Oasis Pipe Line) pipeline. In 1999, Aquila Gas Pipeline had a 35
percent investment in the capital stock of Oasis Pipe Line, which was acquired
in 1996 and was accounted for using the equity method of accounting. In December
2000, Pipeline's investment in Oasis Pipe Line increased to 50 percent as a
result of Oasis Pipe Line's redemption of all the shares of one of its
shareholders.
The following table summarizes transactions for the indicated periods:
<Table>
<Caption>
DECEMBER 31,
SEPTEMBER 30, --------------------
2002 2001 2000
------------- -------- --------
(IN THOUSANDS)
Natural gas sales to affiliated companies................... $166,372 $325,295 $249,541
NGLs sales to affiliated companies.......................... 373 1,267 --
Purchases of natural gas from affiliated companies.......... 101,398 170,105 140,196
Purchases of NGLs from affiliated companies................. 1,841 -- --
Transportation expense with Oasis........................... 3,900 6,727 6,835
Recognized (loss) gain from marketing transactions with
AEM....................................................... 2,678 (10,605) 28,510
Interest expense with Aquila................................ 3,295 5,140 8,745
Reimbursement of direct costs to Aquila..................... (1,739) 15,283 7,324
Service agreement expenses charged by Aquila................ 2,628 3,504 3,504
</Table>
The affiliated receivable due from Aquila was $23,889 and $10,390 for the
periods ending September 30, 2002 and December 31, 2001, respectively. This
receivable was created by overpayments on Aquila Gas Pipeline's revolving credit
agreement (see Note 3) with Aquila. The affiliated payable due to Aquila was
$47,064 and $41,505 as of September 30, 2002 and December 31, 2001,
respectively.
3. DEBT
The following table summarizes Aquila Gas Pipeline's long-term debt:
<Table>
<Caption>
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- ------------
(IN THOUSANDS)
Loan agreement bearing interest at 6.83%, due 2006.......... $16,250 $ 16,250
Loan agreement bearing interest at 6.47%, due 2005.......... 50,000 50,000
8.29% senior notes, due 2002................................ -- 12,500
------- --------
Total debt.................................................. 66,250 78,750
Less -- Current maturities of long-term debt................ -- (12,500)
------- --------
Total long-term debt........................................ $66,250 $ 66,250
======= ========
</Table>
REVOLVING CREDIT AGREEMENT
Aquila Gas Pipeline had a credit agreement, as amended, with Aquila that
provided a revolving credit facility (Revolver) for borrowings of up to
$115,000. As of September 30, 2002, there was $115,000
F-43
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
available for use under the Revolver. Aquila swept all available cash daily to
reduce the revolver. This resulted in a receivable due to Aquila Gas Pipeline of
$23,889 as of September 30, 2002, $10,390 as of December 31, 2001, and $38,641
as of June 30, 2002. The Revolver bore interest at Aquila Gas Pipeline's
election of either (i) a base rate (the higher of the bank prime rate or 1/2 of
1 percent above the Federal Funds rate), (ii) an adjusted certificate of deposit
rate or (iii) a Eurodollar rate. The maturity date of the Revolver automatically
renewed in one-year periods from each commitment period (October of any given
year), unless Aquila gave at least a one-year notice not to renew. As of
September 30, 2002, the maturity date was October 2003. The Revolver was
unsecured and was subordinate to the 8.29% senior notes described below. The
Company paid an annual commitment fee to Aquila of 1/4 of 1% on the unutilized
portion of the revolving credit facility. The Revolver required the Company to
comply with certain restrictive covenants. At September 30, 2002, Aquila Gas
Pipeline was in compliance with such covenants.
LOAN AGREEMENTS
In 1995, Aquila Gas Pipeline entered into a loan agreement with Aquila
Energy, a subsidiary of Aquila for $50,000. The loan was unsecured and bore
interest at 6.47% due semi-annually. The principal amount of the loan was to be
repaid to Aquila Energy by June 1, 2005. In 1997, Aquila Gas Pipeline entered
into a second loan agreement with Aquila Energy for $16,250. This loan was
unsecured and bore interest at 6.83% due semi-annually. The principal amount of
the second loan was to be repaid to Aquila Energy by October 15, 2006.
SENIOR NOTES
The 8.29% Senior Notes (Senior Notes) were unsecured and interest payments
were due semi-annually. Principal payments of $12,500 were required each year
and the balance was paid in full in September 2002. Upon issuance of the Senior
Notes, Aquila Gas Pipeline deferred approximately $1,886 of initial fees and
expenses that were amortized over the life of the notes.
4. INCOME TAXES
Components of income tax provision/(benefit) attributable to income before
taxes are as follows:
<Table>
<Caption>
DECEMBER 31,
SEPTEMBER 30, ------------------
2002 2001 2000
------------- ------- -------
(IN THOUSANDS)
Current............................................... $ 489 $ 5,560 $11,343
Deferred.............................................. (956) 9,843 (3,686)
----- ------- -------
Total................................................. $(467) $15,403 $ 7,657
===== ======= =======
</Table>
F-44
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Tax expense was different than the amount computed by applying the
statutory federal income tax rate to income before taxes. A reconciliation of
Aquila Gas Pipeline's income taxes with the United States Federal statutory rate
is as follows:
<Table>
<Caption>
DECEMBER 31,
SEPTEMBER 30, ----------------
2002 2001 2000
------------- ----- ----
(IN THOUSANDS)
Book income at U.S. federal statutory rate.............. 35.0% 35.0% 35.0%
Equity method earnings.................................. (51.4) (3.3) --
State taxes............................................. 3.5 3.5 3.5
Other................................................... 2.0 2.0 2.0
----- ----- ----
Tax provision effective rate............................ (10.9)% (37.2)% 40.5%
===== ===== ====
</Table>
Deferred taxes resulted from the effect of transactions that were
recognized in different periods for financial and tax reporting purposes.
Significant components of the Company's deferred tax assets and liabilities were
as follows:
<Table>
<Caption>
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- ------------
(IN THOUSANDS)
Deferred tax assets:
Basis difference in intangible assets..................... $ 6,649 $ 6,796
Other..................................................... 388 2,074
--------- ---------
Total deferred tax assets................................... 7,037 8,870
Deferred tax liabilities:
Basis difference in fixed assets.......................... (128,755) (131,544)
--------- ---------
Net deferred tax liabilities................................ $(121,718) $(122,674)
========= =========
</Table>
5. MAJOR CUSTOMERS
The Company's gross sales as a percentage of total revenues to
nonaffiliated major customers were as follows:
<Table>
<Caption>
DECEMBER 31,
SEPTEMBER 30, --------------
2002 2001 2000
------------- ----- -----
Customer A............................................... 17.5% 15.4% 11.9%
Customer B............................................... 9.6% 11.0% 8.4%
</Table>
The Company's natural gas operations had a concentration of customers in
natural gas transmission, distribution and marketing as well as industrial
end-users, while its NGLs operations had a concentration of customers in the
refining and petrochemical industries.
These concentrations of customers impacted the Company's overall exposure
to credit risk, whether positively or negatively, in that the customers were
similarly affected by changes in economic or other conditions. However,
management believed that Aquila Gas Pipeline's portfolio of accounts receivable
was sufficiently diversified to minimize any potential credit risk.
Historically, Aquila Gas Pipeline has not incurred significant problems in
collecting its accounts receivable and, as such, no allowance for doubtful
accounts was provided in the accompanying consolidated financial statements. The
Company's accounts receivable were generally not collateralized.
F-45
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. RETIREMENT AND BENEFIT PLANS
Aquila had a defined contribution plan for virtually all employees.
Pursuant to the plan, employees of the Company could defer a portion of their
compensation and contribute it to a deferred account. The Company's matching
contributions to the plan were $408, $444 and $435 for the periods ended
September 30, 2002 and December 31, 2001 and 2000, respectively.
Aquila had a stock contribution plan under which eligible Aquila Gas
Pipeline employees received a company contribution of 3 percent of their base
income in Aquila common stock. The Company's expense associated with this plan
was $27, $231 and $229 for periods ending September 30, 2002 and December 31,
2001 and 2000, respectively. The reduction for 2002 was due to the reduction in
the number of employees eligible in 2002 and declines in the market value of the
stock.
Aquila had a stock option plan under which eligible Aquila Gas Pipeline
employees were granted options to purchase shares of Aquila's common stock. The
plan provided that the options would not be granted at a price below the market
price at the date of grant. Accordingly, no compensation cost was recognized for
the options. The options vested one year from the date of grant and expired 10
years from the date of grant.
The following table summarizes the options granted to Aquila Gas Pipeline
employees:
<Table>
<Caption>
PERIOD ENDED
-----------------------------------------------------------------
SEPTEMBER 30, DECEMBER 31, DECEMBER 31,
2002 2001 2000
------------------- ------------------- -------------------
AVERAGE AVERAGE AVERAGE
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
------- -------- ------- -------- ------- --------
(IN THOUSANDS)
Outstanding, beginning of period... 170,298 $26.8387 115,876 $21.9475 108,451 $22.5366
Granted.......................... -- -- 85,810 34.8028 27,500 19.1250
Exercised........................ (825) 18.2083 (25,688) 23.4483 (1,575) 28.5700
Forfeited........................ (4,637) 22.7246 (5,700) 21.6565 (18,500) 21.2407
------- ------- -------
Outstanding, end of period....... 164,836 $26.6896 170,298 $26.8387 115,876 $21.8425
======= ======= =======
</Table>
7. COMMITMENTS AND CONTINGENCIES
LEASE OBLIGATIONS
The Company had various non-cancelable operating leases. Total lease
expense amounted to approximately $598 for the period ending September 30, 2002,
$1,059 for the period ending December 31, 2001 and $622 for the period ending
December 31, 2000. All leases were transferred to La Grange Acquisition
effective October 1, 2002.
The following summarizes the future annual lease payments for the
transferred leases for each of the next five years as of September 30, 2002:
<Table>
<Caption>
(IN THOUSANDS)
2003........................................................ $775
2004........................................................ 775
2005........................................................ 773
2006........................................................ 64
2007 and thereafter......................................... --
</Table>
F-46
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
TAXES
The IRS has examined and proposed adjustments to Aquila's consolidated
federal income tax returns for 1988 through 1993. The proposed adjustment
affecting the Company was to lengthen the depreciable life of certain pipeline
assets owned by Aquila Gas Pipeline. Aquila has filed a petition in U.S. Tax
Court contesting the IRS proposed adjustments for the years 1990 through 1991.
The IRS has also proposed an adjustment on the same issue for 1992 through 1998.
Aquila has tentatively agreed with the IRS to hold this issue in abeyance
pending the outcome of the earlier petition.
Aquila intends to vigorously contest the proposed adjustment and believes
it is reasonably possible that they will prevail. If resolved unfavorably, it is
expected that additional assessments for the years 1999 through September 30,
2002 would be made on the same issue.
Any additional taxes would result in an adjustment to the deferred tax
liability with no effect on net income, while any payment of interest or
penalties would affect net income. Aquila Gas Pipeline expects that the ultimate
resolution of this matter will not have a material adverse effect on its
financial position. Under the Asset Purchase Agreement between Aquila and La
Grange Acquisition, La Grange Acquisition would not be impacted by resolution of
this matter.
CONTINGENCIES
In 1996, Aquila Gas Pipeline and Exxon entered into a contract, which
required Aquila Gas Pipeline to pay Exxon $5.1 million in 2006 if Aquila Gas
Pipeline failed to deliver natural gas containing at least 2 gallons per mcf to
the Exxon Katy Plant. In 2000, the determination was made that it was unlikely
that the Company would be in a position to supply natural gas that would meet
the contract specifications. Included in operating expenses in 2000 was an
accrual of $3.6 million representing the present value of the future settlement.
In 2001, the Company reached an agreement with Exxon to cancel the contract for
a cash settlement of $3.7 million and the exchange of property for right-of-way.
The Company was also a party to additional claims and was involved in
various other litigation and administrative proceedings arising in the normal
course of business. Aquila Gas Pipeline believed it was unlikely that the final
outcome of any of the claims, litigation or proceedings to which it was a party
would have a material adverse effect on its financial position or results of
operations. However, due to the inherent uncertainty of litigation, there can be
no assurance that the resolution of any particular claim or proceeding would not
have an adverse effect on the Company's results of operations for the fiscal
period in which such resolution occurred. Per the Asset Purchase Agreement
between Aquila and La Grange Acquisition, Aquila has agreed to indemnify La
Grange Acquisition for any litigation arising from operations before October 1,
2002.
In the normal course of business of its natural gas pipeline operations,
the Company purchased, processed and sold natural gas pursuant to long-term
contracts. Such contracts contained terms, which were customary in the industry.
The Company believes that such terms were commercially reasonable and will not
have a material adverse effect on its financial position or results of
operations.
F-47
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. COMMODITY RISK MANAGEMENT
The following table details information on the Company's positions held or
issued for trading purposes as of:
SEPTEMBER 30, 2002
<Table>
<Caption>
NOTIONAL
VOLUME AQUILA AQUILA FAIR
COMMODITY BCF MATURITY PAYS RECEIVES VALUE
--------- -------- -------- ------ -------- -------
BASIS SWAPS
EPNG Permian.......................... Gas 0.4 2002 Nymex IFERC $ (142)
EPNG Permian.......................... Gas 0.4 2002 IFERC Nymex 143
Waha.................................. Gas 3.3 2005 Nymex IFERC (711)
Waha.................................. Gas 4.1 2005 IFERC Nymex 826
Houston Ship.......................... Gas 0.6 2005 Nymex IFERC (40)
Houston Ship.......................... Gas 0.6 2005 IFERC Nymex 44
EPNG Permian.......................... Gas 1.5 2003 Nymex IFERC (723)
EPNG Permian.......................... Gas 1.5 2003 IFERC Nymex 731
EPNG San Juan......................... Gas -- 2002 Nymex IFERC (456)
EPNG San Juan......................... Gas -- 2002 IFERC Nymex 714
Houston Ship.......................... Gas 101.3 2005 Nymex IFERC (1,038)
Houston Ship.......................... Gas 96.7 2005 IFERC Nymex 1,076
Katy.................................. Gas -- 2002 Nymex IFERC (89)
Katy.................................. Gas -- 2002 IFERC Nymex 94
TGP TX................................ Gas -- 2002 Nymex IFERC (36)
TGP TX................................ Gas -- 2002 IFERC Nymex 16
SOCAL................................. Gas 1.5 2003 Nymex IFERC (428)
SOCAL................................. Gas 1.5 2003 IFERC Nymex 174
TETCO STX............................. Gas 13.6 2005 Nymex IFERC 274
TETCO STX............................. Gas 11.7 2005 IFERC Nymex (130)
Waha.................................. Gas 97.1 2003 Nymex IFERC (8,617)
Waha.................................. Gas 97.1 2003 IFERC Nymex 8,531
</Table>
<Table>
<Caption>
NOTIONAL AVERAGE
BUYER/ VOLUME STRIKE FAIR
SELLER COMMODITY BCF MATURITY PRICE VALUE
-------- --------- -------- -------- ------- --------
FUTURES
Buyer Gas 0.3 2002 3.203 $ (121)
Seller Gas 1.1 2002 2.685 (1,086)
Buyer Gas 115.9 2005 3.733 29,518
Seller Gas 114.3 2005 3.730 (29,729)
Buyer Gas 2.5 2002 3.150 679
Seller Gas 3.4 2002 2.995 (810)
FORWARDS
Buyer Gas 181.0 2020 2.919 (3,683)
Seller Gas 339.7 2020 3.686 6,570
Buyer Transport 15.3 2004 0.029 (12)
</Table>
F-48
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
AVERAGE
BUYER/ BARRELS IN STRIKE FAIR
SELLER COMMODITY THOUSANDS MATURITY PRICE VALUE
-------- --------- ---------- -------- ------- -------
NGLS FUTURES
Seller Ethane 150 2002 0.215 $ 194
Buyer Ethane 150 2002 0.265 121
Seller Propane 75 2002 0.373 265
Buyer Propane 135 2002 0.406 (287)
Seller Crude (254) 2002 29.552 (1,374)
</Table>
DECEMBER 31, 2001
<Table>
<Caption>
NOTIONAL
VOLUME AQUILA AQUILA FAIR
COMMODITY BCF MATURITY PAYS RECEIVES VALUE
--------- -------- -------- ------ -------- -------
BASIS SWAPS
EPNG Permian.......................... Gas 12.4 2005 Nymex IFERC $(2,597)
EPNG Permian.......................... Gas 12.4 2005 IFERC Nymex 2,635
Waha.................................. Gas 72.8 2005 Nymex IFERC (1,463)
Waha.................................. Gas 79.5 2005 IFERC Nymex 2,373
Houston Ship.......................... Gas 27.1 2005 Nymex IFERC 779
Houston Ship.......................... Gas 28.1 2005 IFERC Nymex (1,177)
EPNG Permian.......................... Gas 52.8 2002 Nymex IFERC (4,201)
EPNG Permian.......................... Gas 52 2002 IFERC Nymex 4,267
EPNG San Juan......................... Gas 3.1 2002 Nymex IFERC ( 96)
EPNG San Juan......................... Gas 3.1 2002 IFERC Nymex 134
Henry Hub............................. Gas 4 2002 Nymex IFERC (185)
Henry Hub............................. Gas 3.4 2002 IFERC Nymex 133
Houston Ship.......................... Gas 264.1 2005 Nymex IFERC 7,959
Houston Ship.......................... Gas 261.4 2005 IFERC Nymex (7,424)
Houston Ship.......................... Gas 0.90 2002 Nymex IFERC (21)
Houston Ship.......................... Gas 0.90 2002 IFERC Nymex (41)
PEPL.................................. Gas 2.7 2002 Nymex IFERC 48
PEPL.................................. Gas 2.7 2002 IFERC Nymex (46)
PEPL.................................. Gas 2.7 2002 Nymex IFERC 45
SOCAL................................. Gas 2.3 2002 Nymex IFERC (976)
SOCAL................................. Gas 2.3 2002 IFERC Nymex 711
TETCO STX............................. Gas 21.2 2005 Nymex IFERC 270
TETCO STX............................. Gas 10.6 2005 IFERC Nymex (281)
Waha.................................. Gas 312.3 2003 Nymex IFERC (3,278)
Waha.................................. Gas 315.6 2003 IFERC Nymex 3,503
</Table>
F-49
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
NOTIONAL AVERAGE
BUYER/ VOLUME STRIKE
SELLER COMMODITY BCF MATURITY PRICE FAIR VALUE
-------- --------- -------- -------- ------- ----------
FUTURES
Buyer Gas 8.1 2005 2.806 $ (2,318)
Seller Gas 13.6 2005 2.902 5,015
Buyer Gas 246.1 2005 3.807 (37,627)
Seller Gas 269.1 2005 3.761 37,682
Buyer Gas 3.6 2002 2.777 (1,156)
Seller Gas 11 2002 2.780 1,757
FORWARDS
Buyer Gas 97.9 2020 2.826 (2,709)
Seller Gas 424.3 2020 2.688 3,673
Buyer Transport 23.3 2004 0.016 (18)
</Table>
<Table>
<Caption>
AVERAGE
BUYER/ BARRELS IN STRIKE FAIR
SELLER COMMODITY THOUSANDS MATURITY PRICE VALUE
-------- --------- ---------- -------- ------- -------
NGLS
Futures
Buyer Ethane 600 2002 0.215 $(1,417)
Seller Ethane 600 2002 0.265 1,260
Buyer Propane 180 2002 0.310 213
Seller Propane 240 2002 0.408 699
Seller Propane 180 2002 0.310 (225)
Buyer Crude (702) 2002 20.344 904
Forwards
Seller Ethane 300 2002 0.405 822
</Table>
The net gain from derivative activities for the periods ended September 30,
2002, December 31, 2001 and 2000 was $6,273, $9,016 and $1,409, respectively.
9. FINANCIAL INSTRUMENTS
The Company's carrying amounts for cash and cash equivalents, accounts
receivable, other current assets, accounts payable and other current liabilities
approximated fair value. The fair values of its derivative positions are
disclosed in Note 8. The following summarizes the Company's carrying value and
estimated fair value of its long-term debt obligations:
<Table>
<Caption>
SEPTEMBER 30, 2002 DECEMBER 31, 2001
---------------------------- ----------------------------
CARRYING VALUE FAIR VALUE CARRYING VALUE FAIR VALUE
-------------- ---------- -------------- ----------
(IN THOUSANDS)
6.83% Loan............................ $16,250 $19,123 $16,250 $19,639
6.47% Loan............................ 50,000 55,751 50,000 57,335
------- ------- ------- -------
Total................................. $66,250 $74,874 $66,250 $76,974
======= ======= ======= =======
</Table>
F-50
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. INTANGIBLE ASSETS
The following table details the items included in intangible assets:
<Table>
<Caption>
PERIOD ENDED YEAR ENDED
SEPTEMBER 30, DECEMBER 31,
2002 2001
------------- ------------
(IN THOUSANDS)
Goodwill.................................................... $ 9,491 $ 9,491
Less: amortization.......................................... (7,837) (7,837)
-------- --------
1,654 1,654
Oasis transportation rights................................. 18,620 18,620
Less: amortization.......................................... (15,905) (13,475)
-------- --------
2,715 5,145
Gathering producer relationship............................. 14,930 14,930
Less: amortization.......................................... (14,081) (13,355)
-------- --------
849 1,575
Senior note deferred financing costs........................ -- 1,886
Less: amortization.......................................... -- (1,876)
-------- --------
-- 10
-------- --------
Intangibles, net............................................ $ 5,218 $ 8,384
======== ========
</Table>
Effective January 1, 2002, in accordance with Statements of Financial
Accounting Standards No. 141 and No. 142, the Company ceased amortizing its
goodwill. Further, the Company concluded that the carrying value of the goodwill
was not impaired. Goodwill amortization was $900 and $1,147 in 2001 and 2000,
respectively. Amortization expense, excluding goodwill amortization, was $3,644,
$5,031 and $5,072 in September 30, 2002 and December 31, 2001 and 2000,
respectively.
At September 30, 2002, the estimated five-year amortization of the Oasis
Pipe Line transportation rights and gathering producer relationships was as
follows:
<Table>
<Caption>
(IN THOUSANDS)
Remainder of 2002........................................... $ 840
2003........................................................ 1,990
2004........................................................ 91
2005........................................................ 91
2006........................................................ 91
2007........................................................ 91
Thereafter.................................................. 370
------
$3,564
======
</Table>
The Oasis Pipe Line transportation rights was an agreement between Aquila
Gas Pipeline and Oasis Pipe Line whereby Aquila Gas Pipeline could elect to
reserve a portion of Oasis Pipe Line's line capacity in advance. The agreement
has been amended numerous times, and under the most recent amendment it was
cancelable by either party upon ninety days notice and it was scheduled to
expire in July 2003. The gathering producer relationships related to certain
fixed price gathering contracts that were being amortized over ten years.
F-51
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. INVESTMENT IN SUBSIDIARIES
OASIS PIPE LINE
Prior to December 2000, Aquila Gas Pipeline had a 35% interest in Oasis
Pipe Line. Thereafter, Aquila Gas Pipeline held 50% of the stock of Oasis Pipe
Line. The following table presents financial information related to Oasis Pipe
Line for the periods presented:
<Table>
<Caption>
PERIOD ENDED
---------------------------------------------
SEPTEMBER 30, DECEMBER 31, DECEMBER 31,
2002 2001 2000
------------- ------------ ------------
(IN THOUSANDS)
Revenues................................................ $24,733 $26,153 $24,729
Total operating expenses................................ 7,772 11,266 18,152
Income before income tax expense........................ 16,700 14,707 7,191
Net income.............................................. 10,850 9,556 4,673
Pipeline's share of net income.......................... 5,425 4,778 1,636
Pipeline's share of distributions....................... 4,000 1,500 --
Current assets.......................................... 10,680 7,061 9,388
Total assets............................................ 53,929 50,453 54,732
Current liabilities..................................... 3,893 1,911 14,013
Long-term debt.......................................... -- -- --
Shareholder's equity.................................... 41,912 39,062 32,506
</Table>
At September 30, 2002, Aquila Gas Pipeline's investment exceeded its
pro-rata share of Oasis Pipe Line's equity by $79,792. Prior to 2002, the excess
purchase price was being amortized $1,650 per year. In accordance with Aquila
Gas Pipeline's adoption of Statement of Financial Accounting Standards No. 141
and 142, this amortization was ceased effective January 1, 2002.
F-52
REPORT OF INDEPENDENT AUDITORS
Oasis Pipe Line Company
We have audited the accompanying consolidated balance sheet of Oasis Pipe
Line Company and Subsidiaries as of December 27, 2002, and the related
consolidated statement of income, shareholders' equity and cash flow for the
period then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audit.
We conducted our audit 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 audit provides a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Oasis Pipe Line
Company and Subsidiaries at December 27, 2002, and the consolidated results of
its operations and its cash flows for the period then ended in conformity with
accounting principles generally accepted in the United States.
/s/ ERNST & YOUNG LLP
San Antonio, Texas
July 15, 2003
F-53
INDEPENDENT AUDITORS' REPORT
To Oasis Pipe Line Company:
We have audited the accompanying consolidated balance sheet of Oasis Pipe Line
Company and Subsidiaries (the "Company") as of December 31, 2001, and the
related consolidated statements of income, changes in shareholders' equity, and
cash flows for the years ended December 31, 2001 and 2000. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company as of December 31,
2001, and the results of its operations and its cash flows for the years ended
December 31, 2001 and 2000, in conformity with accounting principles generally
accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
April 5, 2002
F-54
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
DECEMBER 27, DECEMBER 31,
2002 2001
------------ ------------
(IN THOUSANDS)
ASSETS
Current assets:
Cash and cash equivalents................................. $ 7,962 $ 2,352
Accounts receivable -- trade (net of allowance for
doubtful accounts of $153 in 2002 and $60 in 2001)..... 2,290 1,997
Accounts receivable -- affiliates......................... 364 552
Inventories............................................... 1,215 1,351
Refundable income taxes................................... -- 540
Prepaid insurance......................................... 325 269
--------- ---------
Total current assets........................................ 12,156 7,061
Property, plant, and equipment:
Pipeline facilities....................................... 169,308 168,745
Construction-in-progress.................................. -- 119
Less accumulated depreciation and amortization............ (127,231) (125,472)
--------- ---------
Property, plant, and equipment, net......................... 42,077 43,392
Other....................................................... 413 --
--------- ---------
Total assets................................................ $ 54,646 $ 50,453
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable -- trade................................. $ 264 $ 230
Accounts payable -- affiliates............................ -- 13
Accrued liabilities....................................... 376 385
Accrued taxes............................................. 820 --
Accrued taxes, other than income taxes.................... -- 783
Accrued compensation...................................... 586 500
--------- ---------
Total current liabilities................................... 2,046 1,911
Deferred income taxes....................................... 9,461 9,480
Commitments and contingencies
Shareholders' equity:
Common stock, $1 par value; 50,000 shares authorized and
6,667 shares outstanding............................... 7 7
Additional paid-in capital................................ 25,432 25,432
Retained earnings......................................... 35,537 31,460
--------- ---------
60,976 56,899
Less treasury stock, 2,000 shares......................... 17,837 17,837
--------- ---------
Total shareholders' equity.................................. 43,139 39,062
--------- ---------
Total liabilities and shareholders' equity.................. $ 54,646 $ 50,453
========= =========
</Table>
See accompanying notes.
F-55
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<Table>
<Caption>
PERIOD ENDED YEAR ENDED YEAR ENDED
DECEMBER 27, DECEMBER 31, DECEMBER 31,
2002 2001 2000
------------ ------------ ------------
(IN THOUSANDS)
Operating revenues:
Gas transportation -- third party..................... $23,490 $15,749 $11,628
Gas transportation -- affiliates...................... 5,975 8,364 7,953
Proceeds from pipeline construction................... -- -- 4,674
Gas sales -- third party.............................. 2,352 883 94
Fuel and unaccounted for gas.......................... -- 763 --
Other................................................. 914 394 380
------- ------- -------
Total operating revenues................................ 32,731 26,153 24,729
Operating expenses:
Fuel and unaccounted for gas.......................... 133 -- 3,344
Operations and maintenance............................ 4,469 4,325 5,045
Cost of pipeline construction......................... -- -- 3,887
Depreciation and amortization......................... 2,106 2,458 2,249
Taxes, other than income.............................. 1,207 1,171 1,300
Administrative and general............................ 2,555 3,312 2,327
------- ------- -------
Total operating expenses................................ 10,470 11,266 18,152
------- ------- -------
Operating income........................................ 22,261 14,887 6,577
Other income (expenses):
Interest income....................................... 64 193 640
Interest expense -- shareholder....................... -- (433) (13)
Other, net............................................ (660) 60 (13)
------- ------- -------
Income before income taxes.............................. 21,665 14,707 7,191
Income tax expense...................................... 7,588 5,151 2,518
------- ------- -------
Net income.............................................. $14,077 $ 9,556 $ 4,673
======= ======= =======
</Table>
See accompanying notes.
F-56
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
PERIOD ENDED DECEMBER 27, 2002 AND YEARS ENDED DECEMBER 31, 2001 AND 2000
<Table>
<Caption>
COMMON STOCK TREASURY STOCK ADDITIONAL
---------------- ------------------ PAID-IN RETAINED
SHARES AMOUNT SHARES AMOUNT CAPITAL EARNINGS TOTAL
------ ------ ------ -------- ---------- -------- --------
(IN THOUSANDS, EXCEPT SHARE DATA)
Balance at January 1, 2000...... 6,667 $7 -- $ -- $25,432 $ 20,231 $ 45,670
Net income.................... -- -- -- -- -- 4,673 4,673
Repurchased common stock...... -- -- 2,000 (17,837) -- -- (17,837)
----- -- ----- -------- ------- -------- --------
Balance at December 31, 2000.... 6,667 7 2,000 (17,837) 25,432 24,904 32,506
Net income.................... -- -- -- -- -- 9,556 9,556
Dividends paid ($.45 per
share)..................... -- -- -- -- -- (3,000) (3,000)
----- -- ----- -------- ------- -------- --------
Balance at December 31, 2001.... 6,667 7 2,000 (17,837) 25,432 31,460 39,062
Net income.................... -- -- -- -- -- 14,077 14,077
Dividends paid ($1.50 per
share)..................... -- -- -- -- -- (10,000) (10,000)
----- -- ----- -------- ------- -------- --------
Balance at December 27, 2002.... 6,667 $7 2,000 $(17,837) $25,432 $ 35,537 $ 43,139
===== == ===== ======== ======= ======== ========
</Table>
See accompanying notes.
F-57
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<Table>
<Caption>
PERIOD ENDED YEAR ENDED YEAR ENDED
DECEMBER 27, DECEMBER 31, DECEMBER 31,
2002 2001 2000
------------ ------------ ------------
(IN THOUSANDS)
OPERATING ACTIVITIES
Net income.............................................. $ 14,077 $ 9,556 $ 4,673
Reconciliation of net income to net cash provided by
operating activities:
Depreciation and amortization......................... 2,106 2,458 2,249
Deferred income taxes................................. (19) 213 (1,940)
Changes in assets and liabilities that provided (used)
cash:
Accounts receivable................................ (105) (1,744) 125
Inventories........................................ 136 120 96
Refundable income taxes............................ 540 488 --
Accounts payable................................... 21 (340) 229
Accrued liabilities................................ 114 96 (1,945)
Other, net......................................... (469) 3 (324)
-------- -------- --------
Net cash provided by operating activities............... 16,401 10,850 3,163
INVESTING ACTIVITIES
Additions to property, plant, and equipment, net........ (791) (511) (1,234)
Sale of property, plant, and equipment.................. -- 5 1,031
-------- -------- --------
Net cash used in investing activities................... (791) (506) (203)
FINANCING ACTIVITIES
Repayment of notes payable -- related parties........... -- (11,832) --
Dividends paid.......................................... (10,000) (3,000) --
Note issued to purchase treasury stock.................. -- -- 11,832
Purchase of treasury stock.............................. -- -- (17,832)
-------- -------- --------
Net cash used in financing activities................... (10,000) (14,832) (6,000)
-------- -------- --------
Increase (decrease) in cash and cash equivalents........ 5,610 (4,488) (3,040)
Cash and cash equivalents, beginning of year............ 2,352 6,840 9,880
-------- -------- --------
Cash and cash equivalents, end of year.................. $ 7,962 $ 2,352 $ 6,840
======== ======== ========
Supplemental cash flow information:
Cash paid for income taxes............................ $ 7,080 $ 4,450 $ 4,431
Cash paid for interest................................ -- 433 13
</Table>
See accompanying notes.
F-58
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PERIOD ENDED DECEMBER 27, 2002 AND YEARS ENDED DECEMBER 31, 2001 AND 2000
1. CONTROL AND OWNERSHIP OF THE COMPANY AND RELATED-PARTY TRANSACTIONS
Oasis Pipe Line Company (the "Company"), a Delaware corporation, is engaged
in the operation of an intrastate natural gas transmission system in the state
of Texas. Immediately prior to December 27, 2002, the Company was owned 50% by a
subsidiary of Aquila Gas Pipeline Corporation (Aquila Gas Pipeline), and 50% by
Dow Hydrocarbons & Resources, Inc. ("DHRI"). Prior to October 4, 2002, Aquila
Gas Pipeline was the wholly owned subsidiary of Aquila, Inc. In October 2002, La
Grange Acquisition, L.P. ("La Grange Acquisition") acquired substantially all
the assets of Aquila Gas Pipeline. On December 27, 2002 the Company redeemed all
of DHRI's stock using funds advanced from La Grange Acquisition making the
Company a wholly owned subsidiary of La Grange Acquisition.
Before December 28, 2000, ownership was 35% by a subsidiary of Aquila Gas
Pipeline, 35% by El Paso Field Services ("EPFS"), and 30% by DHRI. On that date,
EPFS sold 5% of its interest to DHRI and the remaining 30% interest was acquired
by the Company as treasury stock.
During 2002, 2001 and 2000, the Company derived revenues from its
shareholders and their affiliates for the transmission and sale of natural gas.
The amount of such net revenues totaled approximately $5,975,000, $8,364,000,
and $7,953,000 for the years ended December 27, 2002, and December 31, 2001, and
2000, respectively. Accounts receivable due from affiliates were approximately
$364,000 and $552,000 for 2002 and 2001, respectively.
During 2000, the Company reacquired 2,000 previously issued shares of
capital stock for $17.8 million. The acquisition was funded with working capital
and the borrowing of $11.8 million from shareholders (Aquila Gas Pipeline and
DHRI). The borrowings were represented by notes payable bearing interest at 9%.
Interest expense associated with the notes payable was $433,000 and $13,000
during 2001 and 2000, respectively. The notes were paid during 2001.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiaries (collectively, the "Company"). All
intercompany accounts and transactions have been eliminated in consolidation.
The consolidated financial statements present the financial position and results
of operations of the Company prior to its becoming a subsidiary of La Grange
Acquisition and therefore exclude the purchase adjustments relating to the
redemption and intercompany promissory note on December 27, 2002 (see Note 7).
INVENTORIES
The Company requires its customers to provide additional gas, based on
predetermined quantities of gas to be delivered, for fuel. If the gas is in
excess of the Company's needs, the Company can retain the excess gas or sell it
to third parties. If additional fuel is required, the Company will purchase
additional volumes in the market. Inventories represent the gas that is
retained. The Company values inventories at the lower of cost or market as of
the balance sheet dates.
PROPERTY, PLANT, AND EQUIPMENT
Normal maintenance that does not add capacity or extend the useful life of
the equipment and repairs of property, plant, and equipment are charged to
expense as incurred. Improvements that materially extend the useful lives of the
assets are capitalized, and the assets replaced, if any, are retired. When
capital assets are retired or replaced, the balance of the assets and the
accumulated depreciation are removed and
F-59
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
any gain or loss upon disposition is included in income. Fixed assets of
approximately $346,000 and $134,000 were retired during 2002 and 2001,
respectively.
Depreciation is computed using the straight-line method of accounting over
the estimated useful lives of the related assets. Annual depreciable lives range
from 5 to 85 years.
The Company records impairment losses on long-lived assets used in
operations when events and circumstances indicate that the assets might be
impaired and the undiscounted cash flows estimated to be generated by those
assets are less than the carrying amounts of those assets.
ENVIRONMENTAL EXPENDITURES
Environmental related restoration and remediation costs are recorded as
liabilities and expensed when site restoration and environmental remediation and
cleanup obligations are either known or considered probable and the related
costs can be reasonably estimated.
INCOME TAXES
The Company recognizes deferred tax assets and liabilities for the expected
future tax consequences of temporary differences between the financial
accounting bases and the tax bases of assets and liabilities. The deferred tax
effects of these temporary differences are calculated using the tax rates
currently in effect.
REVENUE RECOGNITION
Transportation revenue is recognized as transportation is provided.
Capacity payments are recognized when earned in the period capacity was made
available.
FINANCIAL INSTRUMENTS AND CREDIT RISK
The Company's financial instruments consist of cash and cash equivalents,
accounts receivable, and accounts payable. The carrying value of the Company's
financial instruments approximates fair value due to their short-term nature.
The Company considers all investments with maturities of three months or less at
acquisition to be cash equivalents. The Company's receivables are generally from
entities involved in the energy industry or significant industrial customers.
The Company specifically reviews all its receivables in determining its
allowance for doubtful accounts and the receivables are generally unsecured.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amount of revenues and expenses during the reporting
period. Actual results could differ from these estimates.
RECLASSIFICATIONS
Certain reclassifications have been made to the 2001 and 2000 amounts to
conform to the 2002 presentation.
F-60
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3. INCOME TAXES
Components of income tax provision/(benefit) attributable to income before
taxes are as follows:
<Table>
<Caption>
DECEMBER 27, DECEMBER 31, DECEMBER 31,
2002 2001 2000
------------ ------------ ------------
Current......................................... $7,607 $4,938 $ 4,458
Deferred........................................ (19) 213 (1,940)
------ ------ -------
Total income tax expense........................ $7,588 $5,151 $ 2,518
====== ====== =======
</Table>
The tax provision effective rate for December 27, 2002 and December 31,
2001 and 2000 was 35%.
Deferred income taxes consist of the following:
<Table>
<Caption>
DECEMBER 27, DECEMBER 31,
2002 2001
------------ ------------
Property, plant and equipment............................... $(9,178) $(9,131)
Other....................................................... (283) (349)
------- -------
Net deferred tax liabilities................................ $(9,461) $(9,480)
======= =======
</Table>
4. EMPLOYEE BENEFIT PLAN
An employee savings plan is available to all permanent employees, effective
the first day of their employment. For every $1 each employee contributes, the
Company matches $1, not to exceed 5% of each employee's salary subject to the
maximum contribution allowed by law. Each employee is fully vested on his or her
first day of employment. The Company expensed contributions of approximately
$144,000, $140,000, and $140,000 for 2002, 2001 and 2000, respectively.
5. CONTINGENCIES
The Company is subject to federal, state and local environmental laws and
regulations, which generally require expenditures for remediation at operating
facilities and waste disposal sites. At December 27, 2002 and December 31, 2001,
the Company had reserved approximately $252,000 and $292,000 respectively, for
the expected costs of complying with such laws and regulations. These expected
costs are primarily related to properties previously owned and are recorded on
the consolidated balance sheets as accrued liabilities based upon management's
estimates of the timing of the expenditure. The purchase and sale agreement
between La Grange Acquisition and Aquila Gas Pipeline requires Aquila, Inc. to
reimburse Oasis for 50% of any remediation expenditures related to operations
prior to October 1, 2002.
On June 16, 2003, Guadalupe Power Partners, L.P. (GPP) sought and obtained
a Temporary Restraining Order against Oasis Pipe Line. In their pleadings, GPP
alleged unspecified monetary damages for the period from February 25, 2003 to
June 16, 2003 and sought to prevent Oasis Pipe Line from implementing flow
control measures to reduce the flow of gas to their power plant at varying
hourly rates. Oasis Pipe Line filed a counterclaim against GPP asking for
damages and a declaration that the contract was terminated as a result of the
breach by GPP. Oasis Pipe Line and GPP agreed to a "stand still" order and
referred this dispute to binding arbitration. Oasis Pipe Line has retained trial
counsel to defend this matter and a date for the commencement of the arbitration
proceedings has not yet been set.
The Company is also party to legal actions that have arisen in the ordinary
course of its business. Due to the inherent uncertainty of litigation, the range
of any possible loss cannot be estimated with a reasonable degree of precision.
F-61
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. PIPELINE ADDITION
During 1999, the Company entered into a facility agreement with an
affiliate of its customer, American National Power ("ANP"), whereby the Company
committed to construct a lateral pipeline connecting the Company's main pipeline
to a power plant operated by ANP in exchange for a payment of $4.7 million,
which was received by the Company in 2000. The transaction resulted in a gain of
$787,000 in 2000.
7. STOCK REDEMPTION
On December 27, 2002, the Company purchased 50% of its capital stock owned
by DHRI for $87 million. The Company funded the acquisition by borrowing $87
million from La Grange Acquisition evidenced by a promissory note (the "Note").
Effective with the redemption, the Company became a wholly owned subsidiary of
La Grange Acquisition and is included in the financial statements of La Grange
Acquisition effective December 27, 2002. The Note bears interest at an annual
rate of 8.5% with payments of $1.6 million due monthly until final maturity on
February 1, 2006 at which time the remaining balance will be due. The
consolidated financial statements present the financial position and results of
operations of the Company prior to its becoming a subsidiary of LaGrange
Acquisition and therefore exclude the purchase adjustments relating to the
redemption and intercompany promissory note on December 27, 2002.
F-62
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 ANY OFFER TO BUY THESE
SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED.
PROSPECTUS
SUBJECT TO COMPLETION, DATED JANUARY 8, 2004
$800,000,000
HERITAGE PROPANE PARTNERS, L.P.
COMMON UNITS
DEBT SECURITIES
---------------------
HERITAGE OPERATING, L.P.
DEBT SECURITIES
---------------------
1,988,846
COMMON UNITS
OFFERED BY SELLING UNITHOLDERS
---------------------
The following securities may be offered under this prospectus:
- Common units representing limited partner interests in Heritage Propane
Partners, L.P.;
- Debt securities of Heritage Propane Partners, L.P.; and
- Debt securities of Heritage Operating, L.P., in an aggregate initial
offering price of $800,000,000; and
- Up to 1,988,846 common units offered by selling unitholders.
The aggregate initial offering price of the securities that we offer by
this prospectus will not exceed $800,000,000. We will offer the securities in
amounts, at prices and on terms to be determined by market conditions at the
time of our offerings. This prospectus describes only the general terms of these
securities and the general manner in which we will offer the securities. The
specific terms of any securities we offer will be included in a supplement to
this prospectus. The prospectus supplement will describe the specific manner in
which we will offer the securities and also may add, update or change
information contained in this prospectus. The common units are traded on the New
York Stock Exchange under the symbol "HPG."
You should read this prospectus and the prospectus supplement carefully
before you invest in any of our securities. This prospectus may not be used to
consummate sales of our securities unless it is accompanied by a prospectus
supplement.
Investing in our securities involves risk. You should carefully consider
the risk factors described under "Risk Factors" beginning on page 2 of this
prospectus before you make any investment in our securities.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED WHETHER
THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
The date of this prospectus is , 2004.
TABLE OF CONTENTS
<Table>
ABOUT THIS PROSPECTUS....................................... 1
WHO WE ARE.................................................. 1
THE SUBSIDIARY GUARANTORS................................... 1
RISK FACTORS................................................ 2
FORWARD-LOOKING STATEMENTS.................................. 14
USE OF PROCEEDS............................................. 15
RATIO OF EARNINGS TO FIXED CHARGES.......................... 15
DESCRIPTION OF THE COMMON UNITS............................. 17
CASH DISTRIBUTION POLICY.................................... 24
DESCRIPTION OF THE DEBT SECURITIES.......................... 29
SELLING UNITHOLDERS......................................... 39
MATERIAL TAX CONSIDERATIONS................................. 40
INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS.................. 54
PLAN OF DISTRIBUTION........................................ 55
LEGAL MATTERS............................................... 56
EXPERTS..................................................... 56
WHERE YOU CAN FIND MORE INFORMATION......................... 57
</Table>
---------------------
You should rely only on the information contained in this prospectus, any
prospectus supplement and the documents we have incorporated by reference. We
have not authorized anyone else to give you different information. We are not
offering these securities in any state where the offer 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 those
documents. We will disclose any material changes in our affairs in an amendment
to this prospectus, a prospectus supplement or a future filing with the
Securities and Exchange Commission incorporated by reference in this prospectus.
i
ABOUT THIS PROSPECTUS
This prospectus is part of a registration statement on Form S-3 that we
have filed with the Securities and Exchange Commission using a "shelf"
registration process. Under this shelf registration process, we may sell, in one
or more offerings, up to $800,000,000 in total aggregate offering price of
securities described in this prospectus. In addition, the selling unitholders
named in this prospectus may offer and sell up to 6,415,762 common units under
this prospectus. This prospectus provides you with a general description of us
and the securities offered under this prospectus. Unless otherwise provided in a
prospectus supplement, we will not receive any proceeds from sales of common
units by the selling unitholders.
Each time we or a selling unitholder sells securities under this
prospectus, we will provide a prospectus supplement that will contain specific
information about the terms of that offering and the securities being offered.
The prospectus supplement also may add to, update or change information in this
prospectus. If there is any inconsistency between the information in this
prospectus and any prospectus supplement, you should rely on the information in
the prospectus supplement. You should read carefully this prospectus, any
prospectus supplement and the additional information described below under the
heading "Where You Can Find More Information."
As used in this prospectus, "we," "us" and "our" and similar terms mean
either or both of Heritage Propane Partners, L.P. and Heritage Operating, L.P.
and their subsidiaries, unless the context indicates otherwise.
WHO WE ARE
We are a publicly traded Delaware limited partnership formed in conjunction
with our initial public offering in June 1996. We are engaged in the retail and
wholesale marketing of propane and related appliances and services. We believe
that we are the fourth largest retail marketer of propane in the United States,
currently serving more than 650,000 customers from over 300 customer service
locations in 31 states. Our operations extend from coast to coast, with
concentrations in the western, upper midwestern, northeastern, and southeastern
regions of the United States. U.S. Propane, L.P. serves as our general partner
and U.S. Propane, L.L.C. serves as the general partner of U.S. Propane, L.P. We
are also a wholesale propane supplier in the southwestern and southeastern
United States and in Canada, the latter through participation in M-P Energy
Partnership. M-P Energy Partnership is a Canadian partnership in which we own a
60% interest through our subsidiary M-P Oils, Ltd., which is engaged in
lower-margin wholesale marketing activities and also supplies our northern U.S.
locations. Prior to January 2004, our operations in the state of Nevada and a
portion of California were conducted through a California general partnership,
Bi-State Propane, in which we owned a 50% interest through our subsidiary
Heritage-Bi State, L.L.C. In January 2004, Heritage-Bi State, L.L.C. acquired
100% of the assets of Bi-State Propane and continues to conduct those operations
under the tradename Bi-State Propane. Our partnership agreement limits our
general partner's fiduciary duties to our unitholders and restricts the remedies
available for actions taken by our general partner that might otherwise
constitute breaches of fiduciary duty.
We maintain our principal executive offices at 8801 South Yale Avenue,
Suite 310, Tulsa, Oklahoma 74137, and our telephone number is (918) 492-7272.
THE SUBSIDIARY GUARANTORS
Heritage Propane Partners, L.P. will, and Heritage Service Corp.,
Heritage-Bi State, L.L.C. and Heritage Energy Resources, L.L.C. may,
unconditionally guarantee any series of debt securities of Heritage Operating,
L.P. offered by this prospectus, as set forth in a related prospectus
supplement. Heritage Operating, L.P., Heritage Service Corp., Heritage-Bi State,
L.L.C. and Heritage Energy Resources, L.L.C. may unconditionally guarantee any
series of debt securities of Heritage Propane Partners, L.P. offered by this
prospectus, as set forth in a related prospectus supplement. As used in this
prospectus, the term "Subsidiary Guarantors" means Heritage Service Corp.,
Heritage-Bi State, L.L.C. and Heritage Energy Resources, L.L.C. and also
includes Heritage Operating, L.P. when discussing subsidiary guarantees of the
debt securities of Heritage Propane Partners, L.P. The term "Guarantor" means
Heritage Propane Partners, L.P. in its role as guarantor of the debt securities
of Heritage Operating, L.P.
1
RISK FACTORS
Limited partner interests are inherently different from the capital stock
of a corporation, although many of the business risks to which we are subject
are similar to those that would be faced by a corporation engaged in a similar
business. Before you invest in our securities, you should consider carefully the
following risk factors, together with all of the other information included in
this prospectus, any prospectus supplement and the documents we have
incorporated by reference.
If any of the following risks actually were to occur, our business,
financial condition or results of operations could be affected materially and
adversely. In that case, we may be unable to make distributions to our
unitholders or pay interest on, or the principal of, any debt securities, the
trading price of our securities could decline and you could lose all or part of
your investment.
RISKS INHERENT IN OUR BUSINESS
SINCE WEATHER CONDITIONS MAY ADVERSELY AFFECT DEMAND FOR PROPANE, OUR
FINANCIAL CONDITION IS VULNERABLE TO WARM WINTERS
Weather conditions have a significant impact on the demand for propane for
both heating and agricultural purposes because many of our customers rely
heavily on propane as a heating fuel. Typically, we sell approximately
two-thirds of our retail propane volume during the peak-heating season of
October through March. Our results of operations can be adversely affected by
warmer winter weather which results in lower sales volumes. Variations in
weather in one or more of the regions where we operate can significantly affect
the total volume of propane that we sell and the profits realized on these
sales. Agricultural demand for propane is also affected by weather during the
harvest season as poor harvests or dry weather reduce demand for propane used in
crop drying.
SUDDEN AND SHARP PROPANE PRICE INCREASES THAT CANNOT BE PASSED ON TO
CUSTOMERS MAY ADVERSELY AFFECT OUR PROFIT MARGINS
The propane industry is a "margin-based" business in which gross profits
depend on the excess of sales prices over supply costs. As a result, our
profitability is sensitive to changes in energy prices, and in particular,
changes in wholesale prices of propane. When there are sudden and sharp
increases in the wholesale cost of propane, we may not be able to pass on these
increases to our customers through retail or wholesale prices. Propane is a
commodity and the price we pay for it can fluctuate significantly in response to
changes in supply or other market conditions over which we have no control. In
addition, the timing of cost pass-throughs can significantly affect margins.
Sudden and extended wholesale price increases could reduce our gross profits and
could, if continued over an extended period of time, reduce demand by
encouraging our retail customers to conserve or convert to alternative energy
sources.
OUR RESULTS OF OPERATIONS AND OUR ABILITY TO MAKE DISTRIBUTIONS OR PAY
INTEREST OR PRINCIPAL ON DEBT SECURITIES COULD BE NEGATIVELY IMPACTED BY PRICE
AND INVENTORY RISK AND MANAGEMENT OF THESE RISKS
We generally attempt to minimize our price and inventory risk by purchasing
product on a short-term basis, under supply contracts that typically have a
one-year term and at a price that fluctuates based on the prevailing market
prices at major delivery points. In order to help ensure adequate supply sources
are available during periods of high demand, we may purchase large volumes of
propane during periods of low demand or low price, which generally occur during
the summer months, for storage in our facilities, at major storage facilities or
for future delivery. This strategy may not be effective in limiting our price
and inventory risks if, for example, market, weather or other conditions prevent
or allocate the delivery of physical product during periods of peak demand. If
the market price falls below the price at which we made such purchases, it could
adversely affect our profits.
Some of our propane sales are pursuant to commitments at fixed prices. To
mitigate the price risk related to our anticipated sales volumes under the
commitments, we may purchase and store physical product and/or enter into fixed
price over-the-counter energy commodity forward contracts and options.
2
Generally, over-the-counter energy commodity forward contracts have terms of
less than one year. We enter into such contracts and exercise such options at
volume levels that we believe are necessary to manage these commitments. The
risk management of our inventory and contracts for the future purchase of
product could impair our profitability if the customers do not fulfill their
obligations.
We also engage in other trading activities, and may enter into other types
of over-the-counter energy commodity forward contracts and options. These
trading activities are based on our management's estimates of future events and
prices and are intended to generate a profit. However, if those estimates are
incorrect or other market events outside of our control occur, such activities
could generate a loss in future periods and potentially impair our
profitability.
WE ARE DEPENDENT ON OUR PRINCIPAL SUPPLIERS, WHICH INCREASES THE RISK OF AN
INTERRUPTION IN SUPPLY
During the first nine months of fiscal 2003, we purchased approximately 29%
of our propane from Enterprise Products Operating L.P., approximately 13% of our
propane from Dynegy Liquids Marketing and Trade and approximately 19% of our
propane from MP Energy, the Canadian partnership in which we own a 60% interest.
If supplies from these sources were interrupted, the cost of procuring
replacement supplies and transporting those supplies from alternative locations
might be materially higher and, at least on a short-term basis, margins could be
adversely affected. Supply from Canada is subject to the additional risk of
disruption associated with foreign trade such as trade restrictions, shipping
delays and political, regulatory and economic instability.
Historically, a substantial portion of the propane we purchase has
originated from one of the industry's major markets located in Mont Belvieu,
Texas and has been shipped to us through major common carrier pipelines. Any
significant interruption in the service at Mont Belvieu or other major market
points, or on the common carrier pipelines we use would adversely affect our
ability to obtain propane.
BECAUSE OF THE HIGHLY COMPETITIVE NATURE OF THE RETAIL PROPANE BUSINESS, WE
MAY NOT BE ABLE TO MAINTAIN EXISTING CUSTOMERS OR ACQUIRE NEW CUSTOMERS, WHICH
WOULD HAVE AN ADVERSE IMPACT ON OUR OPERATING RESULTS AND FINANCIAL CONDITION
We compete with a number of large national and regional propane companies,
some of whom have greater financial resources than we do, and several thousand
small independent propane companies. Because of the relatively low barriers to
entry into the retail propane market, there is potential for small independent
propane retailers, as well as other companies that may not be engaged in retail
propane distribution, to compete with our retail outlets. As a result, we are
always subject to the risk of additional competition in the future. Generally,
warmer-than-normal weather further intensifies competition. Most of our propane
retail branch locations compete with several other marketers or distributors in
their service areas. The principal factors influencing competition with other
retail marketers are:
- price,
- reliability and quality of service,
- responsiveness to customer needs,
- safety concerns,
- long-standing customer relationships,
- the inconvenience of switching tanks and suppliers, and
- the lack of growth in the industry.
We can make no assurances that we will be able to compete successfully on the
basis of these factors.
3
COMPETITION FROM ALTERNATIVE ENERGY SOURCES MAY CAUSE US TO LOSE CUSTOMERS,
THEREBY REDUCING OUR REVENUES
Competition from alternative energy sources has been increasing as a result
of reduced regulation of many utilities. Propane is generally not competitive
with natural gas in areas where natural gas pipelines already exist because
natural gas is a less expensive source of energy than propane. The gradual
expansion of natural gas distribution systems and the availability of natural
gas in many areas that previously depended upon propane could cause us to lose
customers, thereby reducing our revenues. Fuel oil also competes with propane
and is generally less expensive than propane. In addition, the successful
development and increasing usage of alternative energy sources could adversely
affect our operations.
IF WE DO NOT CONTINUE TO MAKE ACQUISITIONS ON ECONOMICALLY ACCEPTABLE
TERMS, OUR FUTURE FINANCIAL PERFORMANCE WILL BE LIMITED
The propane industry is not a growth industry in part because of increased
competition from alternative energy sources. In addition, because of
long-standing customer relationships that are typical in the retail propane
industry, the inconvenience of switching tanks and suppliers, and propane's
higher cost relative to other energy sources, such as natural gas, we may have
difficulty in increasing our retail customer base except through acquisitions.
Therefore, our ability to grow will depend primarily upon our ability to acquire
other retail propane distributors. Any acquisition may involve one or more of
the following risks, including:
- an increase in our indebtedness, which may affect credit ratings and our
ability to make distributions to unitholders;
- the inability to integrate the operations of the acquired business into
our existing operations and make cost-saving changes such that the
acquisition will be accretive to earnings and distributions to
unitholders;
- the diversion of management's attention from other business concerns;
- the assumption of unknown liabilities and/or the inability or failure of
the sellers to indemnify us under the acquisition agreements; and
- greater-than-expected loss of customers or employees from the acquired
business.
We are also subject to restrictive covenants contained in our debt
agreements. Our debt agreements consist of our bank credit facility and the
three note agreements with our secured lenders. These covenants limit our
ability to incur additional indebtedness, grant liens on our properties or
assets, or make loans, advances, investments and engage in transactions with
affiliates. In addition, these covenants require us to maintain ratios of
consolidated funded indebtedness to consolidated EBITDA (as these terms are
similarly defined in the debt agreements) of not more than 5.00 to 1 for the
bank credit facility and not more than 5.25 to 1 for the note agreements and
consolidated EBITDA to consolidated interest expense (as these terms are
similarly defined in the debt agreements) of not less than 2.25 to 1.
In addition, to the extent that warm weather or other factors adversely
affects our operating and financial results, our access to capital and our
acquisition activities may be limited. If we were to acquire a material amount
of non-propane assets as part of our expansion strategy, we would face the
additional risk of integrating a new line of business into our operations.
WE ARE SUBJECT TO OPERATING AND LITIGATION RISKS THAT COULD ADVERSELY
AFFECT OUR OPERATING RESULTS
Our operations are subject to all operating hazards and risks normally
incidental to handling, storing and delivering combustible liquids like propane.
As a result, we have been, and are likely to be, a defendant in various legal
proceedings arising in the ordinary course of business. Our insurance may not be
adequate to protect us from all material expenses related to potential future
claims for personal injury and property damage and we may not be able to
continue purchasing such levels of insurance at economical
4
prices. In addition, the occurrence of a serious accident involving propane,
whether or not we are involved, may have an adverse effect on the public's
desire to use propane.
ENERGY EFFICIENCY AND TECHNOLOGICAL ADVANCES MAY AFFECT THE DEMAND FOR
PROPANE AND ADVERSELY AFFECT OUR OPERATING RESULTS
The national trend toward increased conservation and technological
advances, including installation of improved insulation and the development of
more efficient furnaces and other heating devices, has decreased the demand for
propane by retail customers. Stricter conservation measures in the future or
technological advances in heating, conservation, energy generation or other
devices could adversely affect our operations.
DUE TO OUR LACK OF ASSET DIVERSIFICATION, ADVERSE DEVELOPMENTS IN OUR
PROPANE BUSINESS WOULD REDUCE OUR ABILITY TO MAKE DISTRIBUTIONS TO OUR
UNITHOLDERS
We rely exclusively on the revenues generated from our propane business.
Due to our lack of asset diversification, an adverse development in this
business would have a significantly greater impact on our financial condition
and results of operations than if we maintained more diverse assets.
RISKS INHERENT IN AN INVESTMENT IN US
CASH DISTRIBUTIONS ARE NOT GUARANTEED AND MAY FLUCTUATE WITH OUR
PERFORMANCE AND OTHER EXTERNAL FACTORS
The amount of cash we can distribute on our common units or other
partnership securities depends upon the amount of cash we generate from our
operations. The amount of cash we generate from our operations will fluctuate
from quarter to quarter and will depend upon, among other things:
- the weather in our operating areas;
- the cost to us of the propane we buy for resale and the prices we receive
for our propane;
- the level of competition from other propane companies and other energy
providers; and
- prevailing economic conditions.
In addition, the actual amount of cash available for distribution will also
depend on other factors, such as:
- the level of capital expenditures we make;
- debt service requirements;
- fluctuations in working capital needs;
- our ability to borrow under our working capital facility to make
distributions; and
- the amount, if any, of cash reserves established by the general partner
in its discretion for the proper conduct of our business.
Because of all these factors, we may not have sufficient available cash
each quarter to be able to pay the minimum quarterly distribution, as defined in
our partnership agreement.
Furthermore, you should be aware that the amount of cash we have available
for distribution depends primarily upon our cash flow, including cash flow from
financial reserves and working capital borrowings, and is not solely a function
of profitability, which will be affected by non-cash items. As a result, we may
make cash distributions during periods when we record net losses and may not
make cash distributions during periods when we record net income.
5
WE MAY SELL ADDITIONAL LIMITED PARTNER INTERESTS, DILUTING EXISTING
INTERESTS OF UNITHOLDERS
Our partnership agreement allows us to issue an unlimited number of
additional limited partner interests, including securities senior to the common
units, without the approval of the unitholders. The issuance of additional
common units or other equity securities will have the following effects:
- the proportionate ownership interest of our unitholders in us will
decrease;
- the amount of cash available for distribution on each common unit or
partnership security may decrease;
- the relative voting strength of each previously outstanding common unit
may be diminished; and
- the market price of the common units or partnership securities may
decline.
OUR DEBT AGREEMENTS MAY LIMIT OUR ABILITY TO MAKE DISTRIBUTIONS TO
UNITHOLDERS AND OUR FINANCIAL FLEXIBILITY
As of August 31, 2003, we had outstanding $349.9 million in senior secured
debt with insurance companies and $51.4 million in secured debt under our bank
credit facility. Our current leverage may adversely affect our ability to
finance future operations and capital needs, limit our ability to pursue
acquisitions and other business opportunities and make our results of operations
more susceptible to adverse economic conditions. We may in the future incur
additional debt to finance acquisitions or for general business purposes, which
could result in a significant increase in our leverage. The payment of principal
and interest on our debt will reduce the cash available to make distributions on
the common units. We will not be able to make any distributions to our
unitholders if there is or will be an event of default under our debt
agreements. Our ability to make principal and interest payments depends on
future performance, which is subject to many factors, several of which will be
outside our control. We have granted liens on substantially all of our personal
property (other than vehicles) to secure our existing debt. If an event of
default occurs, the secured lenders can foreclose on the collateral.
Our debt agreements contain provisions relating to changes in ownership and
changes of our general partner. If these provisions are triggered, the
outstanding debt under these agreements may become due. If that happens, we
cannot guarantee that we would be able to pay the debt. The general partner and
its partners are not prohibited from entering into a transaction that would
trigger these change-in-ownership provisions. The notes and the bank credit
facility also contain restrictive covenants that limit our ability to incur
additional debt and to engage in certain transactions. The debt agreements
contain covenants that require us to maintain ratios of consolidated funded
indebtedness to consolidated EBITDA (as these terms are similarly defined in the
debt agreements) of not more than 5.00 to 1 for the bank credit facility and not
more than 5.25 to 1 for the note agreements and consolidated EBITDA to
consolidated interest expense (as these terms are similarly defined in the debt
agreements) of not less than 2.25 to 1. Other covenants also limit our ability
to incur additional indebtedness, grant liens on our properties or assets, or
make loans, advances, investments and engage in transactions with affiliates.
These covenants could reduce our ability to capitalize on business opportunities
as they arise. Any new indebtedness could be reasonably expected to have similar
or greater restrictions.
Our ability to access the capital markets for future offerings may be
limited by adverse market conditions resulting from, among other things, general
economic conditions, contingencies and uncertainties that are difficult to
predict and beyond our control. If we are unable to access the capital markets
for future offerings, we might be forced to seek extensions for some of our
short-term maturities or to refinance some of our debt obligations through bank
credit, as opposed to long-term public or private debt securities or equity
securities. The price and terms upon which we might receive such extensions or
additional bank credit could be more onerous than those contained in our
existing debt agreements. Any such arrangements could, in turn, increase the
risk that our leverage may adversely affect our future financial and operating
flexibility.
6
THE GENERAL PARTNER IS NOT ELECTED BY THE UNITHOLDERS AND CANNOT BE REMOVED
WITHOUT ITS CONSENT
Unlike the holders of common stock in a corporation, unitholders have only
limited voting rights on matters affecting our business, and therefore limited
ability to influence management's decisions regarding our business. Unitholders
did not elect our general partner and will have no right to elect our general
partner on an annual or other continuing basis. Although our general partner has
a fiduciary duty to manage us in a manner beneficial to Heritage Propane
Partners, L.P. and the unitholders, the directors of our general partner and its
general partner, U.S. Propane, L.L.C., have a fiduciary duty to manage the
general partner and its general partner in a manner beneficial to the owners of
those entities.
Furthermore, if the unitholders are dissatisfied with the performance of
our general partner, they will have little ability to remove our general
partner. The general partner generally may not be removed except upon the vote
of the holders of 66 2/3% of the outstanding units voting together as a single
class, including units owned by the general partner and its affiliates. Because
the general partner and its affiliates currently hold approximately 25.7% of all
the units, with an additional 11.0% of units held by our officers and directors,
it will be difficult to remove the general partner without the consent of the
general partner and our affiliates.
Furthermore, unitholders' voting rights are further restricted by the
partnership agreement provision providing that any units held by a person that
owns 20% or more of any class of units then outstanding, other than the general
partner and its affiliates, cannot be voted on any matter.
THE CONTROL OF OUR GENERAL PARTNER MAY BE TRANSFERRED TO A THIRD PARTY
WITHOUT UNITHOLDER CONSENT
The general partner may transfer its general partner interest to a third
party in a merger or in a sale of all or substantially all of its assets without
the consent of the unitholders. Furthermore, there is no restriction in the
partnership agreement on the ability of the general partner of our general
partner from transferring its general partner interest in our general partner to
a third party. Any new owner of the general partner would be in a position to
replace the officers of the general partner with its own choices and to control
the decisions taken by such officers.
UNITHOLDERS MAY BE REQUIRED TO SELL THEIR UNITS TO THE GENERAL PARTNER AT
AN UNDESIRABLE TIME OR PRICE
If at any time less than 20% of the outstanding units of any class are held
by persons other than the general partner and its affiliates, the general
partner will have the right to acquire all, but not less than all, of those
units at a price no less than their then-current market price. As a consequence,
a unitholder may be required to sell his common units at an undesirable time or
price. The general partner may assign this purchase right to any of its
affiliates or to us.
COST REIMBURSEMENTS DUE OUR GENERAL PARTNER MAY BE SUBSTANTIAL AND REDUCE
OUR ABILITY TO PAY THE DISTRIBUTIONS TO UNITHOLDERS
Prior to making any distributions on the units, we will reimburse our
general partner for all expenses it has incurred on our behalf. In addition, our
general partner and its affiliates may provide us with services for which we
will be charged reasonable fees as determined by the general partner. The
reimbursement of these expenses and the payment of these fees could adversely
affect our ability to make distributions to the unitholders. Our general partner
has sole discretion to determine the amount of these expenses and fees.
UNITHOLDERS MAY HAVE LIABILITY TO REPAY DISTRIBUTIONS
Under certain circumstances unitholders may have to repay us amounts
wrongfully returned or distributed to them. Under Delaware law, we may not make
a distribution to you if the distribution causes our liabilities to exceed the
fair value of our assets. Liabilities to partners on account of their
partnership interests and non-recourse liabilities are not counted for purposes
of determining whether a distribution is permitted. Delaware law provides that a
limited partner who receives such a distribution and knew at the time of the
distribution that the distribution violated Delaware law will be liable to the
limited partnership
7
for the distribution amount for three years from the distribution date. Under
Delaware law, an assignee who becomes a substituted limited partner of a limited
partnership is liable for the obligations of the assignor to make contributions
to the partnership. However, such an assignee is not obligated for liabilities
unknown to him at the time he or she became a limited partner if the liabilities
could not be determined from the partnership agreement.
OUR PARTNERSHIP AGREEMENT LIMITS OUR GENERAL PARTNER'S FIDUCIARY DUTIES TO
OUR UNITHOLDERS AND RESTRICTS THE REMEDIES AVAILABLE TO UNITHOLDERS FOR ACTIONS
TAKEN BY OUR GENERAL PARTNER THAT MIGHT OTHERWISE CONSTITUTE BREACHES OF
FIDUCIARY DUTY
Our partnership agreement contains provisions that waive or consent to
conduct by our general partner and its affiliates that reduce the obligations to
which our general partner would otherwise be held by state-law fiduciary duty
standards. The following is a summary of the material restrictions contained in
our partnership agreement on the fiduciary duties owed by our general partner to
the limited partners. Our partnership agreement:
- permits our general partner to make a number of decisions in its "sole
discretion." This entitles our general partner to consider only the
interests and factors that it desires, and it has no duty or obligation
to give any consideration to any interest of, or factors affecting, us,
our affiliates or any limited partner;
- provides that our general partner is entitled to make other decisions in
its "reasonable discretion";
- generally provides that affiliated transactions and resolutions of
conflicts of interest not involving a required vote of unitholders must
be "fair and reasonable" to us and that, in determining whether a
transaction or resolution is "fair and reasonable," our general partner
may consider the interests of all parties involved, including its own.
Unless our general partner has acted in bad faith, the action taken by
our general partner shall not constitute a breach of its fiduciary duty;
and
- provides that our general partner and its officers and directors will not
be liable for monetary damages to us, our limited partners or assignees
for errors of judgment or for any acts or omissions if our general
partner and those other persons acted in good faith.
In order to become a limited partner of our partnership, a common
unitholder is required to agree to be bound by the provisions in the partnership
agreement, including the provisions discussed above.
THE GENERAL PARTNER'S ABSOLUTE DISCRETION IN DETERMINING THE LEVEL OF CASH
RESERVES MAY ADVERSELY AFFECT OUR ABILITY TO MAKE CASH DISTRIBUTIONS TO OUR
UNITHOLDERS
Our partnership agreement requires the general partner to deduct from
operating surplus cash reserves that in its reasonable discretion are necessary
to fund our future operating expenditures. In addition, the partnership
agreement permits the general partner to reduce available cash by establishing
cash reserves for the proper conduct of our business, to comply with applicable
law or agreements to which we are a party or to provide funds for future
distributions to partners. These cash reserves will affect the amount of cash
available for distribution to unitholders.
OUR GENERAL PARTNER HAS CONFLICTS OF INTEREST AND LIMITED FIDUCIARY
RESPONSIBILITIES, WHICH MAY PERMIT OUR GENERAL PARTNER TO FAVOR ITS OWN
INTERESTS TO THE DETRIMENT OF UNITHOLDERS
Our general partner and its affiliates directly and indirectly own an
aggregate limited partner interest of approximately 25.6% and our officers and
directors own approximately 11.5% of the limited partner interests in us.
Conflicts of interest could arise in the future as a result of relationships
between our general partner and its affiliates, on the one hand, and us, on the
other hand. As a result of these conflicts
8
our general partner may favor its own interests and those of its affiliates over
the interests of the unitholders. The nature of these conflicts includes the
following considerations:
- Our general partner may limit its liability and reduce its fiduciary
duties, while also restricting the remedies available to unitholders for
actions that might, without the limitations, constitute breaches of
fiduciary duty. Unitholders are deemed to have consented to some actions
and conflicts of interest that might otherwise be deemed a breach of
fiduciary or other duties under applicable state law.
- Our general partner is allowed to take into account the interests of
parties in addition to us in resolving conflicts of interest, thereby
limiting its fiduciary duties to the unitholders.
- Our general partner's affiliates are not prohibited from engaging in
other businesses or activities, including those in direct competition
with us.
- Our general partner determines the amount and timing of asset purchases
and sales, capital expenditures, borrowings and reserves, each of which
can affect the amount of cash that is distributed to unitholders.
- Our general partner determines whether to issue additional units or other
equity securities of us.
- Our general partner determines which costs are reimbursable by us.
- Our general partner controls the enforcement of obligations owed to us by
it.
- Our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
- Our general partner is not restricted from causing us to pay it or its
affiliates for any services rendered on terms that are fair and
reasonable to us or entering into additional contractual arrangements
with any of these entities on our behalf.
- In some instances our general partner may borrow funds in order to permit
the payment of distributions, even if the purpose or effect of the
borrowing is to make incentive distributions.
TAX RISKS
For a general discussion of the expected federal income tax consequences of
owning and disposing of common units, see "Material Tax Considerations."
THE IRS COULD TREAT US AS A CORPORATION FOR TAX PURPOSES, WHICH WOULD
SUBSTANTIALLY REDUCE THE CASH AVAILABLE FOR DISTRIBUTION TO UNITHOLDERS
The anticipated after-tax economic benefit of an investment in our common
units depends largely on our being treated as a partnership for federal income
tax purposes. We have not requested, and do not plan to request, a ruling from
the IRS on this or any other matter affecting us.
If we were treated as a corporation for federal income tax purposes, we
would pay federal income tax on our income at the corporate tax rate, which is
currently a maximum of 35% and we would likely pay state taxes as well.
Distributions to unitholders would generally be taxed again as corporate
distributions, and none of our income, gains, losses or deductions would flow
through to unitholders. Because a tax would be imposed upon us as a corporation,
our cash available for distribution to unitholders would be substantially
reduced. Therefore, our treatment as a corporation would result in a material
reduction in the after-tax return to the unitholders, likely causing a
substantial reduction in the value of our common units.
A change in current law or a change in our business could cause us to be
treated as a corporation for federal income tax purposes or otherwise subject us
to entity-level taxation. Our partnership agreement provides that, if a law is
enacted or existing law is modified or interpreted in a manner that causes us to
be treated as a corporation or otherwise subjects us to entity-level taxation
for federal, state or local income
9
tax purposes, then the minimum quarterly distribution and the target
distribution levels will be adjusted to reflect that impact on us.
A SUCCESSFUL IRS CONTEST OF THE FEDERAL INCOME TAX POSITIONS WE TAKE MAY
ADVERSELY AFFECT THE MARKET FOR COMMON UNITS AND THE COSTS OF ANY CONTEST WILL
BE BORNE BY OUR UNITHOLDERS AND OUR GENERAL PARTNER
We have not requested a ruling from the IRS with respect to any matter
affecting us. The IRS may adopt positions that differ from the conclusions of
our counsel expressed in this prospectus or from the positions we take. It may
be necessary to resort to administrative or court proceedings to sustain our
counsel's conclusions or the positions we take. A court may not concur with some
or all of our counsel's conclusions or the positions we take. Any contest with
the IRS may materially and adversely affect the market for our common units and
the price at which they trade. In addition, the costs of any contest with the
IRS, principally legal, accounting and related fees, will be indirectly borne by
our unitholders and our general partner since such costs will reduce the amount
of cash available for distribution.
UNITHOLDERS MAY BE REQUIRED TO PAY TAXES ON THEIR SHARE OF OUR INCOME EVEN
IF THEY DO NOT RECEIVE ANY CASH DISTRIBUTIONS FROM US
Unitholders will be required to pay federal income taxes and, in some
cases, state and local income taxes on their share of our taxable income even if
they do not receive any cash distributions from us. Unitholders may not receive
cash distributions from us equal to their share of our taxable income or even
equal to the actual tax liability that results from the taxation of their share
of our taxable income.
ONLY CALENDAR YEAR TAXPAYERS MAY BECOME PARTNERS
Only calendar year taxpayers may purchase common units. Any unitholder who
is not a calendar year taxpayer will not be admitted to Heritage Propane
Partners, L.P. as a partner, will not be entitled to receive distributions or
federal income tax allocations from Heritage Propane Partners, L.P. and may only
transfer these common units to a purchaser or other transferee.
TAX GAIN OR LOSS ON DISPOSITION OF COMMON UNITS COULD BE DIFFERENT THAN
EXPECTED
Unitholders who sell common units will recognize gain or loss equal to the
difference between the amount realized and their tax basis in those common
units. Prior distributions in excess of the total net taxable income allocated
for a common unit that decreased a unitholder's tax basis in that common unit
will, in effect, become taxable income to the unitholder if the common unit is
sold at a price greater than the unitholder's tax basis in that common unit,
even if the price is less than his original cost. A substantial portion of the
amount the unitholder realizes, whether or not representing gain, will likely be
ordinary income to the unitholder. Should the IRS successfully contest some
positions we take, a unitholder could recognize more gain on the sale of common
units than would be the case under those positions, without the benefit of
decreased income in prior years. Also, unitholders who sell common units may
incur a tax liability in excess of the amount of cash they receive from the
sale.
TAX-EXEMPT ENTITIES, REGULATED INVESTMENT COMPANIES AND FOREIGN PERSONS
FACE UNIQUE TAX ISSUES FROM OWNING COMMON UNITS WHICH MAY RESULT IN ADVERSE TAX
CONSEQUENCES TO THEM
Investment in common units by tax-exempt entities, including employee
benefit plans and individual retirement accounts (known as IRAs), regulated
investment companies (known as mutual funds) and non-U.S. persons raises issues
unique to them. For example, virtually all of our income allocated to
unitholders who are organizations exempt from federal income tax, may be
unrelated business taxable income and will be taxable to them. Very little of
our income will be qualifying income to a regulated investment company.
Distributions to non-U.S. persons will be reduced by withholding taxes, at the
highest applicable rate, and non-U.S. persons will be required to file federal
income tax returns and generally pay tax on their share of our taxable income.
10
OUR REGISTRATION AS A "TAX SHELTER" MAY INCREASE THE RISK OF AN IRS AUDIT
OF US OR A UNITHOLDER
We are registered with the IRS as a "tax shelter." Our tax shelter
registration number is 96234000014. As a result, we may be audited by the IRS
and tax adjustments could be made. Any unitholder owning less than a 1% profits
interest in us has very limited rights to participate in the income tax audit
process. Further, any adjustments in our tax returns will lead to adjustments in
the unitholders' tax returns and may lead to audits of the unitholders' tax
returns and adjustments of items unrelated to us. Unitholders will bear the cost
of any expense incurred in connection with an examination of their personal tax
returns and will indirectly bear a portion of the cost of an audit of us.
WE WILL TREAT EACH PURCHASER OF COMMON UNITS AS HAVING THE SAME TAX
BENEFITS WITHOUT REGARD TO THE UNITS PURCHASED. THE IRS MAY CHALLENGE THIS
TREATMENT, WHICH COULD ADVERSELY AFFECT THE VALUE OF THE UNITS
Because we cannot match transferors and transferees of common units, we
will adopt depreciation and amortization positions that do not conform with all
aspects of existing Treasury regulations. A successful IRS challenge to those
positions could adversely affect the amount of tax benefits available to you. It
also could affect the timing of these tax benefits or the amount of gain from
the unitholder's sale of common units and could have a negative impact on the
value of the common units or result in audit adjustments to the unitholder's tax
returns. Please read "Material Tax Considerations -- Tax Consequences of Unit
Ownership -- Section 754 Election" and "-- Uniformity of Units."
UNITHOLDERS LIKELY WILL BE SUBJECT TO STATE AND LOCAL TAXES IN STATES WHERE
THEY DO NOT LIVE AS A RESULT OF AN INVESTMENT IN THE UNITS
In addition to federal income taxes, the unitholders may be subject to
other taxes, including state and local taxes, unincorporated business taxes and
estate, inheritance or intangible taxes that are imposed by the various
jurisdictions in which we do business or own property now or in the future, even
if they do not live in any of those jurisdictions. We presently conduct business
in 29 states. In the future, we may acquire property or do business in other
states or in foreign jurisdictions. Unitholders may be required to file state
and local income tax returns and pay state and local income taxes in some or all
of the jurisdictions. Further, unitholders may be subject to penalties for
failure to comply with those requirements. It is the responsibility of each
unitholder to file all federal, state and local tax returns. Our counsel has not
rendered an opinion on the state or local tax consequences of an investment in
us.
RISKS RELATING TO THE DEBT SECURITIES
References in these "Risks Relating to the Debt Securities" to "we," "us,"
and "our" means Heritage Propane Partners, L.P. and Heritage Operating, L.P.
HERITAGE PROPANE PARTNERS, L.P. IS A HOLDING COMPANY AND CONDUCTS ITS
OPERATIONS THROUGH ITS SUBSIDIARIES AND DEPENDS ON CASH FLOW FROM ITS
SUBSIDIARIES TO SERVICE ANY OF ITS DEBT OBLIGATIONS
Heritage Propane Partners, L.P. conducts all of its operations through its
subsidiaries and owns no significant assets other than the ownership interests
in these subsidiaries. Therefore, the ability of Heritage Propane Partners, L.P.
to make required payments on any debt securities it issues will depend on the
performance of Heritage Operating, L.P. and its subsidiaries and their ability
to distribute funds to Heritage Propane Partners, L.P. The ability of these
subsidiaries to make such distributions may be restricted by, among other
things, their debt agreements and applicable state partnership laws and other
laws and regulations. Under Heritage Operating, L.P.'s debt agreements, Heritage
Operating, L.P. is prohibited from making a distribution to us that would result
in a default in its debt agreements. Heritage Operating, L.P. accounts for
substantially all of our subsidiaries' outstanding indebtedness. Furthermore,
applicable state partnership and limited liability company laws restrict our
subsidiaries from making distributions to us that would result in their
insolvency. Delaware corporate law also provides that Heritage Service Corp. may
only declare dividends either out of its surplus or net profits. If Heritage
Propane Partners, L.P. is unable to obtain the funds necessary to pay the
principal amount at maturity of its debt
11
securities, or to repurchase its debt securities upon the occurrence of a change
of control, Heritage Propane Partners, L.P. may be required to adopt one or more
alternatives, such as a refinancing of the debt securities. We cannot assure you
that Heritage Propane Partners, L.P. would be able to so refinance its debt
securities.
YOUR RIGHT TO RECEIVE PAYMENTS ON THE SECURITIES IS UNSECURED AND WILL BE
EFFECTIVELY SUBORDINATED TO OUR EXISTING AND FUTURE SECURED INDEBTEDNESS AND TO
INDEBTEDNESS OF ANY OF OUR SUBSIDIARIES WHO DO NOT GUARANTEE THE SECURITIES
Any debt securities, including any guarantees, issued by Heritage Propane
Partners, L.P., Heritage Operating, L.P. or the Subsidiary Guarantors will be
effectively subordinated to the claims of our secured creditors. In the event of
the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding
up of the business of Heritage Propane Partners, L.P., Heritage Operating, L.P.
or any Subsidiary Guarantors, their secured creditors would generally have the
right to be paid in full before any distribution is made to the holders of the
debt securities. Furthermore, if any of our subsidiaries do not guarantee the
debt securities, the debt securities will be effectively subordinated to the
claims of all creditors, including trade creditors and tort claimants, of those
subsidiaries. In the event of the insolvency, bankruptcy, liquidation,
reorganization, dissolution or winding up of the business of a subsidiary that
is not a guarantor, creditors of that subsidiary would generally have the right
to be paid in full before any distribution is made to the issuer of the debt
securities or the holders of the debt securities. As of August 31, 2003,
Heritage Propane Partners, L.P. had no outstanding indebtedness. Heritage
Operating, L.P. had outstanding approximately $404.5 million of secured
indebtedness and approximately $21.0 million of unsecured indebtedness. Our
other subsidiaries had approximately $300,000 of outstanding indebtedness, all
of which is secured.
A SUBSIDIARY GUARANTEE COULD BE DEEMED TO BE A FRAUDULENT CONVEYANCE UNDER
CERTAIN CIRCUMSTANCES, AND A COURT MAY TRY TO SUBORDINATE OR VOID THE SUBSIDIARY
GUARANTEES
Under federal bankruptcy laws and comparable provisions of state fraudulent
transfer laws, a guarantee by a subsidiary could be voided, or claims in respect
of a guarantee could be subordinated to all other debts of that guarantor if,
among other things, the guarantor, at the time it incurred the indebtedness
evidenced by its guarantee, received less than reasonably equivalent fair value
or fair consideration for the incurrence of such guarantee, and
- was insolvent or rendered insolvent by reason of such incurrence;
- was engaged in a business or transaction for which the guarantor's
remaining assets constituted unreasonably small capital; or
- intended to incur, or believed that it would incur, debts beyond its
ability to pay such debts as they mature.
In addition, any payment by that subsidiary guarantor pursuant to its
guarantee could be voided and required to be returned to the guarantor, or to a
fund for the benefit of the creditors of the guarantor. The measures of
insolvency for purposes of these fraudulent transfer laws will vary depending
upon the law applied in any proceeding to determine whether a fraudulent
transfer has occurred. Generally, however, a guarantor would be considered
insolvent if:
- the sum of its assets, including contingent liabilities, were greater
than the fair saleable value of all of its assets;
- the present fair saleable value of its assets were less than the amount
that would be required to pay its procurable liability, including
contingent liabilities, on its existing debts, as they become absolute or
mature; or
- it could not pay its debts as they become due.
12
HERITAGE PROPANE PARTNERS, L.P. AND HERITAGE OPERATING, L.P. ARE REQUIRED
TO DISTRIBUTE ALL OF THEIR AVAILABLE CASH TO THEIR UNITHOLDERS AND ARE NOT
REQUIRED TO ACCUMULATE CASH FOR THE PURPOSE OF MEETING THEIR FUTURE OBLIGATIONS
TO HOLDERS OF THEIR DEBT SECURITIES, WHICH MAY LIMIT THE CASH AVAILABLE TO
SERVICE THOSE DEBT SECURITIES
The partnership agreements of Heritage Propane Partners, L.P. and Heritage
Operating, L.P. require us to distribute all of our available cash each fiscal
quarter to our partners. Available cash is generally defined to mean all cash on
hand at the end of the quarter, plus certain working capital borrowings after
the end of the quarter, less reserves established by the general partner in its
sole discretion to provide for the proper conduct of our business (including
reserves for future capital expenditures), to comply with applicable law or
agreements, including debt agreements, or to provide funds for future
distributions to partners. Depending on the timing and amount of our cash
distributions to unitholders and because we are not required to accumulate cash
for the purpose of meeting obligations to holders of any debt securities, such
distributions could significantly reduce the cash available to us in subsequent
periods to make payments on any debt securities.
13
FORWARD-LOOKING STATEMENTS
Some of the information included in this prospectus, any prospectus
supplement and the documents we incorporate by reference contain
"forward-looking" statements. These statements discuss goals, intentions and
expectations as to future trends, plans, events, results of operations or
financial condition, or state other information relating to us, based on the
current beliefs of our management as well as assumptions made by, and
information currently available to, management. Words such as "may," "will,"
"anticipate," "believe," "expect," "estimate," "intend," "project" and other
similar phrases or expressions identify forward-looking statements. When
considering forward-looking statements, you should keep in mind the risk factors
and other cautionary statements in this prospectus, any prospectus supplement
and the documents we have incorporated by reference.
Although we believe these forward-looking statements to be reasonable, they
are based upon a number of assumptions, any or all of which ultimately may prove
to be inaccurate. These statements are subject to numerous assumptions,
uncertainties and risks including, but not limited to, the following:
- the general economic conditions in the United States of America as well
as the general economic conditions and currencies in foreign countries;
- the political and economic stability of petroleum producing nations;
- the effect of weather conditions on demand for propane;
- the effectiveness of risk-management policies and procedures and the
ability of our liquids marketing counterparties to satisfy their
financial commitments;
- energy prices generally and specifically, and the price of propane to the
consumer compared to the price of alternative and competing fuels;
- the general level of petroleum product demand and the availability and
price of propane supplies;
- our ability to obtain adequate supplies of propane for retail sale in the
event of an interruption in supply or transportation and the availability
of capacity to transport propane to market areas;
- hazards or operating risks incidental to transporting, storing and
distributing propane that may not be fully covered by insurance;
- the maturity of the propane industry and competition from other propane
distributors;
- energy efficiencies and technological trends;
- loss of key personnel;
- the availability and cost of capital and our ability to access certain
capital sources;
- changes in laws and regulations to which we are subject, including tax,
environmental, transportation and employment regulations;
- the costs and effects of legal and administrative proceedings; and
- our ability to successfully identify and consummate strategic
acquisitions at purchase prices that are accretive to our financial
results.
These factors are not necessarily all of the important factors that could
cause actual results to differ materially from those expressed in any of our
forward-looking statements. Our future results will depend upon various other
risks and uncertainties, including, but not limited to, those detailed in our
other filings with the SEC. For additional information, please read our other
current filings with the SEC under the Exchange Act and the Securities Act.
Other unknown or unpredictable factors also could have material adverse effects
on our future results. You should not put undue reliance on any future-looking
statements. When considering forward-looking statements, please review the risk
factors described under "Risk Factors" beginning on page 2 of this prospectus.
14
USE OF PROCEEDS
Unless we specify otherwise in any prospectus supplement, we will use the
net proceeds (after the payment of offering expenses and underwriting discounts
and commissions) from the sale of securities for general partnership purposes,
which may include, among other things:
- paying or refinancing all or a portion of our indebtedness outstanding at
the time; and
- funding working capital, capital expenditures or acquisitions.
The actual application of proceeds from the sale of any particular offering
of securities using this prospectus will be described in the applicable
prospectus supplement relating to such offering. The precise amount and timing
of the application of these proceeds will depend upon our funding requirements
and the availability and cost of other funds.
We will not receive any of the proceeds from any sale of common units by
the selling unitholders.
RATIO OF EARNINGS TO FIXED CHARGES
In August 2000, Heritage Propane Partners, L.P. acquired all of the propane
operations of U.S. Propane, L.P., an entity that was formed when TECO Energy,
Inc., AGL Resources, Inc., Piedmont Natural Gas Company, Inc., and Atmos Energy
Corporation contributed each company's propane operations, Peoples Gas Company,
AGL Propane, Inc., Piedmont Propane Company, and United Cities Propane Gas,
Inc., respectively, to U.S. Propane, L.P. in exchange for equity interests in
U.S. Propane, L.P. Simultaneously with the transaction, U.S. Propane, L.P.
acquired all of the outstanding common stock of our former general partner,
Heritage Holdings, Inc., thereby acquiring control of us. The transaction was
accounted for as an acquisition using the purchase method of accounting with
Peoples Gas Company being treated as the acquiror for accounting purposes as a
result of Peoples Gas Company being the acquiror in the transaction that formed
U.S. Propane, L.P. However, Heritage Propane Partners, L.P. is the surviving
entity for legal purposes.
Because the fiscal year of Heritage Propane Partners, L.P. ended on August
31 and Peoples Gas Company had a fiscal year-end of December 31, the eight-month
period ended August 31, 2000 was treated as a transition period under the rules
of the Securities and Exchange Commission and is presented separately below.
However, we continue to have an August 31 fiscal year-end.
The table below sets forth the ratio of earnings to fixed charges of
Heritage Propane Partners, L.P. and subsidiaries on a consolidated basis for the
periods indicated. The ratio of earnings to fixed charges presented below for
the years ending December 31, 1997, 1998 and 1999 includes information with
respect to Heritage Propane Partners, L.P. (formerly Peoples Gas). The ratio of
earnings to fixed charges presented below for the eight months ended August 31,
2000 includes information with respect to Heritage Propane Partners, L.P.
(formerly Peoples Gas), and beginning August 10, 2000 the propane operations of
U.S. Propane, L.P. and Heritage Propane Partners, L.P. (Predecessor Heritage).
RATIO OF EARNINGS TO FIXED CHARGES (FORMERLY PEOPLES GAS):
<Table>
<Caption>
EIGHT
MONTHS
ENDED
YEAR ENDED DECEMBER 31, AUGUST 31, YEAR ENDED AUGUST 31,
-------------------------- ---------- ---------------------
1997 1998 1999 2000 2001 2002 2003
------ ------- ------- ---------- ----- ----- -----
Ratio of Earnings to Fixed Charges..................... 76.38x 436.37x 242.25x (A) 1.53x 1.12x 1.88x
</Table>
- ---------------
(A) Earnings for the eight months ended August 31, 2000, were insufficient to
cover fixed charges by $3.5 million.
15
The table below sets forth the ratio of earnings to fixed charges of
Heritage Propane Partners, L.P. and subsidiaries (Predecessor Heritage) on a
consolidated basis for the periods indicated and does not include information
with respect to Peoples Gas or the propane operations of U.S. Propane, L.P.
during those periods (which were prior to the acquisition of U.S. Propane, L.P.,
by Heritage Propane Partners, L.P.).
RATIO OF EARNINGS TO FIXED CHARGES (PREDECESSOR HERITAGE):
<Table>
<Caption>
PERIOD
YEAR ENDED ENDED
AUGUST 31, AUGUST 9,
------------- ---------
1998 1999 2000
----- ----- ---------
Ratio of Earnings to Fixed Charges.......................... 1.57x 1.58x 1.35x
</Table>
For these ratios, "earnings" is the amount resulting from adding the
following items:
- pre-tax income from continuing operations, before minority interest and
equity in earnings of affiliates;
- distributed income of equity investees; and
- fixed charges.
The term "fixed charges" means the sum of the following:
- interest expensed;
- amortized debt issuance costs; and
- estimated interest element of rentals.
16
DESCRIPTION OF THE COMMON UNITS
Our common units represent limited partner interests that entitle the
holders to participate in our cash distributions and to exercise the rights and
privileges available to limited partners under our partnership agreement. For a
description of the relative rights and preferences of holders of common units
and our general partner in and to cash distributions, see "Cash Distribution
Policy." For a general discussion of the expected federal income tax
consequences of owning and disposing of common units, see "Material Tax
Considerations." References in this "Description of the Common Units" to "we,"
"us" and "our" mean Heritage Propane Partners, L.P.
NUMBER OF UNITS
As of November 21, 2003, we have 18,028,029 common units outstanding, of
which 11,349,748 are held by the public, 4,606,944 are held by our general
partner or its affiliates, and 2,071,337 are held by our officers and directors.
The common units represent an aggregate 98.0% limited partner interest. Our
general partner owns an aggregate 2.0% general partner interest in Heritage
Propane Partners, L.P.
Our common units represent limited partner interests in us and entitle the
holders thereof to participate in distributions and exercise the rights and
privileges available to our limited partners under our partnership agreement. A
copy of the partnership agreement of Heritage Propane Partners, L.P. is filed as
an exhibit to this registration statement of which this prospectus is a part.
ISSUANCE OF ADDITIONAL SECURITIES
Our partnership agreement authorizes us to issue an unlimited number of
additional partnership securities and rights to buy partnership securities for
the consideration and on the terms and conditions established by our general
partner in its sole discretion, without the approval of the unitholders. Any
such additional partnership securities may be senior to the common units.
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 distributions of available cash. 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 securities that, in the sole
discretion of the general partner, have special voting rights to which the
common units are not entitled.
Upon issuance of additional partnership securities, our general partner
will be required to make additional capital contributions to the extent
necessary to maintain its 2.0% general partner interest in us. Moreover, our
general partner will have the right, which it may from time to time assign in
whole or in part to any of its affiliates, to purchase common units or other
equity securities whenever, and on the same terms that, we issue those
securities to persons other than the general partner and its affiliates, to the
extent necessary to maintain its percentage interest, including its interest
represented by common units, that existed immediately prior to each issuance.
The holders of common units will not have preemptive rights to acquire
additional common units or other partnership securities.
The following matters require the approval of the majority of the
outstanding common units, including the common units owned by the general
partner and its affiliates:
- a merger of our partnership;
- a sale or exchange of all or substantially all of our assets;
- dissolution or reconstitution of our partnership upon dissolution;
- certain amendments to the partnership agreement;
17
- the transfer to another person of our general partner interest before
June 30, 2006 or the incentive distribution rights at any time, except
for transfers to affiliates of the general partner or transfers in
connection with the general partner's merger or consolidation with or
into, or sale of all or substantially all of its assets to, another
person; and
- the withdrawal of the general partner prior to June 30, 2006 in a manner
that would cause the dissolution of our partnership.
The removal of our general partner requires the approval of not less than
66 2/3% of all outstanding units, including units held by our general partner
and its affiliates. Any removal is subject to the election of a successor
general partner by the holders of a majority of the outstanding common units,
including units held by our general partner and its affiliates.
AMENDMENTS TO OUR PARTNERSHIP AGREEMENT
Amendments to our partnership agreement may be proposed only by our general
partner. Certain amendments require the approval of a majority of the
outstanding common units, including common units owned by the general partner
and its affiliates. Any amendment that materially and adversely affects the
rights or preferences of any class of partnership interests in relation to other
classes of partnership interests will require the approval of at least a
majority of the class of partnership interests so affected. Our general partner
may make amendments to the partnership agreement without unitholder approval to
reflect:
- a change in our name, the location of our principal place of business or
our registered agent or office;
- the admission, substitution, withdrawal or removal of partners;
- a change to qualify or continue our qualification as a limited
partnership or a partnership in which the limited partners have limited
liability or to ensure that neither we nor our operating partnership will
be treated as an association taxable as a corporation or otherwise taxed
as an entity for federal income tax purposes;
- a change that does not affect our unitholders in any material respect;
- a change to (i) satisfy any requirements, conditions or guidelines
contained in any opinion, directive, order, ruling or regulation of any
federal or state agency or judicial authority or contained in any federal
or state statute, (ii) facilitate the trading of common units or comply
with any rule, regulation, guideline or requirement of any national
securities exchange on which the common units are or will be listed for
trading, (iii) that is necessary or advisable in connection with action
taken by our general partner with respect to subdivision and combination
of our securities or (iv) that is required to effect the intent expressed
in our partnership agreement;
- a change in our fiscal year or taxable year and any changes that are
necessary or advisable as a result of a change in our fiscal year or
taxable year;
- an amendment that is necessary to prevent us, or our general partner or
its directors, officers, trustees or agents from being subjected to the
provisions of the Investment Company Act of 1940, as amended, the
Investment Advisors Act of 1940, as amended, or "plan asset" regulations
adopted under the Employee Retirement Income Security Act of 1974, as
amended;
- an amendment that is necessary or advisable in connection with the
authorization or issuance of any class or series of our securities;
- any amendment expressly permitted in our partnership agreement to be made
by our general partner acting alone;
- an amendment effected, necessitated or contemplated by a merger agreement
approved in accordance with our partnership agreement;
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- an amendment that is necessary or advisable to reflect, account for and
deal with appropriately our formation of, or investment in, any
corporation, partnership, joint venture, limited liability company or
other entity other than our operating partnership, in connection with our
conduct of activities permitted by our partnership agreement;
- a merger or conveyance to effect a change in our legal form; or
- any other amendment substantially similar to the foregoing.
WITHDRAWAL OR REMOVAL OF OUR GENERAL PARTNER
Our general partner has agreed not to withdraw voluntarily as our general
partner prior to June 30, 2006 without obtaining the approval of the holders of
a majority of our outstanding common units, excluding those held by our general
partner and its affiliates, and furnishing an opinion of counsel stating that
such withdrawal (following the selection of the successor general partner) would
not result in the loss of the limited liability of any of our limited partners
or of the limited partner of our operating partnership or cause us or our
operating partnership to be treated as an association taxable as a corporation
or otherwise to be taxed as an entity for federal income tax purposes (to the
extent not previously treated as such).
On or after June 30, 2006, 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.
Upon the voluntary withdrawal of our general partner, the holders of a
majority of our outstanding common units, excluding the common units held by the
withdrawing general partner and its affiliates, may elect a successor to the
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 90 days
after that withdrawal, the holders of a majority of our outstanding units,
excluding the common units held by the withdrawing general partner and its
affiliates, agree 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,
including 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 the majority of our outstanding common units,
including those held by our general partner and its affiliates.
While our partnership agreement limits the ability of our general partner
to withdraw, it allows the general partner interest to be transferred to an
affiliate or to a third party in conjunction with a merger or sale of all or
substantially all of the assets of our general partner. In addition, our
partnership agreement expressly permits the sale, in whole or in part, of the
ownership of our general partner. Our general partner may also transfer, in
whole or in part, any common units it owns.
LIQUIDATION AND DISTRIBUTION OF PROCEEDS
Upon our dissolution, unless we are reconstituted and continue 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:
- first, towards the payment of all of our creditors and the creation of a
reserve for contingent liabilities; and
- then, to all partners in accordance with the positive balance in their
respective capital accounts.
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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 a loss to our partners, our general partner may distribute assets in kind
to our partners.
LIMITED CALL RIGHT
If at any time less than 20% of the outstanding common units of any class
are held by persons other than our general partner and its affiliates, our
general partner will have the right to acquire all, but not less than all, of
those common units at a price no less than their then-current market price. As a
consequence, a unitholder may be required to sell his common units at an
undesirable time or price. Our general partner may assign this purchase right to
any of its affiliates or us.
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 effectuate any 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.
LISTING
Our outstanding common units are listed on the New York Stock Exchange
(NYSE) under the symbol "HPG." Any additional common units we issue also will be
listed on the NYSE.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the common units is American Stock
Transfer & Trust Company.
TRANSFER OF COMMON UNITS
Each purchaser of common units offered by this prospectus must execute a
transfer application. By executing and delivering a transfer application, the
purchaser of common units:
- becomes the record holder of the common units and is an assignee until
admitted into our partnership as a substituted limited partner;
- automatically requests admission as a substituted limited partner in our
partnership;
- agrees to be bound by the terms and conditions of, and executes, our
partnership agreement;
- represents that such person has the capacity, power and authority to
enter into the partnership agreement;
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- grants to our general partner the power of attorney to execute and file
documents required for our existence and qualification as a limited
partnership, the amendment of the partnership agreement, our dissolution
and liquidation, the admission, withdrawal, removal or substitution of
partners, the issuance of additional partnership securities and any
merger or consolidation of the partnership.
- makes the consents and waivers contained in the partnership agreement,
including the waiver of the fiduciary duties of the general partner to
unitholders as described in "Risk Factors -- Risks Inherent in an
Investment in Us -- Our partnership agreement limits our general
partner's fiduciary duties to our unitholders and restricts the remedies
available to unitholders for actions taken by our general partner that
might otherwise constitute breaches of fiduciary duty."
An assignee will become a substituted limited partner of our partnership
for the transferred common units upon the consent of our general partner and the
recording of the name of the assignee on our books and records. Although the
general partner has no current intention of doing so, it may withhold its
consent in its sole discretion. An assignee who is not admitted as a limited
partner will remain an assignee. An assignee is entitled to an interest
equivalent to that of a limited partner for the right to share in allocations
and distributions from us, including liquidating distributions. Furthermore, our
general partner will vote and exercise other powers attributable to common units
owned by an assignee at the written direction of the assignee.
Transfer applications may be completed, executed and delivered by a
purchaser's broker, agent or nominee. We are entitled to treat the nominee
holder of a common unit as the absolute owner. In that case, the beneficial
holders' rights are limited solely to those that it has against the nominee
holder as a result of any agreement between the beneficial owner and the nominee
holder.
Common units are securities and are transferable according to the laws
governing transfer of securities. In addition to other rights acquired, the
purchaser has the right to request admission as a substituted limited partner in
our partnership for the purchased common units. A purchaser of common units who
does not execute and deliver a transfer application obtains only:
- the right to assign the common unit to a purchaser or transferee; and
- the right to transfer the right to seek admission as a substituted
limited partner in our partnership for the purchased common units.
Thus, a purchaser of common units who does not execute and deliver a
transfer application:
- will not receive cash distributions or federal income tax allocations,
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; and
- may not receive some federal income tax information or reports furnished
to record holders of common units.
Until a common unit has been transferred on our books, we and the transfer
agent, notwithstanding any notice to the contrary, may treat the record holder
of the unit as the absolute owner for all purposes, except as otherwise required
by law or NYSE regulations.
STATUS AS LIMITED PARTNER OR ASSIGNEE
Except as described under "-- Limited Liability," the common units will be
fully paid, and the unitholders will not be required to make additional capital
contributions to us.
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 possible exceptions, to the amount of capital he is
obligated to contribute to us
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for his common units plus his share of any undistributed profits and assets. If
it were determined, however, that the right or exercise of the right by the
limited partners as a group:
- to remove or replace the general partner;
- to approve some amendments to our partnership agreement; or
- to take other action under our partnership agreement;
constituted "participation in the control" of our business for the purposes of
the Delaware Act, then the limited partners could be held personally liable for
our obligations under Delaware law, to the same extent as the general partner.
This liability would extend to persons who transact business with us and who
reasonably believe that the limited partner is a general partner. Neither our
partnership agreement nor the Delaware Act specifically provides for legal
recourse against our general partner if a limited partner were to lose limited
liability through any fault of the general partner. While this does not mean
that a limited partner could not seek legal recourse, we have found no precedent
for this type of a claim in Delaware case law.
Under the Delaware Act, a limited partnership may not make a distribution
to a partner if after the distribution all liabilities of the limited
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 our partnership, exceed the fair value of the assets of the
limited partnership. For the purpose of determining the fair value of the assets
of a limited partnership, the Delaware Act provides that the fair value of
property subject to liability for 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
shall be liable to the limited partnership for the amount of the distribution
for three years. Under the Delaware Act, an assignee who becomes a substituted
limited partner of a limited partnership is liable for the obligations of his
assignor to make contributions to our partnership, except the assignee is not
obligated for liabilities unknown to him at the time he became a limited partner
and which could not be ascertained from our partnership agreement.
Our subsidiaries currently conduct business in 29 states: Alabama, Arizona,
California, Colorado, Delaware, Florida, Georgia, Idaho, Kentucky,
Massachusetts, Michigan, Minnesota, Montana, Nevada, New Hampshire, New Jersey,
New Mexico, New York, North Carolina, Oregon, Pennsylvania, South Carolina,
Tennessee, Texas, Utah, Vermont, Virginia, Washington and Wyoming. To maintain
the limited liability for Heritage Propane Partners, L.P., as the holder of a
98.9899% limited partner interest in Heritage Operating, L.P., we may be
required to comply with legal requirements in the jurisdictions in which
Heritage Operating, L.P. conducts business, including qualifying our
subsidiaries to do business there. Limitations on the liability of limited
partners for the obligations of a limited partnership have not been clearly
established in many jurisdictions. If it were determined that we were, by virtue
of our limited partner interest in Heritage Operating, L.P. or otherwise,
conducting business in any state without compliance with the applicable limited
partnership statute, or that our right or the exercise of our right to remove or
replace Heritage Operating, L.P.'s general partner, to approve some amendments
to Heritage Operating, L.P.'s partnership agreement, or to take other action
under Heritage Operating, L.P.'s partnership agreement constituted
"participation in the control" of Heritage Operating, L.P.'s business for
purposes of the statutes of any relevant jurisdiction, then we could be held
personally liable for Heritage Operating, L.P.'s obligations under the law of
that jurisdiction to the same extent as our general partner under the
circumstances. We will operate in a manner as our general partner considers
reasonable and necessary or appropriate to preserve our limited liability.
MEETINGS; VOTING
Except as described below regarding a person or group owning 20% or more of
any class of units then outstanding, unitholders or assignees who are record
holders of units on the record date will be entitled to notice of, and to vote
at, meetings of our limited partners and to act upon matters for which approvals
may
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be solicited. Common units that are owned by an assignee who is a record holder,
but who has not yet been admitted as a limited partner, shall be voted by our
general partner at the written direction of the record holder. Absent direction
of this kind, the common units will not be voted, except that, in the case of
common units held by our general partner on behalf of non-citizen assignees, our
general partner shall distribute the votes on those common units in the same
ratios as the votes of limited partners on other units are cast.
Our general partner does not anticipate that any meeting of unitholders
will be called in the foreseeable future. Any action that is required or
permitted to be taken by the unitholders may be taken either at a meeting of the
unitholders or without a meeting if consents in writing describing the action so
taken are signed by holders of the number of units as would be necessary to
authorize or take that action at a meeting. Meetings of the unitholders may be
called by our general partner or by unitholders owning at least 20% of the
outstanding units of the class for which a meeting is proposed. Unitholders may
vote either in person or by proxy at meetings. The holders of a majority of the
outstanding units of the class or classes for which a meeting has been called
represented in person or by proxy shall constitute a quorum unless any action by
the unitholders requires approval by holders of a greater percentage of the
units, in which case the quorum shall be the greater percentage.
Each record holder of a unit has a vote according to his percentage
interest in us, although additional limited partner interests having special
voting rights could be issued. However, if at any time any person or group,
other than our general partner and its affiliates, owns, in the aggregate,
beneficial ownership of 20% or more of the common units then outstanding, the
person or group will lose voting rights on all of its common units and its
common units may not be voted on any matter and will not be considered to be
outstanding when sending notices of a meeting of unitholders, calculating
required votes, determining the presence of a quorum or for other similar
purposes. Common units held in nominee or street name account will be voted by
the broker or other nominee in accordance with the instruction of the beneficial
owner unless the arrangement between the beneficial owner and his nominee
provides otherwise.
Any notice, demand, request, report or proxy material required or permitted
to be given or made to record holders of common units under our partnership
agreement will be delivered to the record holder by us or by the transfer agent.
BOOKS AND REPORTS
Our general partner is required to keep appropriate books of our business
at our principal offices. The books will be maintained for both tax and
financial reporting purposes on an accrual basis. Reporting for tax purposes is
done on a calendar year basis.
We will furnish or make available to record holders of common units, within
120 days after the close of each fiscal year, an annual report containing
audited financial statements and a report on those financial statements by our
independent public accountants. Except for our fourth quarter, we will also
furnish or make available summary financial information within 90 days after the
close of each quarter.
We will furnish each record holder of a unit with information reasonably
required for tax reporting purposes within 90 days after the close of each
calendar year. This information is expected to be furnished in summary form so
that some complex calculations normally required of partners can be avoided. Our
ability to furnish this summary information to unitholders will depend on the
cooperation of unitholders in supplying us with specific information. Every
unitholder will receive information to assist him in determining his federal and
state tax liability and filing his federal and state income tax returns,
regardless of whether he supplies us with information.
Our partnership agreement provides that a limited partner can, for a
purpose reasonably related to his 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;
23
- 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, the certificate of limited
partnership of the partnership, related amendments and powers of attorney
under which they have been executed;
- 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 interests or that we are
required by law or by agreements with third parties to keep confidential.
CASH DISTRIBUTION POLICY
DISTRIBUTIONS OF AVAILABLE CASH
References in this "Cash Distribution Policy" to "we," "us" and "our" mean
Heritage Propane Partners, L.P.
General. We will distribute all of our "available cash" to our unitholders
and our general partner within 45 days following the end of each fiscal quarter.
Definition of Available Cash. Available cash is defined in our partnership
agreement and generally means, with respect to any calendar quarter, all cash on
hand at the end of such quarter:
- less the amount of cash reserves that are necessary or appropriate in the
reasonable discretion of the general partner to:
- provide for the proper conduct of our business;
- comply with applicable law or any debt instrument or other agreement
(including reserves for future capital expenditures and for our future
credit needs); or
- provide funds for distributions to unitholders and our general partner
in respect of any one or more of the next four quarters;
- plus all cash on hand on the date of determination of available cash for
the quarter resulting from working capital borrowings made after the end
of the quarter. Working capital borrowings are generally borrowings that
are made under our credit facilities and in all cases are used solely for
working capital purposes or to pay distributions to partners.
OPERATING SURPLUS AND CAPITAL SURPLUS
General. All cash distributed to unitholders will be characterized as
either "operating surplus" or "capital surplus." We distribute available cash
from operating surplus differently than available cash from capital surplus.
Definition of Operating Surplus. Operating surplus for any period
generally means:
- our cash balance on the closing date of our initial public offering; plus
- $10.0 million (as described below); plus
- all of our cash receipts since the closing of our initial public
offering, excluding cash from interim capital transactions such as
borrowings that are not working capital borrowings, sales of equity and
debt securities and sales or other dispositions of assets outside the
ordinary course of business; plus
- working capital borrowings made after the end of a quarter but before the
date of determination of operating surplus for the quarter; less
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- all of our operating expenditures after the closing of our initial public
offering, including the repayment of working capital borrowings, but not
the repayment of other borrowings, and including maintenance capital
expenditures; less
- the amount of cash reserves that the general partner deems necessary or
advisable to provide funds for future operating expenditures.
Definition of Capital Surplus. Generally, capital surplus will be
generated only by:
- borrowings other than working capital borrowings;
- sales of debt and equity securities; and
- sales or other disposition of assets for cash, other than inventory,
accounts receivable and other current assets sold in the ordinary course
of business or as part of normal retirements or replacements of assets.
Characterization of Cash Distributions. We will treat all available cash
distributed as coming from operating surplus until the sum of all available cash
distributed since we began operations equals the operating surplus as of the
most recent date of determination of available cash. We will treat any amount
distributed in excess of operating surplus, regardless of its source, as capital
surplus. As reflected above, operating surplus includes $10.0 million in
addition to our cash balance on the closing date of our initial public offering,
cash receipts from our operations and cash from working capital borrowings. This
amount does not reflect actual cash on hand that is available for distribution
to our unitholders. Rather, it is a provision that will enable us, if we choose,
to distribute as operating surplus up to $10.0 million of cash we receive in the
future from non-operating sources, such as asset sales, issuances of securities,
and long-term borrowings, that would otherwise be distributed as capital
surplus. We have not made, and we anticipate that we will not make, any
distributions from capital surplus.
INCENTIVE DISTRIBUTION RIGHTS
Incentive distribution rights represent the contractual right to receive an
increasing percentage of quarterly distributions of available cash from
operating surplus after the minimum quarterly distribution has been paid. Please
read "-- Distributions of Available Cash from Operating Surplus" below. The
general partner owns all of the incentive distribution rights, except that in
conjunction with the August 2000 transaction with U.S. Propane, L.P., we issued
1,000,000 class C units to Heritage Holdings, Inc., our general partner at that
time, in conversion of that portion of Heritage Holdings, Inc.'s incentive
distribution rights that entitled it to receive any distribution made by us of
funds attributable to the net amount received by us in connection with the
settlement, judgment, award or other final nonappealable resolution of the
litigation filed by us against SCANA Corporation, Cornerstone Ventures, L.P. and
Suburban Propane, L.P. Any amount payable on the class C units in the future
will reduce the amount otherwise distributable to holders of incentive
distribution rights at the time the distribution of such litigation proceeds is
made and will not reduce the amount distributable to holders of common units. No
payments to date have been made on the class C units.
DISTRIBUTIONS OF AVAILABLE CASH FROM OPERATING SURPLUS
We will make distributions of available cash from operating surplus for any
quarter in the following manner:
- First, 98% to all unitholders, pro rata, and 2% to the general partner,
until all unitholders have received $0.50 per unit for such quarter (the
"minimum quarterly distribution");
- Second, 98% to all unitholders, pro rata, and 2% to the general partner,
until all unitholders have received $0.55 per unit for such quarter (the
"first target distribution");
- Third, 85% to all unitholders, pro rata, 13% to the holders of incentive
distribution rights, pro rata, and 2% to the general partner, until all
unitholders have received $0.635 per unit for such quarter (the "second
target distribution");
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- Fourth, 75% to all unitholders, pro rata, 23% to the holders of incentive
distribution rights, pro rata, and 2% to the general partner, until all
unitholders have received $0.825 per unit for such quarter (the "third
target distribution"); and
- Fifth, thereafter, 50% to all unitholders, pro rata, 48% to the holders
of incentive distribution rights, pro rata, and 2% to the general
partner.
DISTRIBUTIONS OF AVAILABLE CASH FROM CAPITAL SURPLUS
We will make distributions of available cash from capital surplus, if any,
in the following manner:
- First, 98% to all unitholders, pro rata, and 2% to the general partner,
until we distribute for each common unit, an amount of available cash
from capital surplus equal to the initial public offering price;
- Thereafter, we will make all distributions of available cash from capital
surplus as if they were from operating surplus.
Our partnership agreement treats a distribution of capital surplus as the
repayment of the initial unit price from the initial public offering, which is a
return of capital. The initial public offering price less any distributions of
capital surplus per unit is referred to as the "unrecovered capital." Each time
a distribution of capital surplus is made, the minimum quarterly distribution
and the target distribution levels will be reduced in the same proportion as the
corresponding reduction in the unrecovered capital. Because distributions of
capital surplus will reduce the minimum quarterly distribution, after any of
these distributions are made, it may be easier for the general partner to
receive incentive distributions. However, any distribution of capital surplus
before the unrecovered capital is reduced to zero cannot be applied to the
payment of the minimum quarterly distribution.
Once we distribute capital surplus on a unit in an amount equal to the
initial unit price, we will reduce the minimum quarterly distribution and the
target distribution levels to zero. We will then make all future distributions
from operating surplus, with 50% being paid to the holders of units, 48% to the
holders of the incentive distribution rights and 2% to the general partner.
ADJUSTMENT TO THE MINIMUM QUARTERLY DISTRIBUTION AND TARGET DISTRIBUTION LEVELS
In addition to adjusting the minimum quarterly distribution and target
distribution levels to reflect a distribution of capital surplus, if we combine
our units into fewer units or subdivide our units into a greater number of
units, we will proportionately adjust:
- the minimum quarterly distribution;
- the target distribution levels; and
- unrecovered capital.
For example, if a two-for-one split of the common units should occur, the
minimum quarterly distribution, the target distribution levels and the
unrecovered capital would each be reduced to 50% of its initial level. We will
not make any adjustment by reason of the issuance of additional units for cash
or property.
In addition, if legislation is enacted or if existing law is modified or
interpreted in a manner that causes us to become taxable as a corporation or
otherwise subject to taxation as an entity for federal, state or local income
tax purposes, we will reduce the minimum quarterly distribution and the target
distribution levels by multiplying the same by one minus the sum of the highest
marginal federal corporate income tax rate that could apply and any increase in
the effective overall state and local income tax rates.
DISTRIBUTIONS OF CASH UPON LIQUIDATION
General. If we dissolve in accordance with our partnership agreement, we
will sell or otherwise dispose of our assets in a process called liquidation. We
will first apply the proceeds of liquidation to the
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payment of our creditors. We will distribute any remaining proceeds to the
unitholders and the general partner, in accordance with their capital account
balances, as adjusted to reflect any gain or loss upon the sale or other
disposition of our assets in liquidation.
Any further net gain recognized upon liquidation will be allocated in a
manner that takes into account the incentive distribution rights of the general
partner.
Manner of Adjustments for Gain. The manner of the adjustment for gain is
set forth in our partnership agreement in the following manner:
- First, to the general partner and the holders of units who have negative
balances in their capital accounts to the extent of and in proportion to
those negative balances;
- Second, 98% to the common unitholders, pro rata, and 2% to the general
partner, until the capital account for each common unit is equal to the
sum of:
- the unrecovered capital; and
- the amount of the minimum quarterly distribution for the quarter during
which our liquidation occurs;
- Third, 98% to all unitholders, pro rata, and 2% to the general partner,
until we allocate under this paragraph an amount per unit equal to:
- the sum of the excess of the first target distribution per unit over the
minimum quarterly distribution per unit for each quarter of our
existence; less
- the cumulative amount per unit of any distributions of available cash
from operating surplus in excess of the minimum quarterly distribution
per unit that we distributed 98% to the unitholders, pro rata, and 2% to
the general partner, for each quarter of our existence;
- Fourth, 85% to all unitholders, pro rata, 13% to the holders of the
incentive distribution rights, pro rata, and 2% to the general partner,
until we allocate under this paragraph an amount per unit equal to:
- the sum of the excess of the second target distribution per unit over
the first target distribution per unit for each quarter of our
existence; less
- the cumulative amount per unit of any distributions of available cash
from operating surplus in excess of the first target distribution per
unit that we distributed 85% to the unitholders, pro rata, 13% to the
holders of the incentive distribution rights, pro rata, and 2% to the
general partner for each quarter of our existence;
- Fifth, 75% to all unitholders, pro rata, 23% to the holders of the
incentive distribution rights, pro rata, and 2% to the general partner,
until we allocate under this paragraph an amount per unit equal to:
- the sum of the excess of the third target distribution per unit over the
second target distribution per unit for each quarter of our existence;
less
- the cumulative amount per unit of any distributions of available cash
from operating surplus in excess of the second target distribution per
unit that we distributed 75% to the unitholders, pro rata, 23% to the
holders of the incentive distribution rights, pro rata, and 2% to the
general partner for each quarter of our existence; and
- Sixth, thereafter, 50% to all unitholders, pro rata, 48% to the holders
of the incentive distribution rights, pro rata, and 2% to the general
partner.
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Manner of Adjustments for Losses. Upon our liquidation, we will generally
allocate any loss to the general partner and the unitholders in the following
manner:
- First, 98% to the holders of common units in proportion to the positive
balances in their capital accounts and 2% to the general partner, until
the capital accounts of the common unitholders have been reduced to zero;
and
- Second, thereafter, 100% to the general partner.
Adjustments to Capital Accounts upon the Issuance of Additional Units. We
will make adjustments to capital accounts upon the issuance of additional units.
In doing so, we will allocate any unrealized and, for tax purposes, unrecognized
gain or loss resulting from the adjustments to the unitholders and the general
partner in the same manner as we allocate gain or loss upon liquidation. In the
event that we make positive adjustments to the capital accounts upon the
issuance of additional units, we will allocate any later negative adjustments to
the capital accounts resulting from the issuance of additional units or upon our
liquidation in a manner which results, to the extent possible, in the general
partner's capital account balances equaling the amount which they would have
been if no earlier positive adjustments to the capital accounts had been made.
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DESCRIPTION OF THE DEBT SECURITIES
Heritage Propane Partners, L.P. may issue senior debt securities on a
senior unsecured basis under an indenture among Heritage Propane Partners, L.P.,
as issuer, the Subsidiary Guarantors, if any, and a trustee that we will name in
the related prospectus supplement. We refer to this indenture as the Heritage
Propane senior indenture. Heritage Propane Partners, L.P. may also issue
subordinated debt securities under an indenture to be entered into among
Heritage Propane Partners, L.P., the Subsidiary Guarantors, if any, and the
trustee. We refer to this indenture as the Heritage Propane subordinated
indenture.
Heritage Operating, L.P. may issue senior debt securities on a senior
unsecured basis under an indenture among Heritage Operating, L.P., as issuer,
Heritage Propane Partners, L.P., as Guarantor, the Subsidiary Guarantors, if
any, and a trustee that we will name in the related prospectus supplement. We
refer to this indenture as the Heritage Operating senior indenture. Heritage
Operating, L.P. may also issue subordinated debt securities under an indenture
to be entered into among Heritage Operating, L.P., the Guarantor, the Subsidiary
Guarantors, if any, and the trustee. We refer to this indenture as the Heritage
Operating subordinated indenture.
We refer to the Heritage Propane senior indenture, the Heritage Operating
senior indenture, the Heritage Propane subordinated indenture and the Heritage
Operating subordinated indenture collectively as the indentures. The debt
securities will be governed by the provisions of the related indenture and those
made part of the indenture by reference to the Trust Indenture Act.
We have summarized material provisions of the indentures, the debt
securities and the guarantees below. This summary is not complete. We have filed
the form of senior indentures and the form of subordinated indentures with the
SEC as exhibits to the registration statement, and you should read the
indentures for provisions that may be important to you.
References in this "Description of the Debt Securities" to "we," "us" and
"our" mean Heritage Propane Partners, L.P. and Heritage Operating, L.P.
References in this prospectus to an "indenture" refer to the particular
indenture under which we issue a series of debt securities.
PROVISIONS APPLICABLE TO EACH INDENTURE
General. Any series of debt securities:
- will be general obligations of the issuer;
- will be general obligations of the Guarantor if they are guaranteed by
the Guarantor;
- will be general obligations of the Subsidiary Guarantors if they are
guaranteed by the Subsidiary Guarantors; and
- may be subordinated to the Senior Indebtedness of Heritage Propane
Partners, L.P., Heritage Operating, L.P. and the Subsidiary Guarantors.
The indentures do not limit the amount of debt securities that may be
issued under any indenture, and do not limit the amount of other unsecured debt
or securities that we may issue. We may issue debt securities under the
indentures from time to time in one or more series, each in an amount authorized
prior to issuance.
No indenture contains any covenants or other provisions designed to protect
holders of the debt securities in the event we participate in a highly leveraged
transaction or upon a change of control. The indentures also do not contain
provisions that give holders the right to require us to repurchase their
securities in the event of a decline in our credit ratings for any reason,
including as a result of a takeover, recapitalization or similar restructuring
or otherwise.
Terms. We will prepare a prospectus supplement and either a supplemental
indenture, or authorizing resolutions of the board of directors of our general
partner's general partner, accompanied by an officers'
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certificate, relating to any series of debt securities that we offer, which will
include specific terms relating to some or all of the following:
- whether the debt securities will be senior or subordinated debt
securities;
- the form and title of the debt securities of that series;
- the total principal amount of the debt securities of that series;
- whether the debt securities will be issued in individual certificates to
each holder or in the form of temporary or permanent global securities
held by a depositary on behalf of holders;
- the date or dates on which the principal of and any premium on the debt
securities of that series will be payable;
- any interest rate which the debt securities of that series will bear, the
date from which interest will accrue, interest payment dates and record
dates for interest payments;
- any right to extend or defer the interest payment periods and the
duration of the extension;
- whether and under what circumstances any additional amounts with respect
to the debt securities will be payable;
- whether debt securities are entitled to the benefits of any guarantee of
any Subsidiary Guarantor;
- the place or places where payments on the debt securities of that series
will be payable;
- any provisions for optional redemption or early repayment;
- any provisions that would require the redemption, purchase or repayment
of debt securities;
- the denominations in which the debt securities will be issued;
- whether payments on the debt securities will be payable in foreign
currency or currency units or another form and whether payments will be
payable by reference to any index or formula;
- the portion of the principal amount of debt securities that will be
payable if the maturity is accelerated, if other than the entire
principal amount;
- any additional means of defeasance of the debt securities, any additional
conditions or limitations to defeasance of the debt securities or any
changes to those conditions or limitations;
- any changes or additions to the events of default or covenants described
in this prospectus;
- any restrictions or other provisions relating to the transfer or exchange
of debt securities;
- any terms for the conversion or exchange of the debt securities for our
other securities or securities of any other entity;
- any changes to the subordination provisions for the subordinated debt
securities; and
- any other terms of the debt securities of that series.
This description of debt securities will be deemed modified, amended or
supplemented by any description of any series of debt securities set forth in a
prospectus supplement related to that series.
We may sell the debt securities at a discount, which may be substantial,
below their stated principal amount. These debt securities may bear no interest
or interest at a rate that at the time of issuance is below market rates. If we
sell these debt securities, we will describe in the prospectus supplement any
material United States federal income tax consequences and other special
considerations.
If we sell any of the debt securities for any foreign currency or currency
unit or if payments on the debt securities are payable in any foreign currency
or currency unit, we will describe in the prospectus supplement the
restrictions, elections, tax consequences, specific terms and other information
relating to those debt securities and the foreign currency or currency unit.
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Guarantee of Heritage Propane Partners, L.P. Heritage Propane Partners,
L.P. will fully, irrevocably and unconditionally guarantee on an unsecured basis
all series of debt securities of Heritage Operating, L.P., and will execute a
notation of guarantee as further evidence of its guarantee. As used in this
prospectus, the term "Guarantor" means Heritage Propane Partners, L.P. in its
role as guarantor of the debt securities of Heritage Operating, L.P. The
applicable prospectus supplement will describe the terms of any guarantee by
Heritage Propane Partners, L.P.
If a series of senior debt securities of Heritage Operating, L.P. is so
guaranteed, Heritage Propane Partners, L.P.'s guarantee of the senior debt
securities will be Heritage Propane Partners, L.P.'s unsecured and
unsubordinated general obligation, and will rank on a parity with all of
Heritage Propane Partners, L.P.'s other unsecured and unsubordinated
indebtedness. If a series of subordinated debt securities of Heritage Operating,
L.P. is so guaranteed, Heritage Propane Partners, L.P.'s guarantee of the
subordinated debt securities will be Heritage Propane Partners, L.P.'s unsecured
general obligation and will be subordinated to all of Heritage Propane Partners,
L.P.'s other unsecured and unsubordinated indebtedness.
The Subsidiary Guarantees. The Subsidiary Guarantors may fully,
irrevocably and unconditionally guarantee on an unsecured basis all series of
debt securities of Heritage Propane Partners, L.P. or Heritage Operating, L.P.,
and will execute a notation of guarantee as further evidence of their guarantee.
The term "Subsidiary Guarantors" means Heritage Service Corp., Heritage-Bi
State, L.L.C. and Heritage Energy Resources, L.L.C. and also includes Heritage
Operating, L.P. when discussing subsidiary guarantees of the debt securities of
Heritage Propane Partners, L.P. The applicable prospectus supplement will
describe the terms of any guarantee by the Subsidiary Guarantors.
If a series of senior debt securities of Heritage Propane Partners, L.P. or
Heritage Operating, L.P. is so guaranteed, the Subsidiary Guarantors' guarantee
of the senior debt securities will be the Subsidiary Guarantors' unsecured and
unsubordinated general obligation, and will rank on a parity with all of the
Subsidiary Guarantors' other unsecured and unsubordinated indebtedness. If a
series of subordinated debt securities of Heritage Propane Partners, L.P. or
Heritage Operating, L.P. is so guaranteed, the Subsidiary Guarantors' guarantee
of the subordinated debt securities will be the Subsidiary Guarantors' unsecured
general obligation and will be subordinated to all of the Subsidiary Guarantors'
other unsecured and unsubordinated indebtedness.
The obligations of each Subsidiary Guarantor under its guarantee of the
debt securities will be limited to the maximum amount that will not result in
the obligations of the Subsidiary Guarantor under the guarantee constituting a
fraudulent conveyance or fraudulent transfer under federal or state law, after
giving effect to:
- all other contingent and fixed liabilities of the Subsidiary Guarantor;
and
- any collections from or payments made by or on behalf of any other
Subsidiary Guarantors in respect of the obligations of the Subsidiary
Guarantor under its guarantee.
The guarantee of any Subsidiary Guarantor may be released under certain
circumstances. If we exercise our legal or covenant defeasance option with
respect to debt securities of a particular series as described below in
"-- Defeasance," then any Subsidiary Guarantor will be released with respect to
that series. Further, if no default has occurred and is continuing under the
indentures, and to the extent not otherwise prohibited by the indentures, a
Subsidiary Guarantor will be unconditionally released and discharged from the
guarantee:
- automatically upon any sale, exchange or transfer, whether by way of
merger or otherwise, to any person that is not our affiliate, of all of
our direct or indirect limited partnership or other equity interests in
the Subsidiary Guarantor;
- automatically upon the merger of the Subsidiary Guarantor into us or any
other Subsidiary Guarantor or the liquidation and dissolution of the
Subsidiary Guarantor; or
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- following delivery of a written notice by us to the trustee, upon the
release of all guarantees by the Subsidiary Guarantor of any debt of ours
for borrowed money for a purchase money obligation or for a guarantee of
either, except for any series of debt securities.
Consolidation, Merger and Sale of Assets. The indentures generally permit
a consolidation or merger involving Heritage Propane Partners, L.P., Heritage
Operating, L.P. or the Subsidiary Guarantors. They also permit Heritage Propane
Partners, L.P., Heritage Operating, L.P. or the Subsidiary Guarantors, as
applicable, to lease, transfer or dispose of all or substantially all of its
assets. Each of Heritage Propane Partners, L.P., Heritage Operating, L.P. and
the Subsidiary Guarantors has agreed, however, that it will not consolidate with
or merge into any entity (other than Heritage Propane Partners, L.P., Heritage
Operating, L.P. or a Subsidiary Guarantor, as applicable) or lease, transfer or
dispose of all or substantially all of its assets to any entity (other than
Heritage Propane Partners, L.P., Heritage Operating, L.P. or a Subsidiary
Guarantor, as applicable) unless:
- it is the continuing entity; or
- if it is not the continuing entity, the resulting entity or transferee is
organized and existing under the laws of any United States jurisdiction
and assumes the performance of its covenants and obligations under the
indentures; and
- in either case, immediately after giving effect to the transaction, no
default or event of default would occur and be continuing or would result
from the transaction.
Upon any such consolidation, merger or asset lease, transfer or disposition
involving Heritage Propane Partners, L.P., Heritage Operating, L.P. or the
Subsidiary Guarantors, the resulting entity or transferee will be substituted
for Heritage Propane Partners, L.P., Heritage Operating, L.P. or the Subsidiary
Guarantors, as applicable, under the applicable indenture and debt securities.
In the case of an asset transfer or disposition other than a lease, Heritage
Propane Partners, L.P. or the Subsidiary Guarantors, as applicable, will be
released from the applicable indenture.
Events of Default. Unless we inform you otherwise in the applicable
prospectus supplement, the following are events of default with respect to a
series of debt securities:
- failure to pay interest on that series of debt securities for 30 days
when due;
- default in the payment of principal of or premium, if any, on any debt
securities of that series when due at its stated maturity, upon
redemption, upon required repurchase or otherwise;
- default in the payment of any sinking fund payment on any debt securities
of that series when due;
- failure by us or, if the series of debt securities is guaranteed by the
Guarantor or any Subsidiary Guarantors, by such Guarantor or Subsidiary
Guarantor, to comply for 60 days after notice with the other agreements
contained in the indentures, any supplement to the indentures or any
board resolution authorizing the issuance of that series;
- failure to comply with any covenant or agreement in that series of debt
securities or the applicable indenture for 60 days after written notice
by the trustee or by the holders of at least 25% in principal amount of
the outstanding debt securities issued under that indenture that are
affected by that failure;
- certain events of bankruptcy, insolvency or reorganization of us or, if
the series of debt securities is guaranteed by the Guarantor or any
Subsidiary Guarantor, of the Guarantor and/or any such Subsidiary
Guarantor;
- if the series of debt securities is guaranteed by the Guarantor and/or
any Subsidiary Guarantor:
- any of the guarantees ceases to be in full force and effect, except as
otherwise provided in the indentures;
- any of the guarantees is declared null and void in a judicial
proceeding; or
32
- the Guarantor or any Subsidiary Guarantor denies or disaffirms its
obligations under the indentures or its guarantee; and
- any other event of default provided for in that series of debt
securities.
A default under one series of debt securities will not necessarily be a
default under another series. The trustee may withhold notice to the holders of
the debt securities of any default or event of default (except in any payment on
the debt securities) if the trustee considers it in the interest of the holders
of the debt securities to do so.
If an event of default for any series of debt securities occurs and is
continuing, the trustee or the holders of at least 25% in principal amount of
the outstanding debt securities of the series affected by the default (or, in
some cases, 25% in principal amount of all debt securities issued under the
applicable indenture that are affected, voting as one class) may declare the
principal of and all accrued and unpaid interest on those debt securities to be
due and payable. If an event of default relating to certain events of
bankruptcy, insolvency or reorganization occurs, the principal of and interest
on all the debt securities issued under the applicable indenture will become
immediately due and payable without any action on the part of the trustee or any
holder. The holders of a majority in principal amount of the outstanding debt
securities of the series affected by the default (or, in some cases, of all debt
securities issued under the applicable indenture that are affected, voting as
one class) may in some cases rescind this accelerated payment requirement.
A holder of a debt security of any series issued under each indenture may
pursue any remedy under that indenture only if:
- the holder gives the trustee written notice of a continuing event of
default for that series;
- the holders of at least 25% in principal amount of the outstanding debt
securities of that series make a written request to the trustee to pursue
the remedy;
- the holders offer to the trustee indemnity satisfactory to the trustee;
- the trustee fails to act for a period of 60 days after receipt of the
request and offer of indemnity; and
- during that 60-day period, the holders of a majority in principal amount
of the debt securities of that series do not give the trustee a direction
inconsistent with the request.
This provision does not, however, affect the right of a holder of a debt
security to sue for enforcement of any overdue payment.
In most cases, holders of a majority in principal amount of the outstanding
debt securities of a series (or of all debt securities issued under the
applicable indenture that are affected, voting as one class) may direct the
time, method and place of:
- conducting any proceeding for any remedy available to the trustee; and
- exercising any trust or power conferred upon the trustee relating to or
arising as a result of an event of default.
Under each of the indentures we are required to file each year with the
trustee a written statement as to their compliance with the covenants contained
in the applicable indenture.
Modification and Waiver. Each indenture may be amended or supplemented if
the holders of a majority in principal amount of the outstanding debt securities
of all series issued under that indenture that are affected by the amendment or
supplement (acting as one class) consent to it. Without the consent of the
holder of each debt security affected, however, no modification may:
- reduce the amount of debt securities whose holders must consent to an
amendment, a supplement or a waiver;
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- reduce the rate of or change the time for payment of interest on the debt
security;
- reduce the principal of the debt security or change its stated maturity;
- reduce any premium payable on the redemption of the debt security or
change the time at which the debt security may or must be redeemed;
- change any obligation to pay additional amounts on the debt security;
- make payments on the debt security payable in currency other than as
originally stated in the debt security;
- impair the holder's right to institute suit for the enforcement of any
payment on or with respect to the debt security;
- make any change in the percentage of principal amount of debt securities
necessary to waive compliance with certain provisions of the indenture or
to make any change in the provision related to modification;
- modify the provisions relating to the subordination of any subordinated
debt security in a manner adverse to the holder of that security;
- waive a continuing default or event of default regarding any payment on
the debt securities; or
- release the Guarantor, or any Subsidiary Guarantor, or modify the
guarantee of the Guarantor or any Subsidiary Guarantor in any manner
adverse to the holders.
Each indenture may be amended or supplemented or any provision of that
indenture may be waived without the consent of any holders of debt securities
issued under that indenture:
- to cure any ambiguity, omission, defect or inconsistency;
- to provide for the assumption of our obligations under the indentures by
a successor upon any merger, consolidation or asset transfer permitted
under the indenture;
- to provide for uncertificated debt securities in addition to or in place
of certificated debt securities or to provide for bearer debt securities;
- to provide any security for, any guarantees of or any additional obligors
on any series of debt securities or, with respect to the senior
indentures, the related guarantees;
- to comply with any requirement to effect or maintain the qualification of
that indenture under the Trust Indenture Act of 1939;
- to add covenants that would benefit the holders of any debt securities or
to surrender any rights we have under the indentures;
- to add events of default with respect to any debt securities; and
- to make any change that does not adversely affect any outstanding debt
securities of any series issued under that indenture in any material
respect.
The holders of a majority in principal amount of the outstanding debt
securities of any series (or, in some cases, of all debt securities issued under
the applicable indenture that are affected, voting as one class) may waive any
existing or past default or event of default with respect to those debt
securities. Those holders may not, however, waive any default or event of
default in any payment on any debt security or compliance with a provision that
cannot be amended or supplemented without the consent of each holder affected.
Defeasance. When we use the term defeasance, we mean discharge from some
or all of our obligations under the indentures. If any combination of funds or
government securities are deposited with the trustee under an indenture
sufficient to make payments on the debt securities of a series issued under
34
that indenture on the dates those payments are due and payable, then, at our
option, either of the following will occur:
- we will be discharged from our or their obligations with respect to the
debt securities of that series and, if applicable, the related guarantees
("legal defeasance"); or
- we will no longer have any obligation to comply with the restrictive
covenants, the merger covenant and other specified covenants under the
applicable indenture, and the related events of default will no longer
apply ("covenant defeasance").
If a series of debt securities is defeased, the holders of the debt
securities of the series affected will not be entitled to the benefits of the
applicable indenture, except for obligations to register the transfer or
exchange of debt securities, replace stolen, lost or mutilated debt securities
or maintain paying agencies and hold moneys for payment in trust. In the case of
covenant defeasance, our obligation to pay principal, premium and interest on
the debt securities and, if applicable, guarantees of the payments will also
survive.
Unless we inform you otherwise in the prospectus supplement, we will be
required to deliver to the trustee an opinion of counsel that the deposit and
related defeasance would not cause the holders of the debt securities to
recognize income, gain or loss for U.S. federal income tax purposes. If we elect
legal defeasance, that opinion of counsel must be based upon a ruling from the
U.S. Internal Revenue Service or a change in law to that effect.
No Personal Liability of General Partner. U.S. Propane, L.P., our general
partner, and its directors, officers, employees, incorporators and partners, in
such capacity, will not be liable for the obligations of Heritage Propane
Partners, L.P., Heritage Operating, L.P. or any Subsidiary Guarantor under the
debt securities, the indentures or the guarantees or for any claim based on, in
respect of, or by reason of, such obligations or their creation. By accepting a
debt security, each holder of that debt security will have agreed to this
provision and waived and released any such liability on the part of U.S.
Propane, L.P. and its directors, officers, employees, incorporators and
partners. This waiver and release are part of the consideration for our issuance
of the debt securities. It is the view of the SEC that a waiver of liabilities
under the federal securities laws is against public policy and unenforceable.
Governing Law. New York law will govern the indentures and the debt
securities.
Trustee. We may appoint a separate trustee for any series of debt
securities. We use the term "trustee" to refer to the trustee appointed with
respect to any such series of debt securities. We may maintain banking and other
commercial relationships with the trustee and its affiliates in the ordinary
course of business, and the trustee may own debt securities.
Form, Exchange, Registration and Transfer. The debt securities will be
issued in registered form, without interest coupons. There will be no service
charge for any registration of transfer or exchange of the debt securities.
However, payment of any transfer tax or similar governmental charge payable for
that registration may be required.
Debt securities of any series will be exchangeable for other debt
securities of the same series, the same total principal amount and the same
terms but in different authorized denominations in accordance with the
applicable indenture. Holders may present debt securities for registration of
transfer at the office of the security registrar or any transfer agent we
designate. The security registrar or transfer agent will effect the transfer or
exchange if its requirements and the requirements of the applicable indenture
are met.
The trustee will be appointed as security registrar for the debt
securities. If a prospectus supplement refers to any transfer agents we
initially designate, we may at any time rescind that designation or approve a
change in the location through which any transfer agent acts. We are required to
maintain an office or agency for transfers and exchanges in each place of
payment. We may at any time designate additional transfer agents for any series
of debt securities.
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In the case of any redemption, we will not be required to register the
transfer or exchange of:
- any debt security during a period beginning 15 business days prior to the
mailing of the relevant notice of redemption and ending on the close of
business on the day of mailing of such notice; or
- any debt security that has been called for redemption in whole or in
part, except the unredeemed portion of any debt security being redeemed
in part.
Payment and Paying Agents. Unless we inform you otherwise in a prospectus
supplement, payments on the debt securities will be made in U.S. dollars at the
office of the trustee and any paying agent. At our option, however, payments may
be made by wire transfer for global debt securities or by check mailed to the
address of the person entitled to the payment as it appears in the security
register. Unless we inform you otherwise in a prospectus supplement, interest
payments may be made to the person in whose name the debt security is registered
at the close of business on the record date for the interest payment.
Unless we inform you otherwise in a prospectus supplement, the trustee
under the applicable indenture will be designated as the paying agent for
payments on debt securities issued under that indenture. We may at any time
designate additional paying agents or rescind the designation of any paying
agent or approve a change in the office through which any paying agent acts.
If the principal of or any premium or interest on debt securities of a
series is payable on a day that is not a business day, the payment will be made
on the following business day. For these purposes, unless we inform you
otherwise in a prospectus supplement, a "business day" is any day that is not a
Saturday, a Sunday or a day on which banking institutions in New York, New York
or a place of payment on the debt securities of that series is authorized or
obligated by law, regulation or executive order to remain closed.
Subject to the requirements of any applicable abandoned property laws, the
trustee and paying agent will pay to us upon written request any money held by
them for payments on the debt securities that remains unclaimed for two years
after the date upon which that payment has become due. After payment to us,
holders entitled to the money must look to us for payment. In that case, all
liability of the trustee or paying agent with respect to that money will cease.
Book-Entry Debt Securities. The debt securities of a series may be issued
in the form of one or more global debt securities that would be deposited with a
depositary or its nominee identified in the prospectus supplement. Global debt
securities may be issued in either temporary or permanent form. We will describe
in the prospectus supplement the terms of any depositary arrangement and the
rights and limitations of owners of beneficial interests in any global debt
security.
PROVISIONS APPLICABLE SOLELY TO THE HERITAGE PROPANE AND HERITAGE OPERATING
SUBORDINATED INDENTURES
Subordination. Debt securities of a series may be subordinated to our
"Senior Indebtedness," which we define generally to include any obligation
created or assumed by us (or, if the series is guaranteed, the Guarantor and any
Subsidiary Guarantors) for the repayment of borrowed money, any purchase money
obligation created or assumed by us, and any guarantee therefor, whether
outstanding or hereafter issued, unless, by the terms of the instrument creating
or evidencing such obligation, it is provided that such obligation is
subordinate or not superior in right of payment to the debt securities (or, if
the series is guaranteed, the guarantee of the Guarantor or any Subsidiary
Guarantor), or to other obligations which are pari passu with or subordinated to
the debt securities (or, if the series is guaranteed, the guarantee of the
Guarantor or any Subsidiary Guarantor). Subordinated debt securities will be
subordinated in right of payment, to the extent and in the manner set forth in
the subordinated indentures and the prospectus supplement relating to such
series, to the prior payment of all of our indebtedness and that of the
Guarantor or any Subsidiary Guarantor that is designated as "Senior
Indebtedness" with respect to the series.
The holders of Senior Indebtedness of ours or, if applicable, the Guarantor
or a Subsidiary Guarantor, will receive payment in full of the Senior
Indebtedness before holders of subordinated debt securities will receive any
payment of principal, premium or interest with respect to the subordinated debt
securities upon
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any payment or distribution of our assets or, if applicable to any series of
outstanding debt securities, the Subsidiary Guarantors' assets, to creditors:
- upon a liquidation or dissolution of us or, if applicable to any series
of outstanding debt securities, the Subsidiary Guarantors; or
- in a bankruptcy, receivership or similar proceeding relating to us or, if
applicable to any series of outstanding debt securities, to the
Subsidiary Guarantors.
Until the Senior Indebtedness is paid in full, any distribution to which
holders of subordinated debt securities would otherwise be entitled will be made
to the holders of Senior Indebtedness, except that the holders of subordinated
debt securities may receive units representing limited partner interests and any
debt securities that are subordinated to Senior Indebtedness to at least the
same extent as the subordinated debt securities.
If we do not pay any principal, premium or interest with respect to Senior
Indebtedness within any applicable grace period (including at maturity), or any
other default on Senior Indebtedness occurs and the maturity of the Senior
Indebtedness is accelerated in accordance with its terms, we may not:
- make any payments of principal, premium, if any, or interest with respect
to subordinated debt securities;
- make any deposit for the purpose of defeasance of the subordinated debt
securities; or
- repurchase, redeem or otherwise retire any subordinated debt securities,
except that in the case of subordinated debt securities that provide for
a mandatory sinking fund, we may deliver subordinated debt securities to
the trustee in satisfaction of our sinking fund obligation,
unless, in either case,
- the default has been cured or waived and any declaration of acceleration
has been rescinded;
- the Senior Indebtedness has been paid in full in cash; or
- we and the trustee receive written notice approving the payment from the
representatives of each issue of "Designated Senior Indebtedness."
Generally, "Designated Senior Indebtedness" will include:
- any specified issue of Senior Indebtedness of at least $100 million; and
- any other Senior Indebtedness that we may designate in respect of any
series of subordinated debt securities.
During the continuance of any default, other than a default described in
the immediately preceding paragraph, that may cause the maturity of any
Designated Senior Indebtedness to be accelerated immediately without further
notice, other than any notice required to effect such acceleration, or the
expiration of any applicable grace periods, we may not pay the subordinated debt
securities for a period called the "Payment Blockage Period." A Payment Blockage
Period will commence on the receipt by us and the trustee of written notice of
the default, called a "Blockage Notice," from the representative of any
Designated Senior Indebtedness specifying an election to effect a Payment
Blockage Period and will end 179 days thereafter.
The Payment Blockage Period may be terminated before its expiration:
- by written notice from the person or persons who gave the Blockage
Notice;
- by repayment in full in cash of the Designated Senior Indebtedness with
respect to which the Blockage Notice was given; or
- if the default giving rise to the Payment Blockage Period is no longer
continuing.
37
Unless the holders of the Designated Senior Indebtedness have accelerated
the maturity of the Designated Senior Indebtedness, we may resume payments on
the subordinated debt securities after the expiration of the Payment Blockage
Period.
Generally, not more than one Blockage Notice may be given in any period of
360 consecutive days. The total number of days during which any one or more
Payment Blockage Periods are in effect, however, may not exceed an aggregate of
179 days during any period of 360 consecutive days.
After all Senior Indebtedness is paid in full and until the subordinated
debt securities are paid in full, holders of the subordinated debt securities
shall be subrogated to the rights of holders of Senior Indebtedness to receive
distributions applicable to Senior Indebtedness.
As a result of the subordination provisions described above, in the event
of insolvency, the holders of Senior Indebtedness, as well as certain of our
general creditors, may recover more, ratably, than the holders of the
subordinated debt securities.
38
SELLING UNITHOLDERS
In addition to covering our offering of securities, this prospectus covers
the offering for resale of up to 1,988,846 common units by selling unitholders.
The following table sets forth information relating to the selling unitholders'
beneficial ownership of our common units as of the date of this prospectus.
<Table>
<Caption>
NUMBER OF NUMBER OF COMMON NUMBER OF COMMON
NATURE OF ANY POSITION, OFFICE COMMON UNITS UNITS AVAILABLE FOR UNITS AVAILABLE AFTER
NAME OF SELLING UNITHOLDER OR OTHER RELATIONSHIP OWNED(1)(2) RESALE(1) RESALE(3)
- -------------------------- ------------------------------ ------------ ------------------- ---------------------
U.S. Propane, L.P.(4)..... General Partner 180,028 180,028 --
James E. Bertelsmeyer..... Chairman of the Board of
Directors 1,103,622 1,027,946 75,676
H. Michael Krimbill....... Director, President and Chief
Executive Officer 335,892 292,059 43,833
R.C. Mills................ Executive Vice President and
Chief Operating Officer 341,342 305,509 35,833
Bill W. Byrne............. Director 78,157 64,157 14,000
J. Charles Sawyer......... Director 68,657 64,157 4,500
Mark A. Darr.............. Vice President -- Southern
Operations 27,880 18,330 9,550
Thomas H. Rose............ Vice President -- Northern
Operations 37,455 18,330 19,125
Curtis L. Weishahn........ Vice President -- Western
Operations 29,455 18,330 11,125
</Table>
- ---------------
(1) As of September 19, 2003.
(2) This amount includes the amount of unregistered common units available for
resale pursuant to this registration statement.
(3) Assumes all of the common units available for resale by each of the selling
unitholders have been sold.
(4) AGL Propane Services, Inc., United Cities Propane Gas, Inc., TECO Propane
Ventures, LLC and Piedmont Propane Company respectively own a 22.538%,
18.968%, 37.976% and 20.688% limited partner interest in U.S. Propane, L.P.
U.S. Propane, L.L.C. is the general partner of U.S. Propane, L.P., with a
0.01% general partner interest. AGL Energy Corporation, United Cities
Propane Gas, Inc., TECO Propane Ventures, LLC and Piedmont Propane Company
respectively own 22.36%, 18.97%, 37.98% and 20.69% of the member interests
of U.S. Propane, L.L.C.
The applicable prospectus supplement will set forth, with respect to the
selling unitholders:
- the name of the selling unitholders in that offering;
- the nature of the position, office or other material relationship which
the selling unitholders will have had within the prior three years with
us or any of our affiliates;
- the number of common units owned by the selling unitholders prior to the
offering;
- the number of common units to be offered for the selling unitholders'
account; and
- the number and (if one percent or more) the percentage of common units to
be owned by the selling unitholders after the completion of the offering.
All expenses incurred with the registration of the common units owned by
the selling unitholders, excluding any separate legal fees and expenses of the
selling unitholders, will be borne by us.
39
MATERIAL TAX CONSIDERATIONS
This section is a summary of the material tax consequences that may be
relevant to prospective unitholders who are individual citizens or residents of
the United States and, unless otherwise noted in the following discussion, is
the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us,
insofar as it relates to matters of United States federal income tax law and
legal conclusions with respect to those matters. This section is based upon
current provisions of the Internal Revenue Code, existing and proposed
regulations and current administrative rulings and court decisions, all of which
are subject to change. Later changes in these authorities may cause the tax
consequences to vary substantially from the consequences described below. Unless
the context otherwise requires, references in this section to "us" or "we" are
references to Heritage Propane Partners, L.P. and Heritage Operating, L.P.
No attempt has been made in this section to comment on all federal income
tax matters affecting us or the unitholders. Moreover, the discussion focuses on
unitholders who are individual citizens or residents of the United States and
has only limited application to corporations, estates, trusts, nonresident
aliens or other unitholders subject to specialized tax treatment, such as
tax-exempt institutions, foreign persons, individual retirement accounts (IRAs),
real estate investment trusts (REITs) or mutual funds. Accordingly, we recommend
that you consult, and depend on, your own tax advisor in analyzing the federal,
state, local and foreign tax consequences particular to you of an investment in,
or the disposition of, our securities.
All statements as to matters of law and legal conclusions, but not as to
factual matters, contained in this section, unless otherwise noted, are the
opinion of counsel, and some are based on the accuracy of the representations we
make.
No ruling has been or will be requested from the IRS regarding any matter
affecting us or prospective unitholders. An opinion of counsel represents only
that counsel's best legal judgment and does not bind the IRS or the courts.
Accordingly, the opinions and statements made here may not be sustained by a
court if contested by the IRS. Any contest of this sort with the IRS may
materially and adversely impact the market for the common units and the prices
at which common units trade. In addition, the costs of any contest with the IRS
will be borne directly or indirectly by the unitholders and the general partner.
Furthermore, the tax treatment of us or of an investment in us, may be
significantly modified by future legislative or administrative changes or court
decisions. Any modifications may or may not be retroactively applied.
For the reasons described below, counsel has not rendered an opinion with
respect to the following specific federal income tax issues:
(a) the treatment of a unitholder whose common units are loaned to a
short seller to cover a short sale of common units (please read "-- Tax
Consequences of Unit Ownership -- Treatment of Short Sales");
(b) whether our monthly convention for allocating taxable income and
losses is permitted by existing Treasury regulations (please read
"-- Disposition of Common Units -- Allocations Between Transferors and
Transferees"); and
(c) whether our method for depreciating Section 743 adjustments is
sustainable (please read "-- Tax Consequences of Unit Ownership -- Section
754 Election").
PARTNERSHIP STATUS
A partnership is not a taxable entity and incurs no federal income tax
liability. Instead, each partner of a partnership is required to take into
account his allocable share of items of income, gain, loss and deduction of the
partnership in computing his federal income tax liability, regardless of whether
cash distributions are made to him by the partnership. Distributions of cash by
a partnership to a partner generally are not taxable unless the amount of cash
distributed is in excess of the partner's adjusted basis in his partnership
interest.
40
No ruling has been or will be sought from the IRS and the IRS has made no
determination as to the status of Heritage Propane Partners, L.P. as a
partnership for federal income tax purposes or whether our operations generate
"qualifying income" under Section 7704 of the Code, or any other matter
affecting our prospective unitholders. Instead, we have relied on the opinion of
Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its
regulations, published revenue rulings and court decisions and the
representations described below, Heritage Propane Partners, L.P. has been, is,
and will continue to be, classified as a partnership for federal income tax
purposes.
In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual
representations made by us and our general partner. The representations made by
us and our general partner upon which counsel has relied are:
(a) Neither we nor Heritage Operating, L.P. has elected or will elect
to be treated as a corporation;
(b) Heritage Propane Partners, L.P. and Heritage Operating, L.P. have
been and will be operated in accordance with applicable partnership
statutes, the applicable partnership agreement and in the manner described
in this prospectus; and
(c) For each taxable year, more than 90% of our gross income has been
and will be income that Vinson & Elkins L.L.P. has opined or will opine is
"qualifying income" within the meaning of Section 7704(d) of the Internal
Revenue Code.
Section 7704 of the Internal Revenue Code provides that publicly-traded
partnerships will, as a general rule, be taxed as corporations. However, an
exception, referred to as the "Qualifying Income Exception," exists with respect
to publicly-traded partnerships of which 90% or more of the gross income for
every taxable year consists of "qualifying income." Qualifying income includes
income and gains derived from the processing, transportation and marketing of
crude oil, natural gas and products thereof, including the retail and wholesale
marketing of propane, certain hedging activities and the transportation of
propane and natural gas liquids. Other types of qualifying income include
interest other than from a financial business, dividends, gains from the sale of
real property and gains from the sale or other disposition of assets held for
the production of income that otherwise constitutes qualifying income. We
estimate that less than seven percent of our current gross income is not
qualifying income; however, this estimate could change from time to time. Based
upon and subject to this estimate, the factual representations made by us and
the general partner and a review of the applicable legal authorities, Vinson &
Elkins L.L.P. is of the opinion that at least 90% of our current gross income
constitutes qualifying income.
If we fail to meet the Qualifying Income Exception, other than a failure
which is determined by the IRS to be inadvertent and which 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 of the year in which we fail to meet the Qualifying Income Exception,
in return for stock in that corporation, and then distributed that stock to the
unitholders in liquidation of their interests in us. This contribution and
liquidation should be tax-free to unitholders and us so long as we, at that
time, do not have liabilities in excess of the tax basis of our assets.
Thereafter, we would be treated as a corporation for federal income tax
purposes.
If we were treated as an association taxable as a corporation in any
taxable year, either as a result of a failure to meet the Qualifying Income
Exception or otherwise, our items of income, gain, loss and deduction would be
reflected only on our separate tax returns rather than being passed through to
the unitholders, and our net income would be taxed to us at corporate rates. In
addition, any distribution made to a unitholder would be treated as either
taxable dividend income, to the extent of our current or accumulated earnings
and profits, or, in the absence of earnings and profits, a nontaxable return of
capital, to the extent of the unitholder's tax basis in his common units, or
taxable capital gain, after the unitholder's tax basis in his common units is
reduced to zero. Accordingly, taxation as a corporation would result in a
material reduction in a unitholder's cash flow and after-tax return and thus
would likely result in a substantial reduction of the value of the units.
41
The remainder of this section is based on Vinson & Elkins L.L.P.'s opinion
that Heritage Propane Partners, L.P. and Heritage Operating, L.P. will be
classified as partnerships for federal income tax purposes.
LIMITED PARTNER STATUS
Unitholders who have become limited partners of Heritage Propane Partners,
L.P. will be treated as partners of Heritage Propane Partners, L.P. for federal
income tax purposes. Also:
(a) assignees who have executed and delivered transfer applications,
and are awaiting admission as limited partners, and
(b) 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 of Heritage Propane Partners, L.P. for federal
income tax purposes. As there is no direct authority addressing assignees of
common units who are entitled to execute and deliver transfer applications and
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. Furthermore, a purchaser or other transferee of common units who
does not execute and deliver a transfer application may not receive some 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 for those
common units.
A beneficial owner of common units whose units have been transferred to a
short seller to complete a short sale would appear to lose his status as a
partner with respect to those units for federal income tax purposes. Please read
"-- Tax Consequences of Unit Ownership -- Treatment of Short Sales."
Income, gain, deductions or losses would not appear to be reportable by a
unitholder who is not a partner for federal income tax purposes, and any cash
distributions received by a unitholder who is not a partner for federal income
tax purposes would therefore be fully taxable as ordinary income. These holders
should consult their own tax advisors with respect to their status as partners
in Heritage Propane Partners, L.P. for federal income tax purposes.
TAX CONSEQUENCES OF UNIT OWNERSHIP
Flow-through of Taxable Income. We will not pay any federal income tax.
Instead, each unitholder 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 a unitholder even if he has not received a cash
distribution. Each unitholder will be required to include in income his
allocable share of our income, gains, losses and deductions for our taxable year
ending with or within his taxable year.
Treatment of Distributions. Our distributions to a unitholder generally
will not be taxable to the unitholder for federal income tax purposes to the
extent of his tax basis in his common units immediately before the distribution.
Our cash distributions in excess of a unitholder's tax 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 "-- Disposition of Common Units"
below. Any reduction in a unitholder's share of our liabilities for which no
partner, including the general partner, bears the economic risk of loss, known
as "nonrecourse liabilities," will be treated as a distribution of cash to that
unitholder. To the extent our distributions cause a unitholder's "at risk"
amount to be less than zero at the end of any taxable year, he must recapture
any losses deducted in previous years that are equal to the amount of that
shortfall. Please read "-- Limitations on Deductibility of Losses."
A decrease in a unitholder's percentage interest in us because of our
issuance of additional common units will decrease his share of our nonrecourse
liabilities, and thus will result in a corresponding deemed
42
distribution of cash. A non-pro rata distribution of money or property may
result in ordinary income to a unitholder, regardless of his tax basis in his
common units, if that distribution reduces the unitholder's share of our
"unrealized receivables," including depreciation recapture, and/or substantially
appreciated "inventory items," both as defined in the Internal Revenue Code, and
collectively, "Section 751 Assets."
To that extent, he will be treated as having been distributed his
proportionate share of the Section 751 Assets and having exchanged those assets
with us in return for the non-pro rata portion of the actual distribution made
to him. This latter deemed exchange generally will result in the unitholder's
realization of ordinary income. That income will equal the excess of (1) the
non-pro rata portion of that distribution over (2) the unitholder's tax basis
for the share of Section 751 Assets deemed relinquished in the exchange.
Basis of Common Units. A unitholder's initial tax basis for his common
units will be the amount he paid for the common units plus his share of our
nonrecourse liabilities. That basis will be increased by his share of our income
and by any increases in his share of our nonrecourse liabilities. That basis
will be decreased, but not below zero, by distributions from us, by the
unitholder's share of our losses, by any decreases in his share of our
nonrecourse liabilities and by his share of our expenditures that are not
deductible in computing taxable income and are not required to be capitalized. A
limited partner will have no share of our debt which is recourse to the general
partner, but will have a share, generally based on his share of profits, of our
nonrecourse liabilities. Please read "-- Disposition of Common Units --
Recognition of Gain or Loss."
Limitations on Deductibility of Losses. The deduction by a unitholder of
his share of our losses will be limited to the tax basis in his units and, in
the case of an individual unitholder or a corporate unitholder that is subject
to the "at risk" rules (for example, if more than 50% of the value of the
corporate unitholder's stock is owned directly or indirectly by five or fewer
individuals or some tax-exempt organizations), to the amount for which the
unitholder is considered to be "at risk" with respect to our activities, if that
is less than his tax basis. A unitholder must recapture losses deducted in
previous years to the extent that distributions cause his 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 his tax basis or at risk amount, whichever is the
limiting factor, is subsequently increased. Upon the taxable disposition of a
common unit, any gain recognized by a unitholder can be offset by losses that
were previously suspended by the at risk limitation but may not be offset by
losses suspended by the basis limitation. Any excess loss above that gain
previously suspended by the at risk or basis limitations is no longer
utilizable.
In general, a unitholder will be at risk to the extent of the tax basis of
his common units, excluding any portion of that basis attributable to his share
of our nonrecourse liabilities, reduced by any amount of money he borrows to
acquire or hold his common units, if the lender of those borrowed funds owns an
interest in us, is related to the unitholder or can look only to the units for
repayment. A unitholder's at risk amount will increase or decrease as the tax
basis of the unitholder's common units increases or decreases, other than tax
basis increases or decreases attributable to increases or decreases in his share
of our nonrecourse liabilities.
The passive loss limitations generally provide that individuals, estates,
trusts and some closely-held corporations and personal service corporations can
deduct losses from passive activities, which are generally activities in which
the taxpayer does not materially participate, only to the extent of the
taxpayer's income from those passive activities. The passive loss limitations
are applied separately with respect to each publicly-traded partnership.
Consequently, any losses we generate will only be available to offset our
passive income generated in the future and will not be available to offset
income from other passive activities or investments, including our investments
or investments in other publicly-traded partnerships, or salary or active
business income. Passive losses that are not deductible because they exceed a
unitholder's share of income we generate may be deducted in full when he
disposes of his entire investment in us in a fully taxable transaction with an
unrelated party. The passive activity loss rules are applied after other
applicable limitations on deductions, including the at risk rules and the basis
limitation.
43
A unitholder's share of our net income may be offset by any 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.
Limitations on Interest Deductions. The deductibility of a non-corporate
taxpayer's "investment interest expense" is generally limited to the amount of
that taxpayer's "net investment income." The IRS has indicated that net passive
income from a publicly-traded partnership constitutes investment income for
purposes of the limitations on the deductibility of investment interest. In
addition, the unitholder's share of our portfolio income will be treated as
investment income. Investment interest expense includes:
(a) interest on indebtedness properly allocable to property held for
investment;
(b) our interest expense attributed to portfolio income; and
(c) 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 unit. Net investment income includes gross income from
property held for investment and amounts treated as portfolio income under the
passive loss rules, less deductible expenses, other than interest, directly
connected with the production of investment income, but generally does not
include gains attributable to the disposition of property held for investment.
Entity-Level Collections. If we are required or elect under applicable law
to pay any federal, state or local income tax on behalf of any unitholder or the
general partner or any former unitholder, we are authorized to pay those taxes
from our funds. That payment, if made, will be treated as a distribution of cash
to the partner on whose behalf the payment was made. If the payment is made on
behalf of a person whose identity cannot be determined, we are authorized to
treat the payment as a distribution to all current unitholders. We are
authorized to amend the partnership agreement in the manner necessary to
maintain uniformity of intrinsic tax characteristics of units and to adjust
later distributions, so that after giving effect to these distributions, the
priority and characterization of distributions otherwise applicable under the
partnership agreement is maintained as nearly as is practicable. Payments by us
as described above could give rise to an overpayment of tax on behalf of an
individual partner in which event the partner would be required to file a claim
in order to obtain a credit or refund.
Allocation of Income, Gain, Loss and Deduction. In general, if we have a
net profit, our items of income, gain, loss and deduction will be allocated
among the general partner and the unitholders in accordance with their
percentage interests in us. At any time that incentive distributions are made to
the general partner, gross income will be allocated to the general partner to
the extent of these distributions. If we have a net loss for the entire year,
that loss will be allocated first to the general partner and the unitholders in
accordance with their percentage interests in us to the extent of their positive
capital accounts and, second, to the general partner.
Specified items of our income, gain, loss and deduction will be allocated
to account for the difference between the tax basis and fair market value of our
assets at the time of an offering, referred to in this discussion as
"Contributed Property." The effect of these allocations to a unitholder
purchasing common units in our offering will be essentially the same as if the
tax basis of our assets were equal to their fair market value at the time of the
offering. In addition, items of recapture income will be allocated to the extent
possible to the partner who was allocated the deduction giving rise to the
treatment of that gain as recapture income in order to minimize the recognition
of ordinary income by some unitholders. 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 to eliminate the negative balance as
quickly as possible.
An allocation of items of our income, gain, loss or deduction, other than
an allocation required by the Internal Revenue Code to eliminate the difference
between a partner's "book" capital account, credited
44
with the fair market value of Contributed Property, and "tax" capital account,
credited with the tax basis of Contributed Property, referred to in this
discussion as the "Book-Tax Disparity," will generally be given effect for
federal income tax purposes in determining a partner's 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 share of an item will be determined on
the basis of his interest in us, which will be determined by taking into account
all the facts and circumstances, including his relative contributions to us, the
interests of all the partners in profits and losses, the interest of all the
partners in cash flow and other nonliquidating distributions and rights of all
the partners to distributions of capital upon liquidation.
Vinson & Elkins L.L.P. is of the opinion that, with the exception of the
issues described in "-- Tax Consequences of Unit Ownership -- Section 754
Election" and "-- Disposition of Common Units -- Allocations Between Transferors
and Transferees," allocations under our partnership agreement will be given
effect for federal income tax purposes in determining a partner's share of an
item of income, gain, loss or deduction.
Treatment of Short Sales. A unitholder whose units are loaned to a "short
seller" to cover a short sale of units may be considered as having disposed of
those units. If so, he would no longer be a partner for those units during the
period of the loan and may recognize gain or loss from the disposition. As a
result, during this period:
(a) any of our income, gain, loss or deduction with respect to those
units would not be reportable by the unitholder;
(b) any cash distributions received by the unitholder as to those
units would be fully taxable; and
(c) all of these distributions would appear to be ordinary income.
Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment
of a unitholder where common units are loaned to a short seller to cover a short
sale of common units; therefore, unitholders desiring to assure their status as
partners and avoid the risk of gain recognition from a loan to a short seller
should modify any applicable brokerage account agreements to prohibit their
brokers from borrowing their units. The IRS has announced that it is actively
studying issues relating to the tax treatment of short sales of partnership
interests. Please also read "-- Disposition of Common Units -- Recognition of
Gain or Loss."
Alternative Minimum Tax. Each unitholder will be required to take into
account his distributive share of any items of our income, gain, loss or
deduction for purposes of the alternative minimum tax. The current minimum tax
rate for noncorporate taxpayers is 26% on the first $175,000 of alternative
minimum taxable income in excess of the exemption amount and 28% on any
additional alternative minimum taxable income. Prospective unitholders should
consult with their tax advisors as to the impact of an investment in units on
their liability for the alternative minimum tax.
Tax Rates. In general, the highest effective United States federal income
tax rate for individuals currently is 35% and the maximum United States federal
income tax rate for net capital gains of an individual is 15% if the asset
disposed of was held for more than 12 months at the time of disposition.
Section 754 Election. We have made the election permitted by Section 754
of the Internal Revenue Code. That election is irrevocable without the consent
of the IRS. The election will generally permit us to adjust a common unit
purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the
Internal Revenue Code to reflect his purchase price. This election does not
apply to a person who purchases common units directly from us. The Section
743(b) adjustment belongs to the purchaser and not to other partners. 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 tax basis in our assets
("common basis") and (2) his Section 743(b) adjustment to that basis.
Treasury regulations under Section 743 of the Internal Revenue Code
require, if the remedial allocation method is adopted (which we have adopted), a
portion of the Section 743(b) adjustment
45
attributable to recovery property to be depreciated over the remaining cost
recovery period for the Section 704(c) built-in gain. 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 Internal Revenue 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. Under our partnership agreement, the general partner is authorized to
take a position to preserve the uniformity of units even if that position is not
consistent with these Treasury regulations. Please read "-- Uniformity of
Units."
Although Vinson & Elkins L.L.P. is unable to opine as to the validity of
this approach because there is no clear authority on this issue, we intend to
depreciate the portion of a Section 743(b) adjustment attributable to unrealized
appreciation in the value of Contributed 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 the property, or treat that portion as non-amortizable to
the extent attributable to property the common basis of which is not
amortizable. This method is consistent with the regulations under Section 743
but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of our assets. To
the extent this 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 take a depreciation or
amortization position under which all purchasers acquiring units in the same
month would receive depreciation or amortization, whether attributable to common
basis or a Section 743(b) adjustment, based upon the same applicable rate as if
they had purchased a direct interest in our assets. This kind of aggregate
approach may result in lower annual depreciation or amortization deductions than
would otherwise be allowable to some unitholders. Please read "-- Uniformity of
Units."
A Section 754 election is advantageous if the transferee's tax basis in his
units is higher than the units' share of the aggregate tax basis of our assets
immediately prior to the transfer. In that case, as a result of the election,
the transferee would have, among other items, a greater amount of depreciation
and depletion deductions and his share of any gain on a sale of our assets would
be less. Conversely, a Section 754 election is disadvantageous if the
transferee's tax basis in his units is lower than those units' share of the
aggregate tax basis of our assets immediately prior to the transfer. Thus, the
fair market value of the units may be affected either favorably or unfavorably
by the election.
The calculations involved in the Section 754 election are complex and will
be made on the basis of assumptions as to the value of our assets and other
matters. For example, the allocation of the Section 743(b) adjustment among our
assets must be made in accordance with the Internal Revenue Code. The IRS could
seek to reallocate some or all of any Section 743(b) adjustment we allocated to
our tangible assets to goodwill instead. Goodwill, as an intangible asset, is
generally amortizable over a longer period of time or under a less accelerated
method than our tangible assets. We cannot assure you that the determinations we
make will not be successfully challenged by the IRS and that the deductions
resulting from them will not be reduced or disallowed altogether. Should the IRS
require a different basis adjustment to be made, and should, in our opinion, the
expense of compliance exceed the benefit of the election, we may seek permission
from the IRS to revoke our Section 754 election. If permission is granted, a
subsequent purchaser of units may be allocated more income than he would have
been allocated had the election not been revoked.
TAX TREATMENT OF OPERATIONS
Accounting Method and Taxable Year. We use the year ending December 31 as
our taxable year and the accrual method of accounting for federal income tax
purposes. Each unitholder will be required to include in income his share of our
income, gain, loss and deduction for our taxable year ending within or with his
taxable year.
Tax Basis, Depreciation and Amortization. The tax basis of our assets will
be used for purposes of computing depreciation and cost recovery deductions and,
ultimately, gain or loss on the disposition of
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these assets. The federal income tax burden associated with the difference
between the fair market value of our assets and their tax basis immediately
prior to an offering will be borne by the general partner, its affiliates and
our other unitholders as of that time. Please read "-- Allocation of Income,
Gain, Loss and Deduction."
To the extent allowable, we may elect to use the depreciation and cost
recovery methods that will result in the largest deductions being taken in the
early years after assets are placed in service. We are not entitled to any
amortization deductions with respect to any goodwill conveyed to us on
formation. Property we subsequently acquire or construct may be depreciated
using accelerated methods permitted by the Internal Revenue Code.
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 we own will likely be required to recapture some or all of
those deductions as ordinary income upon a sale of his interest in us. Please
read "-- Tax Consequences of Unit Ownership -- Allocation of Income, Gain, Loss
and Deduction" and "-- Disposition of Common Units -- Recognition of Gain or
Loss."
The costs incurred in selling our units (called "syndication expenses")
must be capitalized and cannot be deducted currently, ratably or upon our
termination. There are uncertainties regarding the classification of costs as
organization expenses, which we may amortize, and as syndication expenses, which
we may not amortize. The underwriting discounts and commissions we incur will be
treated as syndication expenses.
Valuation and Tax Basis of Our Properties. The federal income tax
consequences of the ownership and disposition of units will depend in part on
our estimates of the relative fair market values, and the initial tax bases, of
our assets. Although we may from time to time consult with professional
appraisers regarding valuation matters, we will make many of the relative fair
market value estimates ourselves. These estimates of basis are subject to
challenge and will not be binding on the IRS or the courts. If the estimates of
fair market value or basis are later found to be incorrect, the character and
amount of items of income, gain, loss or deductions previously reported by
unitholders might change, and unitholders might be required to adjust their tax
liability for prior years and incur interest and penalties with respect to those
adjustments.
DISPOSITION OF COMMON UNITS
Recognition of Gain or Loss. Gain or loss will be recognized on a sale of
units equal to the difference between the amount realized and the unitholder's
tax basis for the units sold. A unitholder's amount realized will be measured by
the sum of the cash or the fair market value of other property he receives plus
his share of our nonrecourse liabilities. Because the amount realized includes a
unitholder's share of our nonrecourse liabilities, the gain recognized on the
sale of units could result in a tax liability in excess of any cash received
from the sale.
Prior distributions from us in excess of cumulative net taxable income for
a common unit that decreased a unitholder's tax basis in that common unit will,
in effect, become taxable income if the common unit is sold at a price greater
than the unitholder's tax basis in that common unit, even if the price received
is less than his original cost.
Except as noted below, gain or loss recognized by a unitholder, other than
a "dealer" in units, on the sale or exchange of a unit held for more than one
year will generally be taxable as capital gain or loss. Capital gain recognized
by an individual on the sale of units held more than 12 months will generally be
taxed at a maximum rate of 15%. A portion of this gain or loss, which will
likely be substantial, however, will be separately computed and taxed as
ordinary income or loss under Section 751 of the Internal Revenue Code to the
extent attributable to assets giving rise to depreciation recapture or other
"unrealized receivables" or to "inventory items" we own. The term "unrealized
receivables" includes potential recapture items, including depreciation
recapture. Ordinary income attributable to unrealized receivables,
47
inventory items and depreciation recapture may exceed net taxable gain realized
upon the sale of a unit and may be recognized even if there is a net taxable
loss realized on the sale of a unit. Thus, a unitholder may recognize both
ordinary income and a capital loss upon a sale of units. Net capital loss may
offset capital gains and 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
corporations.
The IRS has ruled that a partner who acquires interests in a partnership in
separate transactions must combine those interests and maintain a single
adjusted tax basis for all those interests. Upon a sale or other disposition of
less than all of those interests, a portion of that tax basis must be allocated
to the interests sold using an "equitable apportionment" method. Treasury
regulations allow a selling unitholder who can identify common units transferred
with an ascertainable holding period to elect to use the actual holding period
of the common units transferred. Thus, according to the ruling, a common
unitholder will be unable to select high or low basis common units to sell as
would be the case with corporate stock, but, according to the regulations, may
designate specific common units sold for purposes of determining the holding
period of units transferred. A unitholder electing to use the actual holding
period of common units transferred must consistently use that identification
method for all subsequent sales or exchanges of common units. A unitholder
considering the purchase of additional units or a sale of common units purchased
in separate transactions should consult his tax advisor as to the possible
consequences of this ruling and application of the Treasury regulations.
Specific provisions of the Internal Revenue Code affect the taxation of
some financial products and securities, including partnership interests, by
treating a taxpayer as having sold an "appreciated" partnership interest, one in
which gain would be recognized if it were sold, assigned or terminated at its
fair market value, if the taxpayer or related persons enter(s) into:
(a) a short sale;
(b) an offsetting notional principal contract; or
(c) a futures or forward contract with respect to the partnership
interest or substantially identical property.
Moreover, if a taxpayer has previously entered into a short sale, an
offsetting notional principal contract or a futures or forward contract with
respect to the partnership interest, the taxpayer will be treated as having sold
that position if the taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of Treasury is also
authorized to issue regulations that treat a taxpayer that enters into
transactions or positions that have substantially the same effect as the
preceding transactions as having constructively sold the financial position.
Allocations Between Transferors and Transferees. In general, our taxable
income and losses will be determined annually, will be prorated on a monthly
basis and will be subsequently apportioned among the unitholders in proportion
to the number of units owned by each of them as of the opening of the applicable
exchange on the first business day of the month (the "Allocation Date").
However, gain or loss realized on a sale or other disposition of our assets
other than in the ordinary course of business will be allocated among the
unitholders on the Allocation Date in the month in which that gain or loss is
recognized. As a result, a unitholder transferring units may be allocated
income, gain, loss and deduction realized after the date of transfer.
The use of this method may not be permitted under existing Treasury
regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the
validity of this method of allocating income and deductions between unitholders.
If this method is not allowed under the Treasury regulations, or only applies to
transfers of less than all of the unitholder's interest, our taxable income or
losses might be reallocated among the unitholders. We are authorized to revise
our method of allocation between unitholders to conform to a method permitted
under future Treasury regulations.
48
A unitholder who owns units at any time during a quarter and who disposes
of them prior to the record date set for a cash distribution for that quarter
will be allocated items of our income, gain, loss and deductions attributable to
that quarter but will not be entitled to receive that cash distribution.
Notification Requirements. A purchaser of units from another unitholder is
required to notify us in writing of that purchase within 30 days after the
purchase. We are required to notify the IRS of that transaction and to furnish
specified information to the transferor and transferee. However, these reporting
requirements do not apply to a sale by an individual who is a citizen of the
United States and who effects the sale or exchange through a broker.
Additionally, a transferor and a transferee of a 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 describe the amount of
the consideration received for the unit that is allocated to our goodwill or
going concern value.
Constructive Termination. We will be considered to have been terminated
for tax purposes if there is a sale or exchange of 50% or more of the total
interests in our capital and profits within a 12-month period. A constructive
termination results in the closing of our taxable year for all unitholders. We
would be required to make new tax elections after a termination, including a new
election under Section 754 of the Internal Revenue Code, and a termination would
result in a deferral of our deductions for depreciation. A termination could
also result in penalties if we were unable to determine that the termination had
occurred. Moreover, a termination might either accelerate the application of, or
subject us to, any tax legislation enacted before the termination.
UNIFORMITY OF UNITS
Because we cannot match transferors and transferees of units, we must
maintain uniformity of the economic and tax characteristics of the units to a
purchaser of these units. In the absence of uniformity, we may be unable to
completely comply with a number of federal income tax requirements, both
statutory and regulatory. A lack of uniformity can result from a literal
application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity
could have a negative impact on the value of the units. Please read "-- Tax
Consequences of Unit Ownership -- Section 754 Election."
We intend to depreciate the portion of a Section 743(b) adjustment
attributable to unrealized appreciation in the value of Contributed 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 that property, or treat that portion as
nonamortizable, to the extent attributable to property the common basis of which
is not amortizable, consistent with the regulations under Section 743, even
though that position may be inconsistent with Treasury Regulation Section
1.167(c)-1(a)(6) which is not expected to directly apply to a material portion
of our assets. Please read "-- Tax Consequences of Unit Ownership -- 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 regulations and legislative history.
If we determine that this position cannot reasonably be taken, we may adopt a
depreciation and amortization position under which all purchasers acquiring
units in the same month would receive depreciation and amortization deductions,
whether attributable to a common basis or Section 743(b) adjustment, based upon
the same applicable rate as if they had purchased a direct interest in our
property. If this position is adopted, it may result in lower annual
depreciation and amortization deductions than would otherwise be allowable to
some unitholders and risk the loss of depreciation and amortization deductions
not taken in the year that these deductions are otherwise allowable. This
position will not be adopted if we determine that the loss of depreciation and
amortization deductions will have a material adverse effect on the unitholders.
If we choose not to utilize this aggregate method, we may use any other
reasonable depreciation and amortization method to preserve the uniformity of
the intrinsic tax characteristics of any units that would not have a material
adverse effect on the unitholders. The IRS may challenge any method of
depreciating the Section 743(b) adjustment described in this paragraph. If this
challenge were sustained, the uniformity of units might be affected, and the
gain from the sale of units might be increased
49
without the benefit of additional deductions. Please read "-- Disposition of
Common Units -- Recognition of Gain or Loss."
TAX-EXEMPT ORGANIZATIONS AND OTHER INVESTORS
Ownership of 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 those investors and,
as described below, may have substantially adverse tax consequences to them.
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 our income allocated to a unitholder which is a tax-exempt
organization will be unrelated business taxable income and will be taxable to
them.
A regulated investment company or "mutual fund" is required to derive 90%
or more of its gross income from interest, dividends and gains from the sale of
stocks or securities or foreign currency or specified related sources. It is not
anticipated that any significant amount of our gross income will include that
type of income.
Non-resident aliens and foreign corporations, trusts or estates that own
units will be considered to be engaged in business in the United States because
of the ownership of units. As a consequence they will be required to file
federal tax returns to report their share of our income, gain, loss or deduction
and pay federal income tax at regular rates on their share of our net income or
gain. And, under rules applicable to publicly traded partnerships, we will
withhold tax, at the highest applicable rate, from 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 BEN or applicable substitute form in order to obtain credit for
these withholding taxes.
In addition, because a foreign corporation that owns units will be treated
as engaged in a United States trade or business, that corporation may be subject
to the United States branch profits tax at a rate of 30%, in addition to regular
federal income tax, on its share of our income and gain, as adjusted for changes
in the foreign corporation's "U.S. net equity," which are effectively connected
with the conduct of a United States trade or business. That tax may be reduced
or eliminated by an income tax treaty between the United States and the country
in which the foreign corporate unitholder is a "qualified resident." In
addition, this type of unitholder is subject to special information reporting
requirements under Section 6038C of the Internal Revenue Code.
Under a ruling of the IRS, a foreign unitholder who sells or otherwise
disposes of a unit will be subject to federal income tax on gain realized on the
sale or disposition of that unit to the extent that this 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 or subject to
withholding upon the sale or disposition of a unit if he has owned less than 5%
in value of the units during the five-year period ending on the date of the
disposition and if the units are regularly traded on an established securities
market at the time of the sale or disposition.
ADMINISTRATIVE MATTERS
Information Returns and Audit Procedures. We intend to furnish to each
unitholder, within 90 days after the close of each calendar year, specific tax
information, including a Schedule K-1, which describes his share of our income,
gain, loss and deduction for our preceding taxable year. In preparing this
information, which will not be reviewed by counsel, we will take various
accounting and reporting positions, some of which have been mentioned earlier,
to determine his share of income, gain, loss and deduction. We cannot assure you
that those positions will yield a result that conforms to the requirements of
the Internal Revenue Code, regulations or administrative interpretations of the
IRS. Neither we nor counsel can assure prospective unitholders that the IRS will
not successfully contend in court that those positions are impermissible. Any
challenge by the IRS could negatively affect the value of the units.
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The IRS may audit our federal income tax information returns. Adjustments
resulting from an IRS audit may require each unitholder to adjust a prior year's
tax liability, and possibly may result in an audit of his own return. Any audit
of a unitholder's return could result in adjustments not related to our returns
as well as those related to our returns.
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 and deduction are determined in a partnership proceeding rather than
in separate proceedings with the partners. The Internal Revenue Code requires
that one partner be designated as the "Tax Matters Partner" for these purposes.
The partnership agreement names the general partner as our Tax Matters Partner.
The Tax Matters Partner will make some elections on our behalf and on
behalf of unitholders. In addition, the Tax Matters Partner can extend the
statute of limitations for assessment of tax deficiencies against unitholders
for items in our returns. The Tax Matters Partner may bind a unitholder with
less than a 1% profits interest in us to a settlement with the IRS unless that
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, by which all the unitholders are bound, of a final partnership
administrative adjustment and, if the Tax Matters Partner fails to seek judicial
review, judicial review may be sought by any unitholder having at least a 1%
interest in profits or by any group of unitholders having in the aggregate at
least a 5% interest in profits. 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. Intentional or negligent disregard of this
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:
(a) the name, address and taxpayer identification number of the
beneficial owner and the nominee;
(b) 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;
(c) the amount and description of units held, acquired or transferred
for the beneficial owner; and
(d) specific 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 specific
information on 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 Internal Revenue Code for failure to report that information to
us. The nominee is required to supply the beneficial owner of the units with the
information furnished to us.
Registration as a Tax Shelter. The Internal Revenue Code requires that
"tax shelters" be registered with the Secretary of the Treasury. It is arguable
that we are not subject to the registration requirement on the basis that we
will not constitute a tax shelter. However, we have registered as a tax shelter
with the Secretary of Treasury in the absence of assurance that we will not be
subject to tax shelter registration and in light of the substantial penalties
which might be imposed if registration is required and not undertaken.
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OUR TAX SHELTER REGISTRATION NUMBER IS 96234000014.
ISSUANCE OF THIS REGISTRATION NUMBER DOES NOT INDICATE THAT INVESTMENT IN US OR
THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS.
A unitholder who sells or otherwise transfers a unit in a later transaction
must furnish the registration number to the transferee. The penalty for failure
of the transferor of a 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 or other benefit we generate is claimed or on which any of our
income is included. A unitholder who fails to disclose the tax shelter
registration number on his return, without reasonable cause for that failure,
will be subject to a $250 penalty for each failure. Any penalties discussed are
not deductible for federal income tax purposes.
Recently issued Treasury Regulations require taxpayers to report certain
information on Internal Revenue Service Form 8886 if they participate in a
"reportable transaction." You may be required to file this form with the IRS if
we participate in a "reportable transaction." A transaction may be a reportable
transaction based upon any of several factors. You are urged to consult with
your own tax advisor concerning the application of any of these factors to your
investment in our common units. Congress is considering legislative proposals
that, if enacted, would impose significant penalties for failure to comply with
these disclosure requirements. The Treasury Regulations also impose obligations
on "material advisors" that organize, manage or sell interests in registered
"tax shelters." As stated above, we have registered as a tax shelter, and, thus,
one of our material advisors will be required to maintain a list with specific
information, including your name and tax identification number, and to furnish
this information to the IRS upon request. You are urged to consult with your own
tax advisor concerning any possible disclosure obligation with respect to your
investment and should be aware that we and our material advisors intend to
comply with the list and disclosure requirements.
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
specified causes, including negligence or disregard of rules or regulations,
substantial understatements of income tax and substantial valuation
misstatements, is imposed by the Internal Revenue Code. No penalty will be
imposed, however, for 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 regarding 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:
(a) for which there is, or was, "substantial authority," or
(b) as to which there is a reasonable basis and the pertinent facts of
that position are disclosed on the return.
More stringent rules apply for purposes of reducing the amount of any
understatement attributable to a "tax shelter," a term that in the context of
the substantial understatement penalty does not appear to include us, even
though we are a registered tax shelter. If any item of income, gain, loss or
deduction included in the distributive shares of unitholders might result in
that kind of 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 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%.
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STATE, LOCAL AND OTHER TAX CONSIDERATIONS
In addition to federal income taxes, you will be subject to other taxes,
including state and local income taxes, unincorporated business taxes, and
estate, inheritance or intangible taxes that may be imposed by the various
jurisdictions in which we do business or own property or in which you are a
resident. We currently do business or own property in 29 states, most of which
impose income taxes. We may also own property or do business in other states or
foreign jurisdictions in the future. Although an analysis of those various taxes
is not presented here, each prospective unitholder should consider their
potential impact on his investment in us. You may not be required to file a
return and pay taxes in some states because your income from that state falls
below the filing and payment requirement. You will be required, however, to file
state income tax returns and to pay state income taxes in many of the states in
which we do business or own property, and you may be subject to penalties for
failure to comply with those requirements. In some states, tax losses may not
produce a tax benefit in the year incurred and also may not be available to
offset income in subsequent taxable years. Some of the states may require us, or
we may elect, 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 of
which may be greater or less than a particular unitholder's income tax liability
to the state, generally does not relieve a nonresident unitholder from the
obligation to file an income tax return. Amounts withheld may be treated as if
distributed to unitholders for purposes of determining the amounts distributed
by us. Please read "-- Tax Consequences of Unit Ownership -- Entity-Level
Collections." Based on current law and our estimate of our future operations,
the general partner anticipates that any amounts required to be withheld will
not be material.
IT IS THE RESPONSIBILITY OF EACH UNITHOLDER TO INVESTIGATE THE LEGAL AND
TAX CONSEQUENCES, UNDER THE LAWS OF PERTINENT STATES AND LOCALITIES, OF HIS
INVESTMENT IN US. ACCORDINGLY, EACH PROSPECTIVE UNITHOLDER IS URGED TO CONSULT
WITH, AND DEPEND UPON, HIS OWN TAX COUNSEL OR OTHER ADVISOR WITH REGARD TO THOSE
MATTERS. FURTHER, IT IS THE RESPONSIBILITY OF EACH UNITHOLDER TO FILE ALL STATE
AND LOCAL, AS WELL AS UNITED STATES FEDERAL TAX RETURNS, THAT MAY BE REQUIRED OF
HIM. VINSON & ELKINS L.L.P. HAS NOT RENDERED AN OPINION ON THE STATE OR LOCAL
TAX CONSEQUENCES OF AN INVESTMENT IN US.
TAX CONSEQUENCES OF OWNERSHIP OF DEBT SECURITIES
A description of the material federal income tax consequences of the
acquisition, ownership and disposition of debt securities will be set forth on
the prospectus supplement relating to the offering of debt securities.
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INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS
An investment in us by an employee benefit plan is subject to certain
additional considerations because the investments of such plans are subject to
the fiduciary responsibility and prohibited transaction provisions of the
Employee Retirement Income Security Act of 1974, as amended ("ERISA"), and
restrictions imposed by Section 4975 of the Internal Revenue Code. As used
herein, the term "employee benefit plan" includes, but is not limited to,
qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified
employee pension plans and tax deferred annuities or IRAs established or
maintained by an employer or employee organization. Among other things,
consideration should be given to (a) whether such investment is prudent under
Section 404(a)(1)(B) of ERISA; (b) whether in making such investment, such plan
will satisfy the diversification requirement of Section 404(a)(1)(C) of ERISA;
and (c) whether such investment will result in recognition of unrelated business
taxable income by such plan and, if so, the potential after-tax investment
return. Please read "Tax Considerations -- Tax-Exempt Organizations and Other
Investors." The person with investment discretion with respect to the assets of
an employee benefit plan (a "fiduciary") should determine whether an investment
in us is authorized by the appropriate governing instrument and is a proper
investment for such plan.
Section 406 of ERISA and Section 4975 of the Internal Revenue Code (which
also applies to IRAs that are not considered part of an employee benefit plan)
prohibit an employee benefit plan from engaging in certain transactions
involving "plan assets" with parties that are "parties in interest" under ERISA
or "disqualified persons" under the Internal Revenue Code with respect to the
plan.
In addition to considering whether the purchase of limited partnership
units is a prohibited transaction, a fiduciary of an employee benefit plan
should consider whether such plan will, by investing in us, be deemed to own an
undivided interest in our assets, with the result that our general partner also
would be a fiduciary of such plan and our operations would be subject to the
regulatory restrictions of ERISA, including its prohibited transaction rules, as
well as the prohibited transaction rules of the Internal Revenue Code.
The Department of Labor regulations provide guidance with respect to
whether the assets of an entity in which employee benefit plans acquire equity
interests would be deemed "plan assets" under certain circumstances. Pursuant to
these regulations, an entity's assets would not be considered to be "plan
assets" if, among other things, (a) the equity interest acquired by employee
benefit plans are publicly offered securities -- i.e., the equity interests are
widely held by 100 or more investors independent of the issuer and each other,
freely transferable and registered pursuant to certain provisions of the federal
securities laws, (b) the entity is an "Operating Partnership" -- i.e., it is
primarily engaged in the production or sale of a product or service other than
the investment of capital either directly or through a majority owned subsidiary
or subsidiaries, or (c) there is no significant investment by benefit plan
investors, which is defined to mean that less than 25% of the value of each
class of equity interest (disregarding certain interests held by our general
partner, its affiliates and certain other persons) is held by the employee
benefit plans referred to above, IRAs and other employee benefit plans not
subject to ERISA (such as governmental plans). Our assets should not be
considered "plan assets" under these regulations because it is expected that the
investment will satisfy the requirements in (a) and (b) above and may also
satisfy the requirements in (c) above.
Plan fiduciaries contemplating a purchase of limited partnership units
should consult with their own counsel regarding the consequences under ERISA and
the Internal Revenue Code in light of the serious penalties imposed on persons
who engage in prohibited transactions or other violations.
54
PLAN OF DISTRIBUTION
We may sell the securities being offered hereby directly to purchasers,
through agents, through underwriters or through dealers.
We, or agents designated by us, may directly solicit, from time to time,
offers to purchase the securities. Any such agent may be deemed to be an
underwriter as that term is defined in the Securities Act of 1933. We will name
the agents involved in the offer or sale of the securities and describe any
commissions payable by us to these agents in the prospectus supplement. Unless
otherwise indicated in the prospectus supplement, these agents will be acting on
a best efforts basis for the period of their appointment. The agents may be
entitled under agreements which may be entered into with us to indemnification
by us against specific civil liabilities, including liabilities under the
Securities Act of 1933. The agents may also be our customers or may engage in
transactions with or perform services for us in the ordinary course of business.
If we utilize any underwriters in the sale of the securities in respect of
which this prospectus is delivered, we will enter into an underwriting agreement
with those underwriters at the time of sale to them. We will set forth the names
of these underwriters and the terms of the transaction in the prospectus
supplement, which will be used by the underwriters to make resales of the
securities in respect of which this prospectus is delivered to the public. We
may indemnify the underwriters under the relevant underwriting agreement to
indemnification by us against specific liabilities, including liabilities under
the Securities Act. The underwriters may also be our customers or may engage in
transactions with or perform services for us in the ordinary course of business.
If we utilize a dealer in the sale of the securities in respect of which
this prospectus is delivered, we will sell those securities to the dealer, as
principal. The dealer may then resell those securities to the public at varying
prices to be determined by the dealer at the time of resale. We may indemnify
the dealers against specific liabilities, including liabilities under the
Securities Act. The dealers may also be our customers or may engage in
transactions with, or perform services for us in the ordinary course of
business.
Common units and debt securities may also be sold directly by us. In this
case, no underwriters or agents would be involved. We may use electronic media,
including the Internet, to sell offered securities directly.
To the extent required, this prospectus may be amended or supplemented from
time to time to describe a specific plan of distribution. The place and time of
delivery for the securities in respect of which this prospectus is delivered are
set forth in the accompanying prospectus supplement.
DISTRIBUTION BY SELLING UNITHOLDERS
Distribution of any common units to be offered by one or more of the
selling unitholders may be effected from time to time in one or more
transactions (which may involve block transactions) (1) on the New York Stock
Exchange, (2) in the over-the-counter market, (3) in underwritten transactions,
(4) in transactions otherwise than on the New York Stock Exchange or in the
over-the-counter market or (5) in a combination of any of these transactions.
The transactions may be effected by the selling unitholders at market prices
prevailing at the time of sale, at prices related to the prevailing market
prices, at negotiated prices or at fixed prices. The selling unitholders may
offer their shares through underwriters, brokers, dealers or agents, who may
receive compensation in the form of underwriting discounts, commissions or
concessions from the selling unitholders and/or the purchasers of the shares for
whom they act as agent. The selling unitholders may engage in short sales, short
sales against the box, puts and calls and other transactions in our securities,
or derivatives thereof, and may sell and deliver their common units in
connection therewith. In addition, the selling unitholders may from time to time
sell their common units in transactions permitted by Rule 144 under the
Securities Act.
As of the date of this prospectus, we have not engaged any underwriter,
broker, dealer or agent in connection with the distribution of common units
pursuant to this prospectus by the selling unitholders. To
55
the extent required, the number of common units to be sold, the purchase price,
the name of any applicable agent, broker, dealer or underwriter and any
applicable commissions with respect to a particular offer will be set forth in
the applicable prospectus supplement. The aggregate net proceeds to the selling
unitholders from the sale of their common units offered hereby will be the sale
price of those shares, less any commissions, if any, and other expenses of
issuance and distribution not borne by us.
The selling unitholders and any brokers, dealers, agents or underwriters
that participate with the selling unitholders in the distribution of shares may
be deemed to be "underwriters" within the meaning of the Securities Act, in
which event any discounts, concessions and commissions received by such brokers,
dealers, agents or underwriters and any profit on the resale of the shares
purchased by them may be deemed to be underwriting discounts and commissions
under the Securities Act.
We have agreed to bear the fees and expenses of the selling unitholders,
excluding underwriting discounts and commissions and any legal expenses, in
connection with the registration of the common units being offered hereby by
them. We have also agreed to indemnify the selling unitholders against certain
civil liabilities, including liabilities under the Securities Act.
LEGAL MATTERS
The validity of the securities offered in this prospectus will be passed
upon for us by Vinson & Elkins L.L.P., Houston, Texas and Doerner, Saunders,
Daniel & Anderson, L.L.P., Tulsa, Oklahoma. Vinson & Elkins L.L.P. will also
render an opinion on the material federal income tax considerations regarding
the securities. If certain legal matters in connection with an offering of the
securities made by this prospectus and a related prospectus supplement are
passed on by counsel for the underwriters of such offering, that counsel will be
named in the applicable prospectus supplement related to that offering.
EXPERTS
The consolidated financial statements of Heritage Propane Partners, L.P.,
as of August 31, 2003 and 2002, and for each of the three years in the period
ended August 31, 2003, the financial statements of Bi-State Propane as of August
31, 2002 and for the year then ended, the consolidated balance sheet of U.S.
Propane, L.P., as of August 31, 2003, and the consolidated balance sheet of U.S.
Propane L.L.C., as of August 31, 2003, incorporated by reference in the
prospectus and elsewhere in the registration statement of which the prospectus
is a part, have been audited by Grant Thornton LLP, independent certified public
accountants, as indicated in their reports with respect thereto, and are
incorporated by reference in the prospectus in reliance upon the authority of
said firm as experts in giving such reports.
The combined financial statements of V-1 Oil Co. and V-1 Gas Co. as of
December 31, 2001 and 2000, and for each of the three years in the period ended
December 31, 2001, incorporated by reference in this prospectus and elsewhere in
the registration statement of which the prospectus is a part, have been audited
by Grant Thornton LLP, independent certified public accountants, as indicated in
their report with respect thereto, and are incorporated by reference in the
prospectus in reliance upon the authority of said firm as experts in giving such
reports.
The consolidated financial statements of Aquila Gas Pipeline Corporation
and Subsidiaries as of September 30, 2002 and December 31, 2001 and for the
periods ended September 30, 2002 and December 31, 2001 and 2000; and the
consolidated financial statements of Oasis Pipe Line Company as of December 27,
2002 and the period then ended; and the combined financial statements of Energy
Transfer Company as of August 31, 2003 and for the eleven months then ended,
appearing in this prospectus supplement have been audited by Ernst & Young LLP,
independent auditors, as set forth in their reports thereon appearing elsewhere
herein, and are included in reliance upon such reports given on the authority of
such firm as experts in accounting and auditing. The audit report covering the
consolidated financial statements of Aquila Gas Pipeline Corporation and
Subsidiaries as of September 30, 2002 and December 31, 2001, and for the periods
ended September 30, 2002 and December 31, 2001 and 2000 refers to a change in
accounting for goodwill and other intangible assets.
56
The consolidated financial statements of Oasis Pipe Line Company and
subsidiaries as of December 31, 2001 and for the years ended December 31, 2001
and 2000 incorporated in this prospectus by reference from the Current Report on
Form 8-K of Heritage Propane Partners, L.P. dated December 17, 2003 have been
audited by Deloitte & Touche LLP, independent auditors, as stated in their
report, which is incorporated herein by reference, and have been so incorporated
in reliance upon the report of such firm given upon their authority as experts
in accounting and auditing.
WHERE YOU CAN FIND MORE INFORMATION
We have filed a registration statement with the SEC under the Securities
Act of 1933 that registers the securities offered by this prospectus. The
registration statement, including the attached exhibits, contains additional
relevant information about us. The rules and regulations of the SEC allow us to
omit some information included in the registration statement from this
prospectus.
In addition, we file annual, quarterly and other reports and other
information with the SEC. You may read and copy any document we file at the
SEC's public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549.
Please call the SEC at 1-800-732-0330 for further information on the operation
of the SEC's public reference room. Our SEC filings are available on the SEC's
web site at http://www.sec.gov. We also make available free of charge on our
website, at http://www.heritagepropane.com, all materials that we file
electronically with the SEC, including our annual report on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K, Section 16 reports and
amendments to these reports as soon as reasonably practicable after such
materials are electronically filed with, or furnished to, the SEC. Additionally,
you can obtain information about us through the New York Stock Exchange, 20
Broad Street, New York, New York 10005, on which our common units are listed.
The SEC allows us to "incorporate by reference" the information we have
filed with the SEC. This means that we can disclose important information to you
without actually including the specific information in this prospectus by
referring you to other documents filed separately with the SEC. These other
documents contain important information about us, our financial condition and
results of operations. The information incorporated by reference is an important
part of this prospectus. Information that we file later with the SEC will
automatically update and may replace information in this prospectus and
information previously filed with the SEC.
We incorporate by reference in this prospectus the documents listed below:
- our annual report on Form 10-K for the year ended August 31, 2003;
- our current reports on Form 8-K filed January 6, 2003, March 18, 2003,
December 1, 2003, December 10, 2003, December 15, 2003, December 17, 2003
and December 19, 2003;
- the description of our common units in our registration statement on Form
8-A (File No. 1-11727) filed pursuant to the Securities Exchange Act of
1934 on May 16, 1996; and
- all documents filed by us under Sections 13(a), 13(c), 14 or 15(d) of the
Securities Exchange Act of 1934 between the date of this prospectus and
the termination of the registration statement.
You may obtain any of the documents incorporated by reference in this
prospectus from the SEC through the SEC's website at the address provided above.
You also may request a copy of any document incorporated by reference in this
prospectus (including exhibits to those documents specifically incorporated by
reference in this document), at no cost, by visiting our internet website at
www.heritagepropane.com, or by writing or calling us at the following address:
Heritage Propane Partners, L.P.
8801 South Yale Avenue, Suite 310
Tulsa, Oklahoma 74137
Attention: Michael L. Greenwood
Telephone: (918) 492-7272
57
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
(Heritage Propane color logo)
7,000,000 COMMON UNITS
REPRESENTING LIMITED PARTNER INTERESTS
------------
PROSPECTUS SUPPLEMENT
JANUARY , 2004
------------
CITIGROUP
LEHMAN BROTHERS
UBS INVESTMENT BANK
A.G. EDWARDS & SONS, INC.
WACHOVIA SECURITIES
CREDIT SUISSE FIRST BOSTON
RBC CAPITAL MARKETS
RAYMOND JAMES
STEPHENS INC.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
Set forth below are the expenses (other than underwriting discounts and
commissions) expected to be incurred in connection with the issuance and
distribution of the securities registered hereby. With the exception of the
Securities and Exchange Commission registration fee, the amounts set forth below
are estimates:
<Table>
Securities and Exchange Commission registration fee......... $ 78,949
Legal fees and expenses..................................... $175,000
Accounting fees and expenses................................ $ 50,000
Printing and engraving expenses............................. $ 75,000
Trustee's fees.............................................. $ 15,000
Miscellaneous............................................... $ 6,051
--------
TOTAL....................................................... $400,000
========
</Table>
ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Heritage Propane Partners, L.P. and Heritage Operating, L.P.
The partnership agreements of each of Heritage Propane Partners, L.P. and
Heritage Operating, L.P. provide that each partnership, as applicable, will
indemnify (i) its respective general partner, any departing partner (as defined
therein), any person who is or was an affiliate of its respective general
partner or any departing partner, (ii) any person who is or was a director,
officer, employee, agent or trustee of the partnerships, (iii) any person who is
or was an officer, director, employee, agent or trustee of its respective
general partner or any departing partner or any affiliate of its respective
general partner or any departing partner, or (iv) any person who is or was
serving at the request of its respective general partner or any departing
partner or any affiliate of its respective general partner or any departing
partner as an officer, director, employee, partner, agent, fiduciary or trustee
of another person (each, an "Indemnitee"), to the fullest extent permitted by
law, from and against any and all losses, claims, damages, liabilities (joint
and 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 any of the foregoing; provided that in each case the Indemnitee
acted in good faith and in a manner that such Indemnitee reasonably believed to
be in or not opposed to the best interests of each 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 each of the partnerships, and the respective general partner shall not
be personally liable for, or have any obligation to contribute or loan funds or
assets to each applicable partnership to enable it to effectuate, such
indemnification. Each partnership is authorized to purchase (or to reimburse the
general partner or its affiliates for the cost of) insurance against liabilities
asserted against and expenses incurred by such persons in connection with each
of the partnerships' activities, regardless of whether each of the partnerships
would have the power to indemnify such person against such liabilities under the
provisions described above.
Heritage Service Corp.
Delaware law permits a corporation to adopt a provision in its certificate
of incorporation eliminating or limiting the personal liability of a director,
but not an officer in his or her capacity as such, to the corporation or its
stockholders for monetary damages for breach of fiduciary duty as a director,
except that such provision shall not limit the liability of a director for (i)
any breach of the director's duty of loyalty
II-1
to the corporation or its stockholders, (ii) acts or omissions not in good faith
or that involve intentional misconduct or a knowing violation of law, (iii)
liability under section 174 of the Delaware General Corporation Law for unlawful
payment of dividends or stock purchases or redemptions, or (iv) any transaction
from which the director derived an improper personal benefit. Heritage Service
Corp.'s Certificate of Incorporation provides that, to the fullest extent of
Delaware law, no Heritage Service Corp. director shall be liable to Heritage
Service Corp. or Heritage Service Corp. stockholders for monetary damages for
breach of fiduciary duty as a director.
Under Delaware law, a corporation may indemnify any individual made a party
or threatened to be made a party to any type of proceeding, other than an action
by or in the right of the corporation, because he or she is or was an officer,
director, employee or agent of the corporation or was serving at the request of
the corporation as an officer, director, employee or agent of another
corporation or entity against expenses, judgments, fines and amounts paid in
settlement actually and reasonably incurred in connection with such proceeding:
(i) if he or she acted in good faith and in a manner he or she reasonably
believed to be in or not opposed to the best interests of the corporation; or
(ii) in the case of a criminal proceeding, he or she had no reasonable cause to
believe that his or her conduct was unlawful. A corporation may indemnify any
individual made a party or threatened to be made a party to any threatened,
pending or completed action or suit brought by or in the right of the
corporation because he or she was an officer, director, employee or agent of the
corporation, or is or was serving at the request of the corporation as a
director, officer, employee or agent of another corporation or other entity,
against expenses actually and reasonably incurred in connection with such action
or suit if he or she acted in good faith and in a manner he or she reasonably
believed to be in or not opposed to the best interests of the corporation,
provided that such indemnification will be denied if the individual is found
liable to the corporation unless, in such a case, the court determines the
person is nonetheless entitled to indemnification for such expenses. A
corporation must indemnify a present or former director or officer who
successfully defends himself or herself in a proceeding to which he or she was a
party because he or she was a director or officer of the corporation against
expenses actually and reasonably incurred by him or her. Expenses incurred by an
officer or director, or any employees or agents as deemed appropriate by the
board of directors, in defending civil or criminal proceedings may be paid by
the corporation in advance of the final disposition of such proceedings upon
receipt of an undertaking by or on behalf of such director, officer, employee or
agent to repay such amount if it shall ultimately be determined that he or she
is not entitled to be indemnified by the corporation. The Delaware law regarding
indemnification and expense advancement is not exclusive of any other rights
which may be granted by Heritage Service Corp.'s Certificate of Incorporation or
Bylaws, a vote of stockholders or disinterested directors, agreement or
otherwise.
Under the Delaware General Corporation Law, termination of any proceeding
by conviction or upon a plea of nolo contendere or its equivalent shall not, of
itself, create a presumption that such person is prohibited from being
indemnified.
The Bylaws of Heritage Service Corp. provide for the indemnification and
advancement of expenses of any individual made, or threatened to be made, a
party to an action, suit or proceeding, whether civil, criminal, administrative
or investigative, by reason of the fact that he or she is or was a director or
officer of Heritage Service Corp. or is or was a director or officer of Heritage
Service Corp. serving as an officer or director, employee or agent of any other
enterprise at the request of Heritage Service Corp. Heritage Service Corp.'s
bylaws provide for such indemnification and advancement of expenses if such
officer or director acted in good faith and in a manner he or she reasonably
believed to be in or not opposed to the best interests of Heritage Service Corp.
and, with respect to any criminal action or proceeding, had no reasonable cause
to believe his or her conduct was unlawful.
Heritage-Bi State, L.L.C.
Under the Delaware Limited Liability Company Act, a limited liability
company may, and shall have the power to, indemnify and hold harmless any member
or manager or other person from and against any and all claims and demands
whatsoever.
II-2
The Amended and Restated Agreement of Limited Liability Company of
Heritage-Bi State, L.L.C. provides that a member shall not be liable to
Heritage-Bi State, L.L.C. for any act or omission based upon errors of judgment
in connection with the business or affairs of Heritage-Bi State, L.L.C. if such
member's conduct does not constitute gross negligence or willful misconduct.
Furthermore, the Amended and Restated Agreement of Limited Liability Company of
Heritage-Bi State, L.L.C. provides that a member shall be indemnified by
Heritage-Bi State, L.L.C., to the fullest extent permitted by law, from and
against any and all losses, claims, damages and settlements arising from any and
all claims, demands, actions, suits or proceedings, whether civil, criminal,
administrative or investigative, in which the member is involved, as a party or
otherwise, by reason of the management of the affairs of Heritage-Bi State,
L.L.C. or the fact that such member is or was an agent of Heritage-Bi State,
L.L.C., provided that no member shall be entitled to indemnification for such
losses, claims, damages and settlements arising as a result of the gross
negligence or willful misconduct of such member.
Heritage Energy Resources, L.L.C.
Under the Oklahoma Limited Liability Company Act, a limited liability
company may (i) limit or eliminate the personal liability of a manager for
monetary damages for breach of any duty under the Oklahoma Limited Liability
Company Act or (ii) provide for indemnification of a manager for judgments,
settlements, penalties, fines or expenses incurred in any proceeding because
such manager is or was a manager of the limited liability company, except, in
either case, for any breach of a manager's duty of loyalty or any acts or
omissions not in good faith or which involve intentional misconduct or a knowing
violation of law.
The Operating Agreement of Heritage Energy Resources, L.L.C. provides
indemnification and eliminates liability for each manager or officer of Heritage
Energy Resources, L.L.C. from any and all monetary damages, claims, demands and
actions of every kind and nature whatsoever which may arise by reason of a
manager's or officer's performance of his or her duties and responsibilities,
except (i) for liabilities arising as a result of a breach of the manager's or
officer's duty of loyalty to Heritage Energy Resources, L.L.C. or its members,
(ii) for acts or omissions not in good faith or which involve intentional
misconduct or a knowing violation of the law, (iii) for any transaction from
which the manager or officer derived an improper personal benefit and (iv) with
respect to indemnification, a breach of any provision of Heritage Energy
Resources, L.L.C.'s Operating Agreement.
Any underwriting agreement entered into in connection with the sale of the
securities offered pursuant to this registration statement will provide for
indemnification of officers, directors, members or managers of the general
partner, Heritage Service Corp., Heritage-Bi State, L.L.C. and Heritage Energy
Resources, L.L.C., including liabilities under the Securities Act.
II-3
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Exhibits. The following documents are filed as exhibits to this
registration:
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
1.1* Form of Underwriting Agreement.
4.1 Amended and Restated Agreement of Limited Partnership of
Heritage Propane Partners, L.P. (incorporated by reference
to Exhibit 3.1 to Heritage Propane Partners, L.P.'s
Registration Statement on Form S-1, filed on June 21, 1996).
4.2 Amendment No. 1 to Amended and Restated Agreement of Limited
Partnership of Heritage Propane Partners, L.P. (incorporated
by reference to Exhibit 3.1.1 to Heritage Propane Partners,
L.P.'s Current Report on Form 8-K dated August 23, 2000).
4.3 Amendment No. 2 to Amended and Restated Agreement of Limited
Partnership of Heritage Propane Partners, L.P. (incorporated
by reference to Exhibit 3.1.2 to Heritage Propane Partners,
L.P.'s Annual Report on Form 10-K for the year ended August
31, 2001).
4.4 Amendment No. 3 to Amended and Restated Agreement of Limited
Partnership of Heritage Propane Partners, L.P. (incorporated
by reference to Exhibit 3.1.3 to Heritage Propane Partners,
L.P.'s Quarterly Report on Form 10-Q for the quarter ended
May 31, 2002).
4.5 Amendment No. 4 to Amended and Restated Agreement of Limited
Partnership of Heritage Propane Partners, L.P. (incorporated
by reference to Exhibit 3.1.4 to Heritage Propane Partners,
L.P.'s Quarterly Report on Form 10-Q for the quarter ended
May 31, 2002).
4.6*** Form of Amendment No. 5 to Amended and Restated Agreement of
Limited Partnership of Heritage Propane Partners, L.P.
4.7 Amended and Restated Agreement of Limited Partnership of
Heritage Operating, L.P. (incorporated by reference to
Exhibit 3.2 to Heritage Propane Partners, L.P.'s
Registration Statement on Form S-1, filed on June 21, 1996).
4.8 Amendment No. 1 to Amended and Restated Agreement of Limited
Partnership of Heritage Operating, L.P. (incorporated by
reference to Exhibit 3.2.1 to Heritage Propane Partners,
L.P.'s Annual Report on Form 10-K for the year ended August
31, 2000).
4.9 Amendment No. 2 to Amended and Restated Agreement of Limited
Partnership of Heritage Operating, L.P. (incorporated by
reference to Exhibit 3.2.2 to Heritage Propane Partners,
L.P.'s Quarterly Report on Form 10-Q for the quarter ended
May 31, 2002).
4.10*** Form of Amendment No. 3 to Amended and Restated Agreement of
Limited Partnership of Heritage Operating, L.P.
4.11** Form of Senior Indenture of Heritage Propane Partners, L.P.
4.12** Form of Subordinated Indenture of Heritage Propane Partners,
L.P.
4.13** Form of Senior Indenture of Heritage Operating, L.P.
4.14** Form of Subordinated Indenture of Heritage Operating, L.P.
5.1*** Opinion of Vinson & Elkins L.L.P. as to the legality of the
securities registered hereby.
5.2** Opinion of Doerner, Saunders, Daniel & Anderson, L.L.P. as
to the legality of the securities registered hereby.
8.1*** Opinion of Vinson & Elkins L.L.P. as to tax matters.
10.1 Acquisition Agreement dated November 6, 2003 among the
owners of U.S. Propane, L.P. and U.S. Propane, L.L.C. and La
Grange Energy, L.P. (incorporated by reference to Exhibit
10.30 to Heritage Propane Partners, L.P.'s Annual Report on
Form 10-K for the year ended August 31, 2003).
10.2 Contribution Agreement dated November 6, 2003 among La
Grange Energy, L.P. and Heritage Propane Partners, L.P. and
U.S. Propane, L.P. (incorporated by reference to Exhibit
10.31 to Heritage Propane Partners, L.P.'s Annual Report on
Form 10-K for the year ended August 31, 2003).
</Table>
II-4
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.3** Amendment No. 1 dated December 7, 2003 to Contribution
Agreement dated November 6, 2003 among La Grange Energy,
L.P. and Heritage Propane Partners, L.P. and U.S. Propane,
L.P.
10.4 Stock Purchase Agreement dated November 6, 2003 among the
owners of Heritage Holdings, Inc. and Heritage Propane
Partners, L.P. (incorporated by reference to Exhibit 10.32
to Heritage Propane Partners, L.P.'s Annual Report on Form
10-K for the year ended August 31, 2003).
12.1** Computation of ratio of earnings to fixed charges.
23.1*** Consent of Vinson & Elkins L.L.P. (included in Exhibits 5.1
and 8.1).
23.2** Consent of Doerner, Saunders, Daniel & Anderson, L.L.P.
(included in Exhibit 5.2).
23.3*** Consent of Grant Thornton LLP.
23.4*** Consent of Ernst & Young LLP.
23.5** Consent of Ray C. Davis.
23.6** Consent of Kelcy L. Warren.
23.7*** Consent of Deloitte & Touche LLP.
23.8*** Consent of David R. Albin.
23.9*** Consent of Kenneth A. Hersh.
24.1** Power of Attorney.
25.1* Form T-1 Statement of Eligibility and Qualification
respecting the Senior Indenture of Heritage Propane
Partners, L.P.
25.2* Form T-1 Statement of Eligibility and Qualification
respecting the Subordinated Indenture of Heritage Propane
Partners, L.P.
25.3* Form T-1 Statement of Eligibility and Qualification
respecting the Senior Indenture of Heritage Operating, L.P.
25.4* Form T-1 Statement of Eligibility and Qualification
respecting the Subordinated Indenture of Heritage Operating,
L.P.
99.1 Balance sheet of U.S. Propane, L.P. (incorporated by
reference to Exhibit 99.1 to Heritage Propane Partners,
L.P.'s Annual Report on Form 10-K for the year ended August
31, 2003).
99.2 Balance Sheet of U.S. Propane, L.L.C. (incorporated by
reference to Exhibit 99.3 to Heritage Propane Partners,
L.P.'s Annual Report on Form 10-K for the year ended August
31, 2003).
</Table>
- ---------------
* To be filed by a post-effective amendment to this registration statement or
as an exhibit to a current report on Form 8-K.
** Previously filed.
*** Filed herewith.
**** To be filed by amendment.
(b) Financial Statement Schedules
No financial statement schedules are included herein. All other schedules
for which provision is made in the applicable accounting regulations of the
Securities and Exchange Commission are not required under the related
instructions, are inapplicable, or the information is included in the
consolidated financial statements, and have therefore been omitted.
(c) Reports, Opinions, and Appraisals
The following reports, opinions, and appraisals are included herein: None.
II-5
ITEM 17. UNDERTAKINGS
I. Each of the undersigned registrants hereby undertakes:
To file, during any period in which offers or sales are being made, a
post-effective amendment to this registration statement:
(a) To include any prospectus required by section 10(a)(3) of the
Securities Act of 1933;
(b) 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. Notwithstanding the foregoing, any
increase or decrease in volume of securities offered (if the total
dollar value of securities offered would not exceed that which was
registered) and any deviation from the low or high end of the estimated
maximum offering range may be reflected in the form of prospectus filed
with the Commission pursuant to Rule 424(b) if, in the aggregate, the
changes in volume and price represent no more than a 20% change in the
maximum aggregate offering price set forth in the "Calculation of
Registration Fee" table in the effective registration statement;
(c) 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;
Provided, however, that paragraphs (a) and (b) above do not apply if
the information required to be included in a post-effective amendment by
those paragraphs is contained in periodic reports filed with or furnished
to the Commission by the registrant pursuant to section 13 or section 15(d)
of the Securities Exchange Act of 1934 that are incorporated by reference
in the registration statement.
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.
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.
(1) For purposes of determining any liability under the Securities
Act, the information omitted from the form of prospectus filed as part of
this registration statement in reliance upon Rule 430A and contained in a
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.
II. Each undersigned registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
registrant's annual report pursuant to section 13(a) or section 15(d) of the
Securities Exchange Act of 1934 (and, where applicable, each filing of an
employee benefit plan's annual report pursuant to section 15(d) of the
Securities Exchange Act of 1934) that is incorporated by reference in the
registration statement 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.
III. Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and controlling
persons of any registrant pursuant to the provisions described in Item 15 above,
or otherwise, the registrant has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public policy
as expressed in the Securities Act of 1933 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
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director, officer or controlling person in connection with the securities being
registered, each 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 Securities Act of 1933 and will be
governed by the final adjudication of such issue.
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended,
each of the registrants certifies that it has reasonable grounds to believe that
it meets all of the requirements for filing on Form S-3 and has duly caused this
Registration Statement to be signed on its behalf by the undersigned, thereunto
duly authorized, in the City of Tulsa, State of Oklahoma, on January 8, 2004.
HERITAGE PROPANE PARTNERS, L.P.
By: U.S. PROPANE, L.P.
its General Partner
By: U.S. PROPANE, L.L.C.
its General Partner
By: /s/ MICHAEL L. GREENWOOD
---------------------------------
Name: Michael L. Greenwood
Title: Vice President and
Chief Financial
Officer
HERITAGE OPERATING, L.P.
By: U.S. PROPANE, L.P.
its General Partner
By: U.S. PROPANE, L.L.C.
its General Partner
By: /s/ MICHAEL L. GREENWOOD
---------------------------------
Name: Michael L. Greenwood
Title: Vice President and
Chief Financial
Officer
HERITAGE SERVICE CORP.
By: /s/ MICHAEL L. GREENWOOD
------------------------------------
Name: Michael L. Greenwood
Title: Vice President and Chief
Financial Officer
HERITAGE-BI STATE, L.L.C.
By: /s/ MICHAEL L. GREENWOOD
------------------------------------
Name: Michael L. Greenwood
Title: Vice President and Chief
Financial Officer
HERITAGE ENERGY RESOURCES, L.L.C.
By: /s/ MICHAEL L. GREENWOOD
------------------------------------
Name: Michael L. Greenwood
Title: Vice President and Chief
Financial Officer
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Pursuant to the requirements of the Securities Act of 1933, as amended,
this Registration Statement has been signed below by the following persons in
the capacities and on the dates indicated below.
<Table>
<Caption>
SIGNATURE TITLE DATE
--------- ----- ----
/s/ H. MICHAEL KRIMBILL (i) President and Chief January 8, 2004
- -------------------------------------- Executive Officer (Principal
H. Michael Krimbill Executive Officer) of U.S.
Propane, L.L.C., Heritage
Service Corp., Heritage-Bi
State, L.L.C. and Heritage
Energy Resources, L.L.C., (ii)
Director of U.S. Propane L.L.C.
and Heritage Service Corp. and
(iii) Manager of Heritage
Energy Resources, L.L.C.
* Chairman of the Board and January 8, 2004
- -------------------------------------- Director of U.S. Propane,
James E. Bertelsmeyer L.L.C.
/s/ MICHAEL L. GREENWOOD (i) Vice President and Chief January 8, 2004
- -------------------------------------- Financial Officer (Principal
Michael L. Greenwood Financial and Accounting
Officer) of U.S. Propane,
L.L.C., Heritage Service Corp.,
Heritage-Bi State, L.L.C. and
Heritage Energy Resources,
L.L.C. and (ii) Manager of
Heritage Energy Resources,
L.L.C.
* Director of U.S. Propane, January 8, 2004
- -------------------------------------- L.L.C.
Bill W. Byrne
* Director of U.S. Propane, January 8, 2004
- -------------------------------------- L.L.C.
J. Charles Sawyer
* Director of U.S. Propane, January 8, 2004
- -------------------------------------- L.L.C.
Stephen L. Cropper
* Director of U.S. Propane, January 8, 2004
- -------------------------------------- L.L.C.
J. Patrick Reddy
* Director of U.S. Propane, January 8, 2004
- -------------------------------------- L.L.C.
Royston K. Eustace
* Director of U.S. Propane, January 8, 2004
- -------------------------------------- L.L.C.
William N. Cantrell
* Director of U.S. Propane, January 8, 2004
- -------------------------------------- L.L.C.
Kevin M. O'Hara
</Table>
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<Table>
<Caption>
SIGNATURE TITLE DATE
--------- ----- ----
* Director of U.S. Propane, January 8, 2004
- -------------------------------------- L.L.C.
Andrew W. Evans
* Director of U.S. Propane, January 8, 2004
- -------------------------------------- L.L.C.
Richard T. O'Brien
*By: /s/ MICHAEL L. GREENWOOD
------------------------------
Michael L. Greenwood
Attorney-in-Fact
</Table>
U.S. Propane, L.L.C. is the general partner of U.S. Propane, L.P., the
general partner of each of Heritage Propane Partners, L.P. and Heritage
Operating, L.P. Heritage Propane Partners, L.P. and Heritage Operating, L.P. are
the only members of Heritage-Bi State, L.L.C.
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INDEX TO EXHIBITS
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
1.1* Form of Underwriting Agreement.
4.1 Amended and Restated Agreement of Limited Partnership of
Heritage Propane Partners, L.P. (incorporated by reference
to Exhibit 3.1 to Heritage Propane Partners, L.P.'s
Registration Statement on Form S-1, filed on June 21, 1996).
4.2 Amendment No. 1 to Amended and Restated Agreement of Limited
Partnership of Heritage Propane Partners, L.P. (incorporated
by reference to Exhibit 3.1.1 to Heritage Propane Partners,
L.P.'s Current Report on Form 8-K dated August 23, 2000).
4.3 Amendment No. 2 to Amended and Restated Agreement of Limited
Partnership of Heritage Propane Partners, L.P. (incorporated
by reference to Exhibit 3.1.2 to Heritage Propane Partners,
L.P.'s Annual Report on Form 10-K for the year ended August
31, 2001).
4.4 Amendment No. 3 to Amended and Restated Agreement of Limited
Partnership of Heritage Propane Partners, L.P. (incorporated
by reference to Exhibit 3.1.3 to Heritage Propane Partners,
L.P.'s Quarterly Report on Form 10-Q for the quarter ended
May 31, 2002).
4.5 Amendment No. 4 to Amended and Restated Agreement of Limited
Partnership of Heritage Propane Partners, L.P. (incorporated
by reference to Exhibit 3.1.4 to Heritage Propane Partners,
L.P.'s Quarterly Report on Form 10-Q for the quarter ended
May 31, 2002).
4.6*** Form of Amendment No. 5 to Amended and Restated Agreement of
Limited Partnership of Heritage Propane Partners, L.P.
4.7 Amended and Restated Agreement of Limited Partnership of
Heritage Operating, L.P. (incorporated by reference to
Exhibit 3.2 to Heritage Propane Partners, L.P.'s
Registration Statement on Form S-1, filed on June 21, 1996).
4.8 Amendment No. 1 to Amended and Restated Agreement of Limited
Partnership of Heritage Operating, L.P. (incorporated by
reference to Exhibit 3.2.1 to Heritage Propane Partners,
L.P.'s Annual Report on Form 10-K for the year ended August
31, 2000).
4.9 Amendment No. 2 to Amended and Restated Agreement of Limited
Partnership of Heritage Operating, L.P. (incorporated by
reference to Exhibit 3.2.2 to Heritage Propane Partners,
L.P.'s Quarterly Report on Form 10-Q for the quarter ended
May 31, 2002).
4.10*** Form of Amendment No. 3 to Amended and Restated Agreement of
Limited Partnership of Heritage Operating, L.P.
4.11** Form of Senior Indenture of Heritage Propane Partners, L.P.
4.12** Form of Subordinated Indenture of Heritage Propane Partners,
L.P.
4.13** Form of Senior Indenture of Heritage Operating, L.P.
4.14** Form of Subordinated Indenture of Heritage Operating, L.P.
5.1*** Opinion of Vinson & Elkins L.L.P. as to the legality of the
securities registered hereby.
5.2** Opinion of Doerner, Saunders, Daniel & Anderson, L.L.P. as
to the legality of the securities registered hereby.
8.1*** Opinion of Vinson & Elkins L.L.P. as to tax matters.
10.1 Acquisition Agreement dated November 6, 2003 among the
owners of U.S. Propane, L.P. and U.S. Propane, L.L.C. and La
Grange Energy, L.P. (incorporated by reference to Exhibit
10.30 to Heritage Propane Partners, L.P.'s Annual Report on
Form 10-K for the year ended August 31, 2003).
10.2 Contribution Agreement dated November 6, 2003 among La
Grange Energy, L.P. and Heritage Propane Partners, L.P. and
U.S. Propane, L.P. (incorporated by reference to Exhibit
10.31 to Heritage Propane Partners, L.P.'s Annual Report on
Form 10-K for the year ended August 31, 2003).
10.3** Amendment No. 1 dated December 7, 2003 to Contribution
Agreement dated November 6, 2003 among La Grange Energy,
L.P. and Heritage Propane Partners, L.P. and U.S. Propane,
L.P.
</Table>
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<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.4 Stock Purchase Agreement dated November 6, 2003 among the
owners of Heritage Holdings, Inc. and Heritage Propane
Partners, L.P. (incorporated by reference to Exhibit 10.32
to Heritage Propane Partners, L.P.'s Annual Report on Form
10-K for the year ended August 31, 2003).
12.1** Computation of ratio of earnings to fixed charges.
23.1*** Consent of Vinson & Elkins L.L.P. (included in Exhibits 5.1
and 8.1).
23.2** Consent of Doerner, Saunders, Daniel & Anderson, L.L.P.
(included in Exhibit 5.2).
23.3*** Consent of Grant Thornton LLP.
23.4*** Consent of Ernst & Young LLP.
23.5** Consent of Ray C. Davis
23.6** Consent of Kelcy L. Warren
23.7*** Consent of Deloitte & Touche LLP.
23.8*** Consent of David R. Albin
23.9*** Consent of Kenneth A. Hersh
24.1** Power of Attorney.
25.1* Form T-1 Statement of Eligibility and Qualification
respecting the Senior Indenture of Heritage Propane
Partners, L.P.
25.2* Form T-1 Statement of Eligibility and Qualification
respecting the Subordinated Indenture of Heritage Propane
Partners, L.P.
25.3* Form T-1 Statement of Eligibility and Qualification
respecting the Senior Indenture of Heritage Operating, L.P.
25.4* Form T-1 Statement of Eligibility and Qualification
respecting the Subordinated Indenture of Heritage Operating,
L.P.
99.1 Balance sheet of U.S. Propane, L.P. (incorporated by
reference to Exhibit 99.1 to Heritage Propane Partners,
L.P.'s Annual Report on Form 10-K for the year ended August
31, 2003).
99.2 Balance Sheet of U.S. Propane, L.L.C. (incorporated by
reference to Exhibit 99.3 to Heritage Propane Partners,
L.P.'s Annual Report on Form 10-K for the year ended August
31, 2003).
</Table>
- ---------------
* To be filed by a post-effective amendment to this registration statement or
as an exhibit to a current report on Form 8-K.
** Previously filed.
*** Filed herewith.
**** To be filed by amendment.
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