UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
--------------
FORM 8-K
CURRENT REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): November 7, 2003
COMMISSION FILE NO. 1-11727
HERITAGE PROPANE PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 73-1493906
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
8801 SOUTH YALE AVENUE, SUITE 310, TULSA, OKLAHOMA 74137
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)
(918) 492-7272
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
ITEM 2. ACQUISITION OR DISPOSITION OF ASSETS
On November 7, 2003, we publicly announced the signing of definitive
agreements to combine our operations with those of La Grange Energy, L.P., a
company 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. We refer to Energy Transfer Company as
Energy Transfer. Energy Transfer's assets are primarily located in major natural
gas producing regions of Texas and Oklahoma.
We are filing this current report on Form 8-K in order to provide
additional information regarding this transaction, including information
relating to the terms of the transaction, information relating to the business
of Energy Transfer, historical financial information relating to Energy Transfer
and related entities and pro forma financial statements that give effect to this
transaction. This information is being filed at this time in part in order to
update our Registration Statement on Form S-4 as filed with the Securities and
Exchange Commission on November 17, 1997 (Registration No. 333-40407) pursuant
to which we issue common units from time to time in connection with
acquisitions.
THE TRANSACTION
The value of this transaction is approximately $987 million based on
the average market price of our common units for the 45 trading days prior to
the time we signed the agreements related to the transaction. The agreements
related to the transaction provide for the following to occur at the closing of
this transaction:
o La Grange Energy will contribute its interest in Energy Transfer and
certain related assets to us in exchange for the following
consideration:
o 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;
o the retirement at closing of Energy Transfer's then outstanding
debt;
o the assumption at closing of Energy Transfer's then existing
accounts payable and other specified liabilities;
o 12,140,719 of our common units and class D units; and
o 3,742,515 special units.
o 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.
o 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.
This transaction has not closed and is subject to a number of closing
conditions, including the incurrence of new borrowings by Energy Transfer of not
less than $275 million and the receipt by us of net proceeds of not less than
$250 million from public offering of our common units. We expect this
transaction to close in January 2004.
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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.
3
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.
- 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.
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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
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.
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 1,050
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.
5
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.
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.
6
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.
THE TRANSPORTATION SEGMENT
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
7
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 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.
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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 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.
9
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 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. The FERC has
proposed rules that would 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. The FERC has proposed that 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. We cannot predict the outcome of this proceeding, 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.
10
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 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
11
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 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
12
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 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.
13
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.
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.
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.
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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.
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.
15
RISK FACTORS RELATING TO ENERGY TRANSFER
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;
- 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.
16
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.
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
17
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 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
18
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 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 4,094,798 common units, 8,045,921 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
19
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 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 "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.
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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 "Energy Transfer -- Environmental Matters."
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. 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.
21
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.
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.
22
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.
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.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS OF ENERGY TRANSFER
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.
23
- 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 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
24
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.
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.
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.
25
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.
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
26
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 OF 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 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%.
27
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.
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
28
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.
ENERGY TRANSFER LIQUIDITY AND CAPITAL RESOURCES
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 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
29
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.
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 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.
ENERGY TRANSFER CONTRACTUAL OBLIGATIONS
The following table summarizes Energy Transfer's long-term debt and other
contractual obligations as of August 31, 2003:
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 $ --
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.
30
ENERGY TRANSFER CRITICAL ACCOUNTING POLICIES
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
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.
31
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.
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.
ENERGY TRANSFER QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.
32
The following summarizes Energy Transfer's open commodity derivative
positions:
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
==========
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
==========
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.
33
IMPACT OF ENERGY TRANSFER TRANSACTION ON MANAGEMENT
MANAGEMENT OF HERITAGE PROPANE PARTNERS PRIOR TO ENERGY TRANSFER TRANSACTION
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.
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
---------------
(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.
34
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
35
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
36
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:
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
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. In addition, we have been advised by
La Grange Energy, the proposed purchaser of our general partner, that four
additional directors will be appointed to the Board of Directors of our general
partner following the closing of the Energy Transfer transaction. Finally, 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.
Set forth below is biographical information regarding the additional
persons who are expected to become officers 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 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
37
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.
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.
38
DESCRIPTION OF UNITS AFTER ENERGY TRANSFER TRANSACTION
The following is a description of our existing units as well as the units
that will be outstanding following consummation of the Energy Transfer
transaction.
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. However, 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."
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 incentive distribution rights
that Heritage Holdings and its former stockholders would have been entitled to.
39
CLASS D UNITS
The class D units generally have voting rights that are identical to the
voting rights of the common units and 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, but only after the payment of
distributions on the common units. 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.
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. 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
4,426,196 class E units. The class E units generally do not have any voting
rights but are entitled to vote on the proposal to make 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. The class E units will not be entitled to any
distributions upon our dissolution and liquidation.
SPECIAL UNITS
The special units are being issued by us as consideration for the Bossier
Pipeline. The special units generally do not have any voting rights but are
entitled to vote on the proposal to make special units convertible to common
units, 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 "Energy
Transfer" relating to the Bossier Pipeline. If, however, our unitholders do not
approve the conversion of the special units into common units, 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.
40
CASH DISTRIBUTION POLICY AFTER ENERGY TRANSFER TRANSACTION
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 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;
-- 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
41
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.
42
ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND EXHIBITS
(a) Financial Statements of Business Proposed to be Acquired.
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 and Oasis Pipe Line Company.
Index to Financial Statements:
Energy Transfer Company
Report of Independent Auditor.............................. 44
Combined Balance sheet as of August 31, 2003............... 45
Combined Income Statement for the period from October 1,
2002 Through August 31, 2003............................ 46
Combined Statement of Partners' Capital for the period
from October 1, 2002 Through August 31, 2003............ 47
Combined Statement of Cash Flows for the Period from
October 1, 2002 Through August 31, 2003................. 48
Notes to Combined Financial Statements..................... 49
Aquila Gas Pipeline Corporation:
Report of Independent Auditors............................. 63
Consolidated Balance Sheets as of September 30, 2002 and
December 31, 2001....................................... 64
Consolidated Statements of Income for the Nine Months
Ended September 30, 2002 and the years ended
December 31, 2001 and 2000.............................. 65
Consolidated Statements of Stockholder's Equity for the
Nine Months Ended September 30, 2002 and the Years
ended December 31, 2001 and 2000........................ 66
Consolidated Statements of Cash Flows for the Nine Months
ended September 30, 2002 and the Years Ended
December 31, 2001 and 2000.............................. 67
Notes to Consolidated Financial Statements................. 68
Oasis Pipe Line Company:
Report of Independent Auditors............................. 82
Independent Auditors' Report............................... 83
Consolidated Balance Sheets as of December 27, 2002
and December 31, 2001 .................................. 84
Consolidated Statements of Income for the Period from
January 1, 2002 Through December 27, 2002 and the
Years Ended December 31, 2001 and 2000 ................. 85
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 ............................................... 86
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.................. 87
Notes to Consolidated Financial Statement.................. 88
43
ENERGY TRANSFER COMPANY
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
44
ENERGY TRANSFER COMPANY
COMBINED BALANCE SHEETS
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
========
See accompanying notes.
45
ENERGY TRANSFER COMPANY
COMBINED INCOME STATEMENTS
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
==========
See accompanying notes.
46
ENERGY TRANSFER COMPANY
COMBINED STATEMENT OF PARTNERS' CAPITAL
FOR THE ELEVEN MONTHS ENDED AUGUST 31, 2003
OPERATING
LA GRANGE 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
======== ==== === ========
See accompanying notes.
47
ENERGY TRANSFER COMPANY
COMBINED STATEMENTS OF CASH FLOWS
IN THOUSANDS
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
=========
See accompanying notes.
48
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
La Grange Acquisition, L.P. (La Grange Acquisition) 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 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.
49
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
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 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
50
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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.
51
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
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.
(IN THOUSANDS)
Interest.................................................... $8,486
Income Taxes................................................ $2,935
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.
52
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
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:
(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
========
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.
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).
(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
53
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
3. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment, at cost, consisted of the following:
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
========
4. INTANGIBLE ASSETS
As of August 31, 2003, intangibles, at cost, consisted of the following:
(IN THOUSANDS)
Deferred financing fees..................................... $ 5,724
Amortization................................................ (2,464)
-------
3,260
Other intangibles........................................... 477
Amortization................................................ (92)
-------
385
-------
Total intangibles........................................... $ 3,645
=======
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.
54
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The following is the scheduled amortization of intangibles for the next
five years:
IN THOUSANDS
2004........................................................ $2,404
2005........................................................ $ 918
2006........................................................ $ 82
2007........................................................ $ 48
2008........................................................ $ 48
Thereafter.................................................. $ 145
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 unaudited financial information related to the
Vantex investments for the 11 months ended August 31, 2003.
(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.................... --
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 Holdings, L.P. For the 11
months ended August 31, 2003, the rent charged to the Partnership was $90,000.
55
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
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:
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
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.
56
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
7. DEBT
Long-term debt consisted of the following as of August 31, 2003:
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
========
The scheduled maturities of long-term debt are as follows:
AUGUST 31,
2003
--------------
(IN THOUSANDS)
2004........................................................ $ 30,000
2005........................................................ 196,000
2006 and thereafter......................................... --
--------
Total....................................................... $226,000
========
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.
57
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:
(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
========
Components of Oasis Pipe Line's income tax provision/(benefit) attributable
to income before taxes, as of August 31, 2003, are as follows:
(IN THOUSANDS)
Current..................................................... $ 5,548
Deferred.................................................... (1,116)
-------
Total income tax expense.................................... $ 4,432
=======
Deferred tax liabilities of Oasis Pipe Line, as of August 31, 2003, consist
of the following:
(IN THOUSANDS)
Property, plant and equipment............................... $55,736
Other....................................................... (351)
-------
Net deferred tax liabilities................................ $55,385
=======
9. MAJOR CUSTOMERS
The Partnership had gross sales as a percentage of total revenues to
nonaffiliated major customers as follows:
ELEVEN MONTHS
ENDED
AUGUST 31,
2,003 S&P RATING
------------- ----------
Customer A.................................................. 18.85% A-
Customer B.................................................. 11.26% BBB
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
58
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:
IN THOUSANDS
2004........................................................ $920
2005........................................................ $927
2006........................................................ $390
2007........................................................ $ 6
2008........................................................ $ 1
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. 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
59
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
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.
60
ENERGY TRANSFER COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The following summarizes Energy Transfer's commodity derivative positions
at August 31, 2003:
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
==========
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
==========
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.
61
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:
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
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.
62
AQUILA GAS PIPELINE CORPORATION
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
63
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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
======== ========
See accompanying notes.
64
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
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
======== ========== ==========
See accompanying notes.
65
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
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
==== ===== ======= ======== ========
See accompanying notes.
66
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
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..................... $ -- $ -- $ --
======== ======== =========
See accompanying notes.
67
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:
DECEMBER 31,
SEPTEMBER 30, -----------------
2002 2001 2000
------------- ------ -------
(IN THOUSANDS)
Interest, net of amount capitalized.................... $3,308 $6,219 $10,511
68
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
69
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.
70
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.
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
======= =======
71
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:
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
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:
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
======= ========
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
72
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:
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
===== ======= =======
73
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:
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%
===== ===== ====
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:
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)
========= =========
5. MAJOR CUSTOMERS
The Company's gross sales as a percentage of total revenues to
nonaffiliated major customers were as follows:
DECEMBER 31,
SEPTEMBER 30, --------------
2002 2001 2000
------------- ----- -----
Customer A............................................... 17.5% 15.4% 11.9%
Customer B............................................... 9.6% 11.0% 8.4%
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.
74
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:
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
======= ======= =======
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:
(IN THOUSANDS)
2003........................................................ $775
2004........................................................ 775
2005........................................................ 773
2006........................................................ 64
2007 and thereafter......................................... --
75
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.
76
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
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
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)
77
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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)
DECEMBER 31, 2001
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
78
AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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)
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
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:
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
======= ======= ======= =======
79
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:
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
======== ========
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:
(IN THOUSANDS)
Remainder of 2002........................................... $ 840
2003........................................................ 1,990
2004........................................................ 91
2005........................................................ 91
2006........................................................ 91
2007........................................................ 91
Thereafter.................................................. 370
------
$3,564
======
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.
80
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:
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
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.
81
OASIS PIPE LINE COMPANY
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
82
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
83
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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
========= =========
See accompanying notes.
84
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
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
======= ======= =======
See accompanying notes.
85
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
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
===== == ===== ======== ======= ======== ========
See accompanying notes.
86
OASIS PIPE LINE COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
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
See accompanying notes.
87
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
88
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.
89
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:
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
====== ====== =======
The tax provision effective rate for December 27, 2002 and December 31,
2001 and 2000 was 35%.
Deferred income taxes consist of the following:
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)
======= =======
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.
90
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.
91
(b) Pro Forma Financial Information.
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.
Energy Transfer 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 the
year ended August 31, 2003, giving effect to the Energy Transfer Transaction and
the La Grange
92
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 report,
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 11 months ended August
31, 2003, contained elsewhere in this report, 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 report) 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.
93
HERITAGE PROPANE PARTNERS, L.P.
UNAUDITED PRO FORMA COMBINED BALANCE SHEET
AUGUST 31, 2003
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) $ 17,655
271,500(b)
250,000(c)
(369,220)(d)
(4,500)(e)
(50,000)(i)
(87,280)(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 3,360 1,505(f) 28,440
-------- -------- -------- --------- ----------
Total current assets................................ 183,770 94,138 4,311 (147,104) 135,115
PROPERTY, PLANT AND EQUIPMENT, net...................... 393,025 426,588 -- 2,000(a) 863,855
5,000(d)
37,242(g)
INVESTMENT IN AFFILIATES................................ 6,844 8,694 -- 2,415(g) 17,953
NOTE RECEIVABLE......................................... -- -- 11,539 (11,539)(h) --
INVESTMENT IN HERITAGE PROPANE.......................... -- -- 168,273 (168,273)(i) --
GOODWILL, net........................................... 13,409 156,595 -- 92,477(g) 262,481
INTANGIBLES AND OTHER ASSETS, net....................... 3,645 52,824 -- 3,500(b) 87,025
15,841(g)
11,215(g)
-------- -------- -------- --------- ----------
Total assets........................................ $600,693 $738,839 $184,123 $(157,226) $1,366,429
======== ======== ======== ========= ==========
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....................... -- 6,255 -- 1,505(f) 7,760
Current maturities of long-term debt.................. 30,000 38,309 -- (30,000)(d) 38,309
-------- -------- -------- --------- ----------
Total current liabilities......................... 168,063 151,027 767 (166,558) 153,299
LONG-TERM DEBT, less current maturities................. 196,000 360,762 -- 275,000(b) 685,762
(196,000)(d)
50,000(i)
MINORITY INTERESTS AND OTHER............................ 157 4,002 -- (157)(d) 647
(3,355)(j)
DEFERRED INCOME TAXES................................... 55,385 -- 103,930 -- 159,315
-------- -------- -------- --------- ----------
419,605 515,791 104,697 (41,070) 999,023
-------- -------- -------- --------- ----------
PARTNERS' CAPITAL:
General partner's capital............................. -- 2,190 -- (90)(e) 12,937
3,183(g)
3,355(j)
13,684(k)
(9,385)(l)
Limited partners' capital............................. 181,088 221,207 -- (157,109)(a) 365,905
250,000(c)
(3,329)(e)
117,763(g)
(9,407)(k)
(371,074)(l)
136,766(l)
Common stock.......................................... -- -- 5 (5)(i) --
Additional paid-in capital............................ -- -- 96,446 (11,539)(h) --
(84,907)(i)
Retained earnings..................................... -- -- (16,973) 16,973(i) --
Class D limited partners' capital..................... -- -- -- (1,081)(e) 188,898
38,244(g)
(4,277)(k)
(112,722)(l)
268,734(l)
Treasury units -- class E units....................... -- -- -- (200,334)(i) (200,334)
Other comprehensive income (loss)..................... -- (349) (52) 401(l) --
-------- -------- -------- --------- ----------
Total partners' capital........................... 181,088 223,048 79,426 (116,156) 367,406
-------- -------- -------- --------- ----------
Total liabilities and partners' capital........... $600,693 $738,839 $184,123 $(157,226) $1,366,429
======== ======== ======== ========= ==========
See accompanying notes.
94
HERITAGE PROPANE PARTNERS, L.P.
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
YEAR ENDED AUGUST 31, 2003
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 -- 1,241(m) 56,386
1,056(n)
134(o)
Selling, general and
administrative............... 17,842 14,037 -- (90)(o) 31,789
---------- -------- ------- -------- ----------
Total costs and expenses..... 1,068,914 501,283 435 2,341 1,572,973
---------- -------- ------- -------- ----------
OPERATING INCOME (LOSS)........... 74,050 70,193 (435) (2,341) 141,467
OTHER INCOME (EXPENSE):
Interest expense................ (13,770) (35,740) (80) (9,563)(p) (59,153)
Equity in earnings (losses) of
affiliates................... (251) 1,371 8,251 (8,251)(q) 1,120
Gain on disposal of assets...... -- 430 -- (181)(r) 249
Other........................... (302) (3,213) 2,777 (2,174)(s) (2,912)
---------- -------- ------- -------- ----------
INCOME BEFORE MINORITY INTEREST
AND INCOME TAXES................ 59,727 33,041 10,513 (22,510) 80,771
MINORITY INTERESTS................ -- 876 -- (318)(t) 558
---------- -------- ------- -------- ----------
INCOME BEFORE INCOME TAXES........ 59,727 32,165 10,513 (22,192) 80,213
INCOME TAXES...................... 6,015 1,023 3,886 -- 10,924
---------- -------- ------- -------- ----------
NET INCOME........................ $ 53,712 $ 31,142 $ 6,627 $(22,192) 69,289
========== ======== ======= ========
GENERAL PARTNER'S INTEREST IN NET
INCOME.......................... 1,386
----------
LIMITED PARTNERS' INTEREST IN NET
INCOME.......................... $ 67,903
==========
BASIC AND DILUTED NET INCOME PER
LIMITED PARTNER UNIT............ $ 2.07
==========
BASIC AND DILUTED WEIGHTED AVERAGE
NUMBER OF UNITS OUTSTANDING..... 32,821
==========
See accompanying notes.
95
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 $405,500 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 $33.40, the average closing price
of Heritage's common units on the New York Stock Exchange for the 45-day period
preceding 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.
96
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 will raise $265,000 of gross proceeds
through the sale of 6,883,117 Common Units at an assumed offering price of
$38.50 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 will be reflected at
fair value to the extent acquired by Energy Transfer, which will be
approximately 38.3%, 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 will be accounted for as a capital
transaction as the primary asset held by Heritage Holdings is 4,426,916 Common
Units of Heritage. Following the acquisition of Heritage Holdings by Heritage,
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.
The historical financial statements of Energy Transfer will become the
historical financial statements of the registrant. The results of operations of
Heritage 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:
Net book value of Heritage at August 31, 2003............... $ 223,048
Equity investment from public offering...................... 250,000
Treasury class E unit purchase.............................. (200,334)
---------
272,714
Percent of Heritage acquired by La Grange Energy............ 38.3%
---------
Equity interest acquired.................................... $ 104,449
=========
Fair market value of limited partner units.................. $ 608,687
Purchase price of general partner interest.................. 30,000
Equity investment from public offering...................... 250,000
Treasury class E unit purchase.............................. (200,334)
---------
688,353
Percent of Heritage acquired by La Grange Energy............ 38.3%
---------
Fair value of equity acquired............................... 263,639
Net book value of equity acquired........................... 104,449
---------
Excess purchase price over predecessor cost................. $ 159,190
=========
97
HERITAGE PROPANE PARTNERS, L.P.
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The excess purchase price over predecessor cost will be allocated as
follows:
Property, plant and equipment (30 year life)................ $ 37,242
Investment in affiliate..................................... 2,415
Customer lists (15 year life)............................... 15,841
Trademarks.................................................. 11,215
Goodwill.................................................... 92,477
--------
$159,190
========
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 7%.
(c) Reflects the net proceeds expected to be received from an assumed
offering of 6,883,117 Common Units of Heritage at an offering price of $38.50
per unit, net of underwriting discount of approximately $15,000. The offering of
Common Units is expected to close simultaneous with the closing of the Energy
Transfer Transaction and is referred to herein as the "Common Units Offering."
(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 elimination of intercompany receivables and payables
between Heritage and Heritage Holdings as a result of Heritage Holdings becoming
a wholly owned subsidiary of Heritage.
(g) Reflects the allocation of the excess purchase price over predecessor
costs to property, plant and equipment of $37,242, investment in affiliate of
$2,415, customer lists of $15,841, trademarks of $11,215 and goodwill of
$92,477, and the allocation to partners' capital based on their ownership
percentages.
(h) 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.
(i) 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. The
purchase price is allocated as follows:
Cash paid to the Utilities.................................. $ 50,000
Note payable to the Utilities............................... 50,000
Assumption of liabilities and elimination of other
comprehensive income (loss)............................... 104,645
--------
$204,645
========
Allocated to assets as follows:
Current assets............................................ $ 4,311
Investment in Heritage Propane............................ 200,334
--------
$204,645
========
98
HERITAGE PROPANE PARTNERS, L.P.
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
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.
(j) 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.
(k) Reflects the contribution from U.S. Propane, L.P. to Heritage of
interests in the Operating Partnerships in connection with the Common Units
Offering and the Energy Transfer Transaction in order to maintain its 2% general
partner interest in Heritage.
(l) Reflects the payment of cash to La Grange Energy of $87,280 and the
issuance to La Grange Energy of 4,094,798 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 Common Units Offering and
8,045,921 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 and the elimination of accumulated other
comprehensive income.
Cash paid to La Grange Energy for Energy Transfer........... $ 87,280
Issuance of 4,094,798 Common Units of Heritage.............. 136,766
Issuance of 8,045,921 Class D Units of Heritage............. 268,734
--------
$492,780
========
(m) Reflects the additional depreciation related to the step-up of net book
value of property, plant and equipment having 30-year lives.
(n) 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.
(o) 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.
(p) Allocation of additional interest expense of $19,250 related to the
$275,000 term loan at an assumed average interest rate of 7%, amortization of
loan origination fees of $583 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.
(q) Reflects elimination of Heritage Holding's equity in earnings of
Heritage.
(r) Reflects the elimination of the gain on sale of assets as the assets
are recorded at fair market value.
(s) Reflects elimination of interest income from the note receivable
retained by the Utilities.
(t) 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.
99
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
this report, which reflect the pro forma effects of the combination of Heritage
and Energy Transfer and the offering and related transactions as contemplated in
this report.
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
this report.
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.
100
ENERGY TRANSFER COMPANY
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED AUGUST 31, 2003
OASIS PIPE
ENERGY TRANSFER AQUILA GAS LINE FOUR
ELEVEN MONTHS PIPELINE ONE MONTHS
ENDED MONTH ENDED ENDED
AUGUST 31, SEPTEMBER 30, DECEMBER 27,
2003 2002 2002 ADJUSTMENTS PRO FORMA
--------------- ------------- ------------ ----------- ----------
(IN THOUSANDS)
OPERATING REVENUES.................... $1,008,723 $66,563 $11,532 $57,409(a) $1,142,964
(1,263)(b)
COSTS AND EXPENSES:
Cost of sales....................... 899,539 59,691 283 55,003(a) 1,013,253
(1,263)(b)
Operating........................... 19,081 1,669 1,424 561(a) 22,735
General and administrative.......... 15,965 3 1,215 659(a) 17,842
Depreciation and amortization....... 13,461 2,226 701 (1,241)(c) 15,996
849(d)
Unrealized (gain) on derivatives.... (912) -- -- -- (912)
---------- ------- ------- ------- ----------
Total costs and expenses......... 947,134 63,589 3,623 54,568 1,068,914
INCOME FROM OPERATIONS................ 61,589 2,974 7,909 1,578 74,050
OTHER INCOME (EXPENSE)................ 102 4 (408) -- (302)
EQUITY IN NET INCOME OF AFFILIATE..... 1,423 850 -- (94)(a) (251)
(2,430)(e)
INTEREST AND DEBT EXPENSES, net....... 12,057 393 (33) 1,353(f) 13,770
---------- ------- ------- ------- ----------
INCOME BEFORE INCOME TAXES............ 51,057 3,435 7,534 (2,299) 59,727
INCOME TAX EXPENSE.................... 4,432 879 2,639 (1,056)(g) 6,015
(879)(h)
---------- ------- ------- ------- ----------
NET INCOME............................ $ 46,625 $ 2,556 $ 4,895 $ (364) $ 53,712
========== ======= ======= ======= ==========
101
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").
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 other assets and a marketing
operation by ETC Holdings, L.P. to Energy Transfer.
2. PRO FORMA ADJUSTMENTS
(a) Reflects the income effects of the contribution of the other assets and
a marketing operation to Energy Transfer by ETC Holdings, L.P. The adjustment to
equity in net income of affiliates is primarily the equity earnings in net
income derived from Vantex Pipeline Company, LLC and Vantex Energy Services,
LTD.
(b) 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.
(c) 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.
(d) 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.
(e) Reflects the elimination of the equity method income derived from Oasis
prior to its becoming a wholly owned subsidiary.
(f) 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 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.
(g) 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).
(h) 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.
102
(c) Exhibit. See Exhibit Index.
103
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
HERITAGE PROPANE PARTNERS, L.P.
BY: U.S. Propane, L.P., its general partner
BY: U.S. Propane, L.L.C., the general partner
of U.S. Propane, L.P.
Date: December 16, 2003 By: /s/ Michael L. Greenwood
------------------- --------------------------------------
Michael L. Greenwood
Vice President and Chief Financial
Officer and officer duly authorized
to sign on behalf of the registrant
104
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
99.1 Consent of Ernst & Young LLP
99.2 Consent of Deloitte & Touche LLP