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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2007
Commission file number 1-11071
UGI CORPORATION
(Exact name of registrant as specified in its charter)
| Pennsylvania (State or Other Jurisdiction of Incorporation or Organization) |
23-2668356 (I.R.S. Employer Identification No.) |
460 North Gulph Road, King of Prussia, PA 19406
(Address of Principal Executive Offices) (Zip Code)
(Address of Principal Executive Offices) (Zip Code)
(610) 337-1000
(Registrant’s telephone number, including area code)
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| Name of each Exchange | ||
| Title of Each Class | on Which Registered | |
| Common Stock, without par value | New York Stock Exchange, Inc. | |
| Philadelphia Stock Exchange, Inc. | ||
| Securities registered pursuant to Section 12(g) of the Act: | None |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act. Yes þ No o.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act. Yes o No þ.
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in
Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer o
Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Securities Exchange Act of 1934). Yes o No þ
The aggregate market value of UGI Corporation Common Stock held by non-affiliates of the registrant
on March 31, 2007 was $2,778,118,692.
At
November 23, 2007 there were 106,684,035 shares of UGI Corporation Common Stock issued and
outstanding.
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Table of Contents
PART I:
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
CORPORATE OVERVIEW
UGI Corporation is a holding company that, through subsidiaries and joint venture affiliates,
distributes and markets energy products and related services. We are a domestic and international
retail distributor of propane and butane (which are liquefied petroleum gases (“LPG”)); a provider
of natural gas and electric service through regulated local distribution utilities; a generator of
electricity; a regional marketer of energy commodities; and a regional provider of heating, air
conditioning, refrigeration and electrical services. Our subsidiaries and joint venture affiliates
operate principally in the following five business segments:
| • | AmeriGas Propane |
||
| • | International Propane |
||
| • | Gas Utility |
||
| • | Electric Utility |
||
| • | Energy Services |
The AmeriGas Propane segment consists of the propane distribution business of AmeriGas
Partners, L.P. (“AmeriGas Partners” or the “Partnership”) which is the nation’s largest retail
propane distributor. The Partnership’s sole general partner is our subsidiary, AmeriGas Propane,
Inc. (“AmeriGas Propane” or the “General Partner”). The common units of AmeriGas Partners represent
limited partner interests in a Delaware limited partnership; they trade on the New York Stock
Exchange under the symbol “APU.” We have an effective 44% ownership interest in the Partnership;
the remaining interest is publicly held. See Note 1 to the Company’s Consolidated Financial
Statements.
The International Propane segment consists of the LPG distribution businesses of our wholly
owned subsidiaries Antargaz, a French société anonyme (“Antargaz”), Flaga GmbH, an Austrian limited
liability company (“Flaga”), and our joint venture in China. Antargaz is one of the largest retail
distributors of LPG in France. Flaga is the largest retail LPG distributor in Austria and through
its joint venture company is the largest retail distributor in the Czech Republic and one of the
largest retail distributors in Slovakia. In China, we participate in an LPG joint venture business
in the Nantong region.
On August 24, 2006, we acquired a Pennsylvania natural gas utility business from Southern
Union Company which significantly increased our natural gas distribution business. The Gas Utility
segment (“Gas Utility”) consists of the regulated natural gas distribution businesses of our
subsidiary, UGI Utilities, Inc. (“UGI Gas”) and UGI Utilities’ subsidiary, UGI
Penn Natural Gas, Inc. (“UGIPNG”). Gas Utility serves approximately 478,000 customers in
eastern and northeastern Pennsylvania. The Electric Utility segment (“Electric Utility”) consists
of the regulated electric distribution business of UGI Utilities, serving approximately 62,000
customers in northeastern Pennsylvania. Gas Utility and Electric Utility are regulated by the
Pennsylvania Public Utility Commission (“PUC”).
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The Energy Services segment consists of energy-related businesses conducted by a number of
subsidiaries. These businesses include (i) energy marketing in the eastern region of the United
States under the trade names GASMARK® and POWERMARK®, (ii) operating or
owning interests in electric generation assets in Pennsylvania, (iii) operating and owning
liquefied natural gas and propane storage and peak-shaving facilities in eastern Pennsylvania, and
(iv) operating and owning a propane import and storage facility in Chesapeake, Virginia.
UGI Corporation also operates and owns heating, ventilation, air conditioning, refrigeration
and electrical contracting service businesses serving customers in the Mid-Atlantic region.
Business Strategy
Our business strategy is to grow the Company by focusing on our core competencies as a
marketer and distributor of energy products and services. We are employing our core competencies
from our existing businesses and using our national scope, international experience, extensive
asset base and access to customers to accelerate both internal growth and growth through
acquisitions in our existing businesses, as well as in related and complementary businesses. During
fiscal year 2007, we completed a number of transactions in pursuit of this strategy, including the
acquisition by AmeriGas Propane of a 13 million gallon propane distribution business in Michigan
and a 32 million gallon propane distribution business serving Arkansas, Arizona, Colorado, Missouri
and Wyoming.
Corporate Information
UGI Corporation was incorporated in Pennsylvania in 1991. UGI Corporation is not subject to
regulation by the PUC. UGI Corporation is a “holding company” under the Public Utility Holding
Company Act of 2005 (“PUHCA 2005”). PUHCA 2005 and the implementing regulations of the Federal
Energy Regulatory Commission (“FERC”) give FERC access to certain holding company books and records
and impose certain accounting, record-keeping, and reporting requirements on holding companies.
PUHCA 2005 also provides state utility regulatory commissions with access to holding company books
and records in certain circumstances. Pursuant to a waiver granted in accordance with FERC’s
regulations on the basis of UGI Corporation’s status as a single-state holding company system, UGI
Corporation is not subject to certain of the accounting, record-keeping, and reporting requirements
prescribed by FERC’s regulations.
Our executive offices are located at 460 North Gulph Road, King of Prussia, Pennsylvania
19406, and our telephone number is (610) 337-1000. In this report, the terms “Company” and “UGI,”
as well as the terms “our,” “we,” and “its,” are sometimes used as abbreviated references to UGI
Corporation or, collectively, UGI Corporation and its consolidated
subsidiaries. Similarly, the terms “AmeriGas Partners” and the “Partnership” are sometimes
used
as abbreviated references to AmeriGas Partners, L.P. or, collectively, AmeriGas Partners, L.P.
and its subsidiaries and the term “UGI Utilities” is sometimes used as an abbreviated reference to
UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries.
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The Company’s corporate website can be found at www.ugicorp.com. The Company makes available
free of charge at this website (under the “Investor Relations and Corporate Governance-SEC filings”
caption) copies of its reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, including its Annual Report on Form 10-K, its Quarterly Reports on
Form 10-Q and its Current Reports on Form 8-K. The Company’s Principles of Corporate Governance,
Code of Ethics for the Chief Executive Officer and Senior Financial Officers, Code of Business
Conduct and Ethics for Directors, Officers and Employees, and charters of the Corporate Governance,
Audit and Compensation and Management Development Committees of the Board of Directors are also
available on the Company’s website, under the caption “Investor Relations and Corporate
Governance-Corporate Governance.” All of these documents are also available free of charge by
writing to Robert W. Krick, Vice President and Treasurer, UGI Corporation, P.O. Box 858, Valley
Forge, PA 19482.
Forward-Looking Statements
Information contained in this Annual Report on Form 10-K may contain forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,”
“plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words.
These statements discuss plans, strategies, events or developments that we expect or anticipate
will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases underlying the
forward-looking statement. We believe that we have chosen these assumptions or bases in good faith
and that they are reasonable. However, we caution you that actual results almost always vary from
assumed facts or bases, and the differences between actual results and assumed facts or bases can
be material, depending on the circumstances. When considering forward-looking statements, you
should keep in mind the following important factors which could affect our future results and could
cause those results to differ materially from those expressed in our forward-looking statements:
(1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of
propane and other LPG, oil, electricity and natural gas and the capacity to transport product to
our market areas; (3) changes in domestic and foreign laws and regulations, including safety, tax
and accounting matters; (4) the impact of pending and future legal proceedings; (5) competitive pressures from the same and alternative energy sources; (6)
failure to acquire new customers thereby reducing or limiting any increase in revenues; (7)
liability for environmental claims; (8) increased customer conservation measures due to high energy
prices and improvements in energy efficiency and technology resulting in reduced demand; (9)
adverse labor relations; (10) large customer, counterparty or supplier defaults; (11) liability in
excess of insurance coverage for personal injury and property damage arising from explosions and
other catastrophic events, including acts of terrorism, resulting from operating hazards and risks
incidental to generating and distributing electricity and transporting, storing and distributing
natural gas, propane and other LPG; (12) political, regulatory and economic conditions in the United States and in
foreign countries, including foreign currency rate fluctuations, particularly in the euro; (13)
reduced access to capital markets and interest rate fluctuations; (14) reduced distributions from
subsidiaries; and (15) the timing and success of the Company’s efforts to develop new business
opportunities.
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These factors are not necessarily all of the important factors that could cause actual results
to differ materially from those expressed in any of our forward-looking statements. Other unknown
or unpredictable factors could also have material adverse effects on future results. We undertake
no obligation to update publicly any forward-looking statement whether as a result of new
information or future events except as required by the federal securities laws.
AMERIGAS PROPANE
Our domestic propane distribution business is conducted through AmeriGas Partners. As of
September 30, 2007, the Partnership operated from approximately 650 district locations in 46
states. The increase in district locations from approximately 600 district locations as of
September 30, 2006 is primarily a result of acquisitions made
during fiscal 2007. In fiscal year 2008,
it is anticipated that many of the district locations added in fiscal
year 2007 will be combined with
other district locations that are situated in close geographic proximity. AmeriGas Propane is
responsible for managing the Partnership. Although our consolidated financial statements include
100% of the Partnership’s revenues, assets and liabilities, our net income reflects only our 44%
effective interest in the income or loss of the Partnership, due to the outstanding publicly-owned
limited partnership interests. See Note 1 to the Company’s Consolidated Financial Statements.
General Industry Information
Propane is separated from crude oil during the refining process and also extracted from
natural gas or oil wellhead gas at processing plants. Propane is normally transported and stored in
a liquid state under moderate pressure or refrigeration for economy and ease of handling in
shipping and distribution. When the pressure is released or the temperature is increased, it is
usable as a flammable gas. Propane is colorless and odorless; an odorant is added to allow its
detection. Propane is clean burning, producing negligible amounts of pollutants when properly
consumed.
The primary customers for propane are residential, commercial, industrial, motor fuel and
agricultural users to whom natural gas is not readily available. Propane is typically more
expensive than natural gas and fuel oil and, in most areas, cheaper than electricity on an
equivalent energy basis.
Based on the most recent annual survey by the American Petroleum Institute, 2005 domestic
retail propane sales (annual sales for other than chemical uses) totaled approximately 10.4 billion
gallons and, based on LP-GAS magazine rankings, 2006 sales volume of the ten largest propane
companies (including AmeriGas Partners) represented approximately 40% of
domestic retail sales. Based upon 2005 sales data, management believes the Partnership’s 2007
retail volume represents approximately 9% of domestic retail sales.
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Products, Services and Marketing
As of September 30, 2007, the Partnership served approximately 1.3 million customers from
district locations in 46 states. In addition to distributing propane, the Partnership also sells,
installs and services propane appliances, including heating systems. In certain markets, the
Partnership also installs and services propane fuel systems for motor vehicles. Typically, district
locations are found in suburban and rural areas where natural gas is not readily available.
Districts generally consist of an office, appliance showroom, warehouse, and service facilities,
with one or more 18,000 to 30,000 gallon storage tanks on the premises. As part of its overall
transportation and distribution infrastructure, the Partnership operates as an interstate carrier
in 48 states throughout the continental United States. It is also licensed as a carrier in the
Canadian Provinces of British Columbia and Quebec.
The Partnership sells propane primarily to five markets: residential, commercial/industrial,
motor fuel, agricultural and wholesale. The Partnership distributed over one billion gallons of
propane in fiscal year 2007. Approximately 90% of the Partnership’s fiscal year 2007 sales (based
on gallons sold) were to retail accounts and approximately 10% were to wholesale customers. Sales
to residential customers in fiscal year 2007 represented approximately 40% of retail gallons sold;
commercial/industrial customers 36%; motor fuel customers 14%; and agricultural customers 5%.
Transport gallons, which are large-scale deliveries to retail customers other than residential,
accounted for 5% of 2007 retail gallons. No single customer represents, or is anticipated to
represent, more than 5% of the Partnership’s consolidated revenues.
The Partnership continues to expand its AmeriGas Cylinder Exchange (“ACE”) program (formerly,
PPX Prefilled Propane Xchange® program or PPX ). At September 30, 2007, ACE was available at
approximately 23,600 retail locations throughout the United States. Sales of our ACE grill
cylinders to retailers are included in the commercial/industrial market. The ACE program enables
consumers to exchange their empty 20-pound propane grill cylinders for filled cylinders or to
purchase filled cylinders at various retail locations such as home centers, gas stations, mass
merchandisers and grocery and convenience stores. The Partnership also supplies retailers with
large propane tanks to enable retailers to fill customers’ 20-pound propane grill cylinders
directly at the retailer’s location.
In the residential market, which includes both conventional and manufactured housing, propane
is used primarily for home heating, water heating and cooking purposes. Commercial users, which
include motels, hotels, restaurants and retail stores, generally use propane for the same purposes
as residential customers. Industrial customers use propane to fire furnaces, as a cutting gas and
in other process applications. Other industrial customers are large-scale heating accounts and
local gas utility customers who use propane as a supplemental fuel to meet peak load deliverability
requirements. As a motor fuel, propane is burned in internal combustion engines that power
over-the-road vehicles, forklifts and stationary engines. Agricultural uses
include tobacco curing, chicken brooding and crop drying. In its wholesale operations, the
Partnership principally sells propane to large industrial end-users and other propane distributors.
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Retail deliveries of propane are usually made to customers by means of bobtail and rack
trucks. Propane is pumped from the bobtail truck, which generally holds 2,400 to 3,000 gallons of
propane, into a stationary storage tank on the customer’s premises. The Partnership owns most of
these storage tanks and leases them to its customers. The capacity of these tanks ranges from
approximately 120 gallons to approximately 1,200 gallons. The Partnership also delivers propane to
retail customers in portable cylinders with capacities of 4 to 24 gallons. Some of these deliveries
are made to the customer’s location, where empty cylinders are either picked up for replenishment
or filled in place.
Propane Supply and Storage
The Partnership has over 250 domestic and international sources of supply, including the spot
market. Supplies of propane from the Partnership’s sources historically have been readily
available. During the year ended September 30, 2007, over 90% of the Partnership’s propane supply
was purchased under supply agreements with terms of 1 to 3 years. The availability of propane
supply is dependent upon, among other things, the severity of winter weather, the price and
availability of competing fuels such as natural gas and crude oil, and the amount and availability
of imported supply. Although no assurance can be given that supplies of propane will be readily
available in the future, management currently expects to be able to secure adequate supplies during
fiscal year 2008. If supply from major sources were interrupted, however, the cost of procuring
replacement supplies and transporting those supplies from alternative locations might be materially
higher and, at least on a short-term basis, margins could be affected. Aside from BP Products North
America Inc. and BP Canada Energy Marketing Corp. (collectively), Enterprise Products Operating LP
and Targa Midstream Services LP, no single supplier provided more than 10% of the Partnership’s
total propane supply in fiscal year 2007. In certain market areas, however, some suppliers provide
more than 50% of the Partnership’s requirements. Disruptions in supply in these areas could also
have an adverse impact on the Partnership’s margins.
The Partnership’s supply contracts typically provide for pricing based upon (i) index formulas
using the current prices established at a major storage point such as Mont Belvieu, Texas, or
Conway, Kansas, or (ii) posted prices at the time of delivery. In addition, some agreements provide
maximum and minimum seasonal purchase volume guidelines. The percentage of contract purchases, and
the amount of supply contracted for at fixed prices, will vary from year to year as determined by
the General Partner. The Partnership uses a number of interstate pipelines, as well as railroad
tank cars, delivery trucks and barges, to transport propane from suppliers to storage and
distribution facilities. The Partnership stores propane at large storage facilities in Arizona and
Pennsylvania, as well as at smaller facilities in several other states.
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Because the Partnership’s profitability is sensitive to changes in wholesale propane costs,
the Partnership generally seeks to pass on increases in the cost of propane to customers. There is
no assurance, however, that the Partnership will always be able to pass on product cost increases
fully, particularly when product costs rise rapidly. Product cost increases can be triggered by
periods of severe cold weather, supply interruptions, increases in the prices of base commodities
such as crude oil and natural gas, or other unforeseen events. The General Partner has adopted
supply acquisition and product cost risk management practices to reduce the effect of volatility on
selling prices. These practices currently include the use of summer storage, forward purchases and
derivative commodity instruments, such as options and propane price swaps. See “Management’s
Discussion and Analysis of Financial Condition and Results of Operations — Market Risk
Disclosures.”
The following graph shows the average prices of propane on the propane spot market during the
last 5 fiscal years at Mont Belvieu, Texas, a major storage area.
Average Propane Spot Market Prices
Competition
Propane competes with other sources of energy, some of which are less costly for equivalent
energy value. Propane distributors compete for customers with suppliers of electricity, fuel oil
and natural gas, principally on the basis of price, service, availability and portability.
Electricity is a major competitor of propane, but propane generally enjoys a competitive price
advantage over electricity for space heating, water heating, and cooking. However, in some areas
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electricity may have a competitive price advantage or be relatively equivalent in price to propane
due to government regulated rate caps on electricity. Additionally, high efficiency electric heat
pumps have led to a decrease in the cost of electricity for heating. Fuel oil is also a major
competitor of propane and is generally less expensive than propane. Furnaces and appliances that
burn propane will not operate on fuel oil, and vice versa, and, therefore, a conversion from one
fuel to the other requires the installation of new equipment. Propane serves as an alternative to
natural gas in rural and suburban areas where natural gas is unavailable or portability of product
is required. Natural gas is generally a less expensive source of energy than propane, although in
areas where natural gas is available, propane is used for certain industrial and commercial
applications and as a standby fuel during interruptions in natural gas service. The gradual
expansion of the nation’s natural gas distribution systems has resulted in the availability of
natural gas in some areas that previously depended upon propane. However, natural gas pipelines are
not present in many regions of the country where propane is sold for heating and cooking purposes.
In the motor fuel market, propane competes with gasoline and diesel fuel as well as electric
batteries and fuel cells. Wholesale propane distribution is a highly competitive, low margin
business. Propane sales to other retail distributors and large-volume, direct-shipment industrial
end-users are price sensitive and frequently involve a competitive bidding process.
The retail propane industry is mature, with only modest growth in total demand for the product
foreseen. Therefore, the Partnership’s ability to grow within the industry is dependent on its
ability to acquire other retail distributors and to achieve internal growth, which includes
expansion of the ACE program and the Strategic Accounts program (through which the Partnership
encourages large, multi-location propane users to enter into a supply agreement with it rather than
with many small suppliers), as well as the success of its sales and marketing programs designed to
attract and retain customers. The failure of the Partnership to retain and grow its customer base
would have an adverse effect on its results.
The domestic propane retail distribution business is highly competitive. The Partnership
competes in this business with other large propane marketers, including other full-service
marketers, and thousands of small independent operators. Some rural electric cooperatives and fuel
oil distributors have expanded their businesses to include propane distribution and the Partnership
competes with them as well. The ability to compete effectively depends on providing high quality
customer service, maintaining competitive retail prices and controlling operating expenses.
Properties
As of September 30, 2007, the Partnership owned approximately 83% of its district locations.
The Partnership owns a 600,000 barrel refrigerated, above-ground storage facility located on leased
property in California. The California facility, which the Partnership operates, is currently
leased to an LPG marketer for the storage of LPG.
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The transportation of propane requires specialized equipment. The trucks and railroad tank
cars utilized for this purpose carry specialized steel tanks that maintain the propane in a
liquefied state. As of September 30, 2007, the Partnership operated a transportation fleet with the
following assets:
| Approximate Quantity & Equipment Type | % Owned | % Leased | ||||||||||
| 530 | Trailers |
92 | 8 | |||||||||
| 300 | Tractors |
27 | 73 | |||||||||
| 180 | Railroad tank cars |
0 | 100 | |||||||||
| 2,600 | Bobtail trucks |
13 | 87 | |||||||||
| 330 | Rack trucks |
9 | 91 | |||||||||
| 2,200 | Service and delivery trucks |
16 | 84 | |||||||||
Other assets owned at September 30, 2007 included approximately 900,000 stationary storage
tanks with typical capacities ranging from 121 to 2,000 gallons and approximately 2.7 million
portable propane cylinders with typical capacities of 1 to 120 gallons. The Partnership also owned
approximately 5,400 large volume tanks with typical capacities of more than 2,000 gallons which are
used for its own storage requirements.
Trade Names, Trade and Service Marks
The
Partnership markets propane principally under the “AmeriGas®” and “America’s Propane
Company®” trade names and related service marks. UGI owns, directly or indirectly, all the right,
title and interest in the “AmeriGas” name and related trade and service marks. The General Partner
owns all right, title and interest in the “America’s Propane Company” trade name and related
service marks. The Partnership has an exclusive (except for use by UGI, AmeriGas, Inc. and the
General Partner), royalty-free license to use these trade names and related service marks. UGI and
the General Partner each have the option to terminate its respective license agreement (on 12
months prior notice in the case of UGI), without penalty, if the General Partner is removed as
general partner of the Partnership other than for cause. If the General Partner ceases to serve as
the general partner of the Partnership for cause, the General Partner has the option to terminate
its license agreement upon payment of a fee to UGI equal to the fair market value of the licensed
trade names. UGI has a similar termination option; however, UGI must provide 12 months prior notice
in addition to paying the fee to the General Partner.
Seasonality
Because many customers use propane for heating purposes, the Partnership’s retail sales volume
is seasonal. Approximately 55% to 60% of the Partnership’s retail sales volume occurs, and
substantially all of the Partnership’s operating income is earned, during the five-month peak
heating season from November through March. As a result of this seasonality, sales are higher in
the Partnership’s first and second fiscal quarters (October 1 through March 31). Cash receipts are
generally greatest during the second and third fiscal quarters when customers pay for propane
purchased during the winter heating season.
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Sales volume for the Partnership traditionally fluctuates from year-to-year in response to
variations in weather, prices, competition, customer mix and other factors, such as conservation
efforts and general economic conditions. For historical information on national weather statistics,
see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Government Regulation
The Partnership is subject to various federal, state and local environmental,
safety and transportation laws and regulations governing the storage, distribution and
transportation of propane and the operation of bulk storage LPG terminals. These laws include,
among others, the Resource Conservation and Recovery Act, CERCLA, the Clean Air Act, the
Occupational Safety and Health Act, the Homeland Security Act of 2002, the Emergency Planning and
Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA imposes
joint and several liability on certain classes of persons considered to have contributed to the
release or threatened release of a “hazardous substance” into the environment without regard to
fault or the legality of the original conduct. Propane is not a hazardous substance within the
meaning of federal and most state environmental laws. See Note 10 to the Company’s Consolidated
Financial Statements.
All states in which the Partnership operates have adopted fire safety codes that regulate the
storage and distribution of propane. In some states these laws are administered by state agencies,
and in others they are administered on a municipal level. The Partnership conducts training
programs to help ensure that its operations are in compliance with applicable governmental
regulations. With respect to general operations, National Fire Protection Association (“NFPA”)
Pamphlets No. 54 and No. 58, which establish a set of rules and procedures governing the safe
handling of propane, or comparable regulations, have been adopted by all states in which the
Partnership operates. The most recent editions of NFPA Pamphlet No. 58, adopted by a majority of
states, requires certain stationary cylinders that are filled in place to be re-qualified
periodically, depending on the date of manufacture and previous schedule of re-qualification of the
cylinders. Management believes that the policies and procedures currently in effect at all of its
facilities for the handling, storage and distribution of propane are consistent with industry
standards and are in compliance in all material respects with applicable environmental, health and
safety laws.
With respect to the transportation of propane by truck, the Partnership is subject to
regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act
and the Homeland Security Act of 2002. Regulations under these statutes cover the security and
transportation of hazardous materials and are administered by the United States Department of
Transportation (“DOT”). The Natural Gas Safety Act of 1968 required the DOT to develop and enforce
minimum safety regulations for the transportation of gases by pipeline. The DOT’s pipeline safety
regulations apply to, among other things, a propane gas system which supplies 10 or more
residential customers or 2 or more commercial customers from a single source and a propane gas
system any portion of which is located in a public place. The code requires operators of all gas
systems to provide training and written instructions for employees, establish written procedures to
minimize the hazards resulting from gas pipeline emergencies, and to conduct and keep records of
inspections and testing. Operators are subject to the Pipeline Safety Improvement
Act of 2002, which, among other things, protects from adverse employment actions employees who
provide information to their employers or to the federal government as to pipeline safety.
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Employees
The Partnership does not directly employ any persons responsible for managing or operating the
Partnership. The General Partner provides these services and is reimbursed for its direct and
indirect costs and expenses, including all compensation and benefit costs. At September 30, 2007,
the General Partner had approximately 6,200 employees, including approximately 430 part-time,
seasonal and temporary employees, working on behalf of the Partnership. UGI also performs certain
financial and administrative services for the General Partner on behalf of the Partnership and is
reimbursed by the Partnership.
INTERNATIONAL BUSINESSES
We conduct our international LPG distribution business principally in Europe through our
wholly owned subsidiaries, Antargaz and Flaga. On February 15, 2006, Flaga entered into a joint
venture with a subsidiary of Progas GmbH & Co KG (“Progas”) to combine our respective central
European LPG operations. The joint venture company, Zentraleuropa LPG Holding GmbH (“ZLH”), is
owned and controlled equally by Flaga and Progas. Flaga contributed the shares of its operating
subsidiaries in the Czech Republic and Slovakia to ZLH and Progas contributed the shares of its
operating subsidiaries in the Czech Republic, Slovakia, Poland, Hungary and Romania to ZLH. In a
related transaction during fiscal year 2006, Flaga expanded its LPG distribution business in
Austria by acquiring Progas Flüssiggas Handelsgesellschaft GmbH. In fiscal 2007, ZLH expanded its
Polish operations by acquiring, through a subsidiary, an LPG distribution business and storage and
filling plant in Poland.
Antargaz operates in France; Flaga operates in Austria and Switzerland; and ZLH operates
through subsidiaries in the Czech Republic, Slovakia, Poland, Hungary and Romania. During fiscal
year 2007, Antargaz sold approximately 269 million gallons of LPG, Flaga sold approximately 14
million gallons of LPG and ZLH, through its subsidiaries, sold approximately 42 million gallons of
LPG. Our joint venture in China sold approximately 15 million gallons of LPG during fiscal year
2007.
ANTARGAZ
Products, Services and Marketing
Antargaz’ customer base consists of residential, commercial, agricultural and motor fuel
customer accounts that use LPG for space heating, cooking, water heating, process heat and
transportation. Antargaz sells LPG in cylinders, and in small, medium and large bulk volumes stored
in tanks. Sales of LPG are also made to service stations to accommodate vehicles that run on LPG.
Antargaz sells LPG in cylinders to approximately 23,000 retail outlets, such as supermarkets,
individually owned stores and gas stations. At September 30, 2007, Antargaz had
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approximately 205,000 bulk customers and approximately 5 million cylinders in circulation.
Approximately 63% of Antargaz’ fiscal year 2007 sales (based on volumes) were cylinder and small
bulk, 14% medium bulk, 20% large bulk, and 3% to service stations for automobiles. Antargaz also
engages in wholesale sales of LPG and provides logistic, storage and other services to third-party
LPG distributors. No single customer represents, or is anticipated to represent, more than 5% of
total revenues for Antargaz.
Sales to small bulk customers represent the largest segment of Antargaz’ business in terms of
volume, revenue and margin. Small bulk customers are primarily residential and small business
users, such as restaurants, that use LPG mainly for heating and cooking. Small bulk customers also
include municipalities, which use LPG for heating sports arenas and swimming pools, and the poultry
industry for use in chicken brooding.
The principal end-users of cylinders are residential customers who use LPG supplied in this
form for domestic applications such as cooking and heating. Butane-filled cylinders accounted for
approximately 59% of all LPG cylinders sold in fiscal year 2007, with propane-filled cylinders
accounting for the remainder. Propane-filled cylinders are also used to supply fuel for forklift
trucks. The market demand for filled cylinders has been declining, due primarily to customers
gradually changing to other household energy sources for heating and cooking, such as natural gas.
Antargaz is seeking to increase demand for butane and propane-filled cylinders through marketing
and product innovations.
Medium bulk customers use propane only, and consist mainly of large residential developments
such as housing projects, hospitals, municipalities and medium-sized industrial and agricultural
enterprises. Large bulk customers are primarily companies that use LPG in their industrial
processes and large agricultural companies.
LPG Supply and Storage
Antargaz has an agreement with Totalgaz for the supply of butane and propane, with pricing
based on internationally quoted market prices. Under this agreement, 80% of Antargaz’ requirements
for butane are guaranteed until June 2009 and 15% of its requirements for propane are guaranteed
until June 2008. Requirements are fixed annually and Antargaz can develop other sources of supply.
For the 2007 fiscal year, Antargaz purchased almost 100% of its butane needs and approximately 31%
of its propane needs from Totalgaz. Antargaz also purchases propane on the international market
and, to a lesser degree, purchases butane on the domestic market, under term agreements with
international oil and gas trading companies such as SHV Gas Supply and Trading, Louis Dreyfus
Energy, VITOL SA. In addition, purchases are made on the spot market from international oil and gas
companies such as Total Oil Trading SA (“Total Trading”) and to a lesser extent from domestic
refineries, including those operated by BP France and Esso SAF.
Antargaz has 4 primary storage facilities in operation, including 3 that are located at deep
sea harbor facilities, and 24 secondary storage facilities. It also manages an extensive logistics
and transportation network. Access to seaborne facilities allows Antargaz to diversify its LPG
supplies through imports. LPG stored in primary storage facilities is transported to smaller
storage facilities by rail, sea and road. At secondary storage facilities, LPG is filled into
cylinders or trucks equipped with tanks and then delivered to customers.
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Competition
The LPG market in France is mature, with limited future growth expected. Sales volumes are affected principally by
the severity of the weather and customer migration to alternative energy forms, including natural gas and electricity.
Like other businesses, it becomes more difficult for Antargaz to pass on product costs increases fully when product
costs rise rapidly. Increased LPG prices may result in slower than expected growth due to customer conservation and
customers seeking less expensive alternative energy sources. France has regulated electricity prices as well as
policies and incentives that favor alternative energy sources which can result in customers migrating to energy sources
other than LPG.
Antargaz competes in all of its product markets on a national level principally with three LPG
distribution companies, Totalgaz (owned by Total France), Butagaz (owned by Societe des Petroles
Shell, “Shell”) and Compagnie des Gaz de Petrole Primagaz (an independent supplier owned by SHV
Holding NV), as well as with regional competitors, Vitogaz and Repsol. Competitive conditions in
the French LPG market are undergoing change. Some supermarket chain stores and other new market
entrants are competing in the cylinder market. As a result of these changes, we have experienced an
intensified level of competition in the French LPG market. Antargaz’ competitors are generally
affiliates of its LPG suppliers. As a result, its competitors may obtain product at more
competitive prices.
During fiscal year 2005, Antargaz received an inquiry from the French competition authority,
the General Division of Competition, Consumption and Fraud Punishment (“DGCCRF”). The DGCCRF
apparently sought evidence of unlawful anticompetitive activities affecting the packaged LPG (i.e.,
cylinder) business in northern France. Antargaz did not have any further contact with the DGCCRF
regarding this matter until February 2007, when it received a letter from the DGCCRF requesting
documents and information relating to Antargaz’ pricing policies and practices. In March 2007, and
again in August 2007, the DGCCRF requested additional information from Antargaz and three joint
ventures in which it participates. Based on these requests, it appears that the DGCCRF has expanded
the scope of its investigation to include both bulk and cylinder markets throughout France. For
more information on the inquiry, see “RISK FACTORS – The expansion of our international business
means that we will face increased risks, which may negatively affect our business results.”
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Seasonality
Because a significant amount of LPG is used for heating, demand is typically higher during the
colder months of the year. Approximately 65% to 70% of Antargaz’ retail sales volume occurs, and
approximately 80% to 85% of Antargaz’ operating income is earned, during the 6 months from October
through March.
Sales volume for Antargaz traditionally fluctuates from year-to-year in response to variations
in weather, prices and other factors, such as conservation efforts and general economic conditions.
For historical information on weather statistics for Antargaz, see “Management’s Discussion and
Analysis of Financial Condition and Results of Operations.”
Government Regulation
Antargaz’ business is subject to various laws and regulations at the national and European
levels with respect to matters such as protection of the environment, the storage and handling of
hazardous materials and flammable substances, the discharge of contaminants into the environment
and the safety of persons and property.
Properties
Antargaz has 4 primary storage facilities in operation. Two of these storage facilities are
underground caverns, one is a refrigerated facility, and one is an aerial pressure facility. The
table below sets forth details of each of these facilities.
| Antargaz | Antargaz | |||||||||||
| Storage Capacity – | Storage Capacity - | |||||||||||
| Propane | Butane | |||||||||||
| Ownership % | (m3) (1) | (m3) (1) | ||||||||||
Norgal |
52.7 | 22,600 | 8,900 | |||||||||
Geogaz Lavera |
16.7 | 17,400 | 32,500 | |||||||||
Donges |
50.0 (2) | 30,000 | 0 | |||||||||
Cobogal |
15.0 | 1,300 | 900 | |||||||||
| (1) | Cubic meters. |
|
| (2) | Pursuant to a contractual arrangement with the owner. |
Antargaz is evaluating whether to close a fifth storage facility, Geovexin. Antargaz has 24
secondary storage facilities, 14 of which are wholly-owned. The others are partially-owned, through
joint ventures.
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Employees
At September 30, 2007, Antargaz had approximately 1,100 employees.
FLAGA
Products, Services and Marketing
Flaga distributes LPG in Austria and Switzerland, and ZLH’s subsidiaries distribute LPG in the
Czech Republic, Slovakia, Poland, Hungary and Romania for residential, commercial, industrial and
auto gas applications. During fiscal year 2007, Flaga sold approximately 14 million gallons of LPG
and ZLH, through its subsidiaries, sold approximately 42 million gallons of LPG.
Flaga is the largest distributor of LPG in Austria, serving residential, commercial and
industrial customers. The retail propane industry in Austria is mature, with slight declines in
overall demand in recent years, due primarily to the expansion of natural gas and renewable energy
sources. Competition for customers is based on contract terms as well as on product prices. Flaga
has 6 sales offices in Austria and 1 sales office in Switzerland. Much of Flaga’s cylinder
business is conducted through approximately 600 local resellers with whom Flaga has a long business
relationship. Flaga utilizes approximately 21 storage facilities in Austria and Switzerland. Flaga
competes with other propane marketers, including competitors located in other Eastern European
countries. Flaga also competes with providers of other sources of energy, principally natural gas,
electricity and wood.
During fiscal year 2007, ZLH’s subsidiaries sold approximately 42 million gallons of LPG in
the Czech Republic, Slovakia, Poland, Hungary and Romania. ZLH utilizes approximately 34 storage
facilities and has approximately 13 sales offices in these countries. ZLH is one of the leading distributors of LPG in both the Czech
Republic and Slovakia.
Seasonality and Competition
Sales volumes in Flaga’s and ZLH’s markets are affected principally by the severity of the
weather and traditionally fluctuate from year-to-year in response to variations in weather, prices
and other factors, such as conservation efforts and general economic conditions. Because Flaga’s
and ZLH’s profitability is sensitive to changes in wholesale LPG costs, Flaga and ZLH generally
seek to pass on increases in the cost of LPG to customers. There is no assurance, however, that
Flaga and ZLH will always be able to pass on product cost increases fully. It is particularly
difficult for Flaga and ZLH to pass on rapid increases in LPG due to the low per capita income of
customers in Flaga’s and ZLH’s markets. Product cost increases can be triggered by periods of
severe cold weather, supply interruptions, increases in the prices of base commodities such as
crude oil and natural gas, or other unforeseen events. High LPG prices may result in slower than
expected growth due to customer conservation and customers seeking less expensive alternative
energy sources. In many of Flaga’s and ZLH’s European markets, government policies and incentives that favor alternative energy sources
may result in customers migrating to energy sources other than LPG.
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Government Regulation
Flaga’s and ZLH’s businesses are subject to various laws and regulations at both the national
and European levels with respect to matters such as protection of the environment and the storage
and handling of hazardous materials and flammable substances.
Employees
At
September 30, 2007, Flaga had approximately 150 employees and
ZLH had approximately 510 employees.
GAS UTILITY
Service Area; Revenue Analysis
Gas Utility is authorized to distribute natural gas to approximately 478,000 customers in
portions of 28 eastern and northeastern Pennsylvania counties through its distribution system of
approximately 7,800 miles of gas mains. The service area includes the cities of Allentown,
Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre and
Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas
Utility’s service area are major production centers for basic industries such as specialty metals,
aluminum, glass and paper product manufacturing.
System throughput (the total volume of gas sold to or transported for customers within Gas
Utility’s distribution system) for the 2007 fiscal year was approximately 131.8 billion cubic feet
(“bcf”). System sales of gas accounted for approximately 43% of system throughput, while gas
transported for residential, commercial and industrial customers (who bought their gas from others)
accounted for approximately 57% of system throughput.
Sources of Supply and Pipeline Capacity
Gas Utility meets its service requirements by utilizing a diverse mix of natural gas purchase
contracts with marketers and producers, along with storage and transportation service contracts.
These arrangements enable Gas Utility to purchase gas from Gulf Coast, Mid-Continent, Appalachian
and Canadian sources. For the transportation and storage function, Gas Utility has agreements with
a number of pipeline companies, including Texas Eastern Transmission Corporation, Columbia Gas
Transmission Corporation, Transcontinental Gas Pipeline Corporation and Tennessee Gas Pipeline.
Gas Supply Contracts
During fiscal year 2007, Gas Utility purchased approximately 79 bcf of natural gas for sale to
retail core market and off-system sales customers. Approximately 87% of the volumes purchased were
supplied under agreements with 10 suppliers. The remaining 13% of gas purchased by Gas Utility was
supplied by approximately 23 producers and marketers. Gas
supply contracts for Gas Utility are generally no longer than 1 year. Gas Utility also has
long-term contracts with suppliers for natural gas peaking supply during the months of November
through March.
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Seasonality
Because many of its customers use gas for heating purposes, Gas Utility sales are seasonal.
Approximately 55% to 60% of Gas Utility’s sales volume is supplied, and approximately 70% to 75% of
Gas Utility’s operating income is earned, during the five-month peak heating season from November
through March.
Competition
Natural gas is a fuel that competes with electricity and oil, and to a lesser extent, with
propane and coal. Competition among these fuels is primarily a function of their comparative price
and the relative cost and efficiency of fuel utilization equipment. Electric utilities in Gas
Utility’s service area are seeking new load, primarily in the new construction market. In parts of
Gas Utility’s service area electricity may have a competitive price advantage over natural gas due
to government regulated rate caps on electricity. Additionally, high efficiency electric heat
pumps have led to a decrease in the cost of electricity for heating. Fuel oil dealers compete for
customers in all categories, including industrial customers. Gas Utility responds to this
competition with marketing efforts designed to retain and grow its customer base.
In substantially all of its service territories, Gas Utility is the only regulated gas
distribution utility having the right, granted by the PUC or by law, to provide gas distribution
services. Since the 1980s, larger commercial and industrial customers have been able to purchase
gas supplies from entities other than natural gas distribution utility companies. As a result of
Pennsylvania’s Natural Gas Choice and Competition Act (“Gas Competition Act”), effective July 1,
1999 all of Gas Utility’s customers, including residential and smaller commercial and industrial
customers (“Core Market Customers”), have been afforded this opportunity. As of September 30, 2007,
three marketers provide gas supplies to approximately 4,100 of Gas Utility’s Core Market Customers.
Gas Utility provides transportation services for its customers who purchase natural gas from
others.
A number of Gas Utility’s commercial and industrial customers have the ability to switch to an
alternate fuel at any time and, therefore, are served on an interruptible basis under rates which
are competitively priced with respect to the alternate fuel. Margin from these customers,
therefore, is affected by the difference or “spread” between the customers’ delivered cost of gas
and the customers’ delivered cost of the alternate fuel, as well as the frequency and duration of
interruptions. See “Gas Utility and Electric Utility Regulation and Rates – Gas Utility Rates.” In
recent years, Gas Utility’s margin for interruptible service has been higher than in past years due
to the higher cost of oil compared to natural gas. In accordance with the PUC’s June 29, 2000 Gas
Restructuring Order applicable to UGI Gas, margin from certain of these customers (who use pipeline
capacity contracted by UGI Gas to serve retail customers) is used to reduce purchased gas cost
rates for retail customers. Approximately 29% of UGI Gas’ commercial and industrial customers,
including certain customers served under interruptible rates, have locations
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which afford them the opportunity, although none have exercised it, of seeking transportation
service directly from interstate pipelines, thereby bypassing UGI Gas. The majority of customers in
this group are served under transportation contracts having 3 to 20 year terms. Included in these
two customer groups are UGI Gas’ 10 largest customers in terms of annual volumes. All of these
customers have contracts, 9 of which extend beyond Fiscal 2008. No single customer represents, or
is anticipated to represent, more than 5% of Gas Utility’s total revenues.
Outlook for Gas Service and Supply
Gas Utility anticipates having adequate pipeline capacity and sources of supply available to
it to meet the full requirements of all firm customers on its system through fiscal year 2008.
Supply mix is diversified, market priced, and delivered pursuant to a number of long-term and
short-term firm transportation and storage arrangements, including transportation contracts held by
some of Gas Utility’s larger customers.
During fiscal year 2007, Gas Utility supplied transportation service to 2 major co-generation
installations and 5 electric generation facilities. Gas Utility continues to pursue opportunities
to supply natural gas to electric generation projects located in its service area. Gas Utility also
continues to seek new residential, commercial and industrial customers for both firm and
interruptible service. In the residential market sector, Gas Utility connected approximately 9,800
residential heating customers during fiscal year 2007. Despite the nationwide slowdown in the real
estate market, of those new customers, new home construction accounted for over 6,200 heating
customers. If the slowdown in new home construction continues in fiscal year 2008 in Gas Utility’s
service area, customer growth may be adversely affected. Customers converting from other energy
sources, primarily oil and electricity, and existing non-heating gas customers who have added gas
heating systems to replace other energy sources, accounted for the balance of the additions. The
number of new commercial and industrial Gas Utility customers was approximately 1,700.
UGI Utilities continues to monitor and participate, where appropriate, in rulemaking and
individual rate and tariff proceedings before FERC affecting the rates and the terms and conditions
under which Gas Utility transports and stores natural gas. Among these proceedings are those
arising out of certain FERC orders and/or pipeline filings which relate to (i) the pricing of
pipeline services in a competitive energy marketplace; (ii) the flexibility of the terms and
conditions of pipeline service tariffs and contracts; and (iii) pipelines’ requests to increase
their base rates, or change the terms and conditions of their storage and transportation services.
UGI Utilities’ objective in negotiations with interstate pipeline and natural gas suppliers,
and in proceedings before regulatory agencies, is to assure availability of supply, transportation
and storage alternatives to serve market requirements at the lowest cost possible, taking into
account the need for security of supply. Consistent with that objective, UGI Utilities negotiates
the terms of firm transportation capacity on all pipelines serving it, arranges for appropriate
storage and peak-shaving resources, negotiates with producers for competitively priced gas
purchases and aggressively participates in regulatory proceedings related to transportation rights
and costs of service.
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ELECTRIC UTILITY
Service Area; Sales Analysis
Electric Utility supplies electric service to approximately 62,000 customers in portions of
Luzerne and Wyoming counties in northeastern Pennsylvania through a system consisting of
approximately 2,150 miles of transmission and distribution lines and 13 transmission substations.
For fiscal year 2007, about 53% of sales volume came from residential
customers, 35% from
commercial customers and 12% from industrial customers.
Sources of Supply
Electric Utility has no owned generation and, as a result, has third-party generation supply
contracts in place for substantially all of its expected energy requirements for fiscal years 2008
and 2009. Electric Utility distributes electricity that it purchases from others and electricity
that customers purchase from other suppliers, if any. As of September 30, 2007, none of Electric
Utility’s customers have selected an alternative electricity generation supplier. Electric Utility
expects to continue to provide energy to the great majority of its distribution customers for the
foreseeable future. See “Management’s Discussion and Analysis of Financial Condition and Results
of Operations – Market Risk Disclosures” for a discussion of risks related to Electric Utility’s
supply contracts.
Competition
As a result of the Electricity Generation Customer Choice and Competition Act (“ECC Act”), all
Pennsylvania retail electric customers have the ability to choose their electric generation
supplier. Electric Utility remains the provider of last resort (“POLR”) for its customers who do
not choose an alternate electric generation supplier. The terms and conditions under which Electric
Utility provides POLR service, and rules governing the rates that may be charged for such service,
have been established in a series of PUC-approved settlements (collectively, the “POLR
Settlement”). Consistent with the terms of the POLR Settlement, Electric Utility’s POLR rates were
increased in January 2007. Electric Utility has announced its intent to increase POLR rates in
January 2008 and is permitted, but not required, to further increase its POLR rates in January
2009. Electric Utility is the only regulated electric utility having the right, granted by the PUC
or by law, to distribute electricity in its service territory. Sales of electricity for residential
heating purposes accounted for approximately 19% of total sales of electricity during fiscal year
2007. Electricity competes with natural gas, oil, propane and other heating fuels for this use.
For current POLR rates see “Gas Utility and Electric Utility Regulation and Rates – Electric
Utility Rates.”
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GAS UTILITY AND ELECTRIC UTILITY REGULATION AND RATES
Pennsylvania Public Utility Commission Jurisdiction
UGI Utilities’ gas and electric utility operations are subject to regulation by the PUC as to
rates, terms and conditions of service, accounting matters, issuance of securities, contracts and
other arrangements with affiliated entities, and various other matters.
Electric Transmission and Wholesale Power Sale Rates
FERC has jurisdiction over the rates and terms and conditions of service of electric
transmission facilities used for wholesale or retail choice transactions. Electric Utility owns
electric transmission facilities that are within the control area of the PJM Interconnection, LLC
(“PJM”) and are dispatched in accordance with a FERC-approved open access tariff and associated
agreements administered by PJM. Electric Utility receives certain revenues collected by PJM,
determined under a formulary rate schedule that is adjusted in June of each year to reflect annual
changes in Electric Utility’s electric transmission revenue requirements, when its transmission
facilities are used by third parties.
FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of
electric capacity and energy. Electric Utility has a tariff on file with FERC pursuant to which it
may make power sales to wholesale customers at market-based rates.
Gas Utility Rates
The most recent general base rate increase for UGI Gas became effective in 1995. In
accordance with a statutory mechanism, a rate increase for firm- residential, commercial and
industrial customers (“retail core-market”) became effective October 1, 2000 along with a Purchased
Gas Cost (“PGC”) variable credit equal to a portion of the margin received from customers served
under interruptible rates to the extent such interruptible customers use capacity contracted for by
UGI Gas for retail core-market customers.
In an order entered on November 30, 2006, the PUC approved a settlement of the UGIPNG base
rate proceeding. The settlement authorized UGIPNG to increase natural gas distribution base rates
by $12.5 million of additional revenue annually, or approximately 4.0%, effective December 2, 2006.
In addition, the settlement provides UGIPNG the ability to recover up to $1.0 million of
additional corporate franchise tax through the state tax adjustment surcharge mechanism.
UGI Gas’ and UGIPNG’s gas service tariffs contain PGC rates applicable to firm retail rate
schedules. These PGC rates permit recovery of substantially all of the prudently incurred costs of
natural gas that UGI Gas and UGIPNG sells to its customers. PGC rates are reviewed and approved
annually by the PUC. UGI Gas and UGIPNG may request quarterly, or, under certain conditions,
monthly adjustments to reflect the actual cost of gas. Quarterly adjustments become effective on 1
day’s notice to the PUC and are subject to review during the next annual PGC filing. Each proposed
annual PGC rate is required to be filed with the PUC 6 months
prior to its effective date. During this period, the PUC holds hearings to determine whether the
proposed rate reflects a least-cost fuel procurement policy consistent with the obligation to
provide safe, adequate and reliable service. After completion of these hearings, the PUC issues an
order permitting the collection of gas costs at levels which meet that standard. The PGC mechanism
also provides for an annual reconciliation.
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UGI Gas has two PGC rates. PGC (1) is applicable to small, firm, retail core-market customers
consisting of the residential and small commercial and industrial classes; PGC (2) is applicable to
firm, contractual, high-load factor customers served on three separate rates. In addition,
residential customers maintaining a high load factor may qualify for the PGC (2) rate. As described
above, UGI Gas’ PGC rates are adjusted to reflect margins, if any, from interruptible rate
customers who do not obtain their own pipeline capacity. UGIPNG has one PGC rate applicable to all
customers.
Electric Utility Rates
The most recent general base rate increase for Electric Utility became effective in 1996.
Electric Utility’s rates were unbundled into distribution, transmission and generation
(Provider-Of-Last-Resort or “POLR” or “default service”) components in 1998. In accordance with
the POLR Settlement, Electric Utility may increase its POLR rates up to certain limits through
December 31, 2009. Consistent with the terms of the POLR Settlement, Electric Utility’s POLR rates
increased annually from 2004 through 2007. Effective January 1, 2007, Electric Utility’s increase
in POLR rates increased the average cost to residential customers by approximately 35% over such
costs in effect during calendar year 2006. Effective January 1, 2008, total average residential
rates will increase by approximately 5.5%. Electric Utility is also permitted to and has entered
into multiple-year fixed-rate POLR contracts with certain of its customers. New PUC default service
regulations became effective on September 15, 2007, but do not disturb Electric Utility’s POLR
Settlement through 2009. Under the default service regulations, Electric Utility will be required
to file a default service plan with the PUC in 2008 that will establish the terms and conditions
under which it will offer POLR service commencing 2010.
FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers
Both Gas Utility and Electric Utility, and our subsidiaries UGI Energy Services, Inc. and UGI
Development Company, are subject to FERC regulations governing the manner in which certain
jurisdictional sales or transportation are conducted. Section 4A of the Natural Gas Act and Section
222 of the Federal Power Act prohibit the use or employment of any manipulative or deceptive
devices or contrivances in connection with the purchase or sale of natural gas, electric energy, or
natural gas transportation or electric transmission services subject to the jurisdiction of FERC.
FERC has adopted regulations to implement these statutory provisions which apply to interstate
transportation and sales by the Electric Utility, and to a much more limited extent, to certain
sales and transportation by the Gas Utility that are subject to FERC’s jurisdiction. Gas Utility
and Electric Utility are subject to certain other regulations and obligations for FERC-regulated activities. Under provisions of the Energy Policy Act of 2005 (“EPACT 2005”), Electric
Utility is subject to certain electric reliability standards established by FERC and administered
by an Electric Reliability Organization (“ERO”). Electric Utility anticipates that substantially all
the costs of complying with the ERO standards will be recoverable through its PJM formulary
electric transmission rate schedule.
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EPACT 2005 also granted FERC authority to impose substantial civil penalties for the violation
of any regulations, orders or provisions under the Federal Power Act and Natural Gas Act, and
clarified FERC’s authority over certain utility or holding company mergers or acquisitions of
electric utilities or electric transmitting utility property valued at $10 million or more.
State Tax Surcharge Clauses
UGI Utilities’ gas and electric service tariffs contain state tax surcharge clauses. The
surcharges are recomputed whenever any of the tax rates included in their calculation are changed.
These clauses protect UGI Utilities from the effects of increases in most of the Pennsylvania taxes
to which it is subject.
Utility Franchises
UGI Utilities and UGIPNG each hold certificates of public convenience issued by the PUC and
certain “grandfather rights” predating the adoption of the Pennsylvania Public Utility Code and its
predecessor statutes, which each of them believes are adequate to authorize them to carry on their
business in substantially all of the territories to which they now render gas or electric service.
Under applicable Pennsylvania law, UGI Utilities and UGIPNG also have certain rights of eminent
domain as well as the right to maintain their facilities in streets and highways in their
territories.
Other Government Regulation
In addition to regulation by the PUC and FERC, the gas and electric utility operations of UGI
Utilities are subject to various federal, state and local laws governing environmental matters,
occupational health and safety, pipeline safety and other matters. UGI Utilities is subject to the
requirements of the federal Resource Conservation and Recovery Act, CERCLA and comparable state
statutes with respect to the release of hazardous substances on property owned or operated by UGI
Utilities. See ITEM 3. “LEGAL PROCEEDINGS — Environmental Matters — Manufactured Gas Plants.”
Employees
At September 30, 2007, UGI Utilities had approximately 1,240 employees.
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ENERGY SERVICES
We operate the energy-related businesses described below through various subsidiaries.
Natural Gas and Electricity Marketing
UGI Energy Services, Inc. (“ESI”) conducts our energy marketing business under the trade names
GASMARK® and POWERMARK®. ESI sells natural gas directly to approximately 11,000 commercial and
industrial customers in Pennsylvania, New Jersey, Delaware, Maryland, Virginia, West Virginia, New
York, Ohio, North Carolina and the District of Columbia through the use of the transportation
systems of 33 utility systems. ESI sells liquid fuel and LPG to commercial and industrial customers
in Pennsylvania, New Jersey, Maryland, Delaware, New York and Virginia. ESI also sells electricity
in New Jersey, Delaware and Maryland.
The gas marketing business is a high revenue, low margin business. A majority of ESI’s
commodity sales are made under fixed-price agreements. ESI manages supply cost volatility related
to these agreements by (i) entering into exchange-traded natural gas futures contracts which are
guaranteed by the New York Mercantile Exchange and have nominal credit risk, (ii) entering into
fixed-price supply arrangements with a diverse group of natural gas producers and holders of
interstate pipeline capacity, (iii) entering into over-the-counter natural gas derivative
arrangements with major international banks and (iv) utilizing supply assets that it owns or
manages. ESI also bears the risk for balancing and delivering natural gas to its customers under
various pipelines and utility company tariffs. See “Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Market Risk Disclosures.”
Credit is another risk factor in the commodity marketing business. ESI bears the risks of
customer defaults and supplier non-performance on commodity and pipeline capacity contracts. ESI
seeks to mitigate risk of supplier defaults by diversifying its supply and pipeline transportation
purchases across a number of suppliers. ESI uses credit insurance to mitigate a portion of the risk
of customer defaults. ESI also requires credit support from certain customers in higher-risk
transactions. This credit support can take the form of prepayments, electronic fund transfers,
bonds and letters of credit.
Peaking and Asset Management Services
ESI operates a natural gas liquefaction, storage and vaporization facility in Temple,
Pennsylvania, and propane storage and propane-air mixing stations in Bethlehem, Reading and
Steelton, Pennsylvania. It also operates a propane storage and rail trans-shipment terminal in
Steelton, Pennsylvania. These assets are used in ESI’s energy peaking business that provides
supplemental energy, primarily liquefied natural gas and propane-air mixtures, to gas utilities at
times of peak demand. In fiscal year 2007, ESI built two propane air plants which expanded its
overall peaking capacity. ESI also made improvements at its LNG plant and its
three other propane air plants which are expected to expand capacity at those plants in fiscal year
2008. ESI also manages natural gas pipeline and storage contracts for UGI Gas.
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Through its subsidiary, Atlantic Energy, Inc., ESI sells propane to large multi-state
retailers, including AmeriGas Partners, and to smaller local dealers throughout Virginia and
northeast North Carolina from its propane import and trans-shipment facility located in Chesapeake,
Virginia.
Electric Generation
We have an approximate 6% (102 megawatts) ownership interest in the Conemaugh generating
station (“Conemaugh”), a 1,711 megawatt, coal-fired generation station located near Johnstown,
Pennsylvania. Conemaugh is owned by a consortium of energy companies and operated by a unit of
Reliant Resources, Inc. In March 2006, our subsidiary, UGI Development Company (“UGID”), sold its
50% ownership interest in Hunlock Creek Energy Ventures (“Energy Ventures”) to Allegheny Energy
Supply Hunlock Creek, LLC. Energy Ventures’ assets primarily comprised a 44-megawatt gas-fired
combustion turbine electric generator and the Hunlock Station 47-megawatt coal-fired electric
generation facility. As part of the consideration in this sale, Energy Ventures transferred the
Hunlock Station 47-megawatt coal-fired electric generation facility to UGID. The output from these
generation assets is sold by UGID on the spot market and under fixed-term contracts. UGID has FERC
authority to sell power at market-based rates.
Government Regulation
FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales
of electric capacity and energy, as well as the purchase or sale of natural gas and transportation
services. As stated above, UGID has a tariff on file with FERC pursuant to which it may make power
sales to wholesale customers at market-based rates. UGID is also subject to FERC market
manipulation rules and enforcement and regulatory powers. See “Gas Utility and Electric Utility
Regulation and Rates — FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory
Powers.”
The operation of Hunlock Station complies with the air quality standards of the
Pennsylvania Department of Environmental Protection (“DEP”) with respect to stack emissions. Under
the Federal Water Pollution Control Act, Hunlock Station has a permit from the DEP to discharge
water into the North Branch of the Susquehanna River. The Federal Clean Air Act Amendments of 1990
(the “Clean Air Act Amendments”) impose emissions limitations for certain compounds, including
sulfur dioxide and nitrous oxides. Both the Conemaugh Station and the Hunlock Station are in
material compliance with these current emission standards. New environmental regulations related
to sulfur dioxide allowances and mercury emission standards have recently been enacted by the DEP
and will take effect in 2009-2010. UGID is currently assessing the operational impact of
compliance with these new regulatory standards.
ESI is subject to various federal, state and local environmental, safety and transportation
laws and regulations governing the storage, distribution and transportation of propane and the
operation of bulk storage LPG terminals. These laws include, among others, the Resource
Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability
Act (“CERCLA” or, the “Superfund Law”), the Clean Air Act, the Occupational
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Safety and Health Act, the Homeland Security Act of 2002, the Emergency Planning and Community
Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA imposes joint and
several liability on certain classes of persons considered to have contributed to the release or
threatened release of a “hazardous substance” into the environment without regard to fault or the
legality of the original conduct. Propane is not a hazardous substance within the meaning of
federal and most state environmental laws.
Employees
At September 30, 2007, ESI and its subsidiaries had approximately 190 employees.
HVAC/R
We conduct a heating, ventilation, air-conditioning, refrigeration and electrical contracting
service business through UGI HVAC Enterprises, Inc. (“HVAC/R”) serving portions of eastern
Pennsylvania and the Mid-Atlantic region, including the Philadelphia suburbs and portions of New
Jersey and northern Delaware. This business serves more than 150,000 customers in residential,
commercial, industrial and new construction markets. During fiscal year 2007, HVAC/R generated
approximately $94 million in revenues and employed approximately 570 people.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income (loss) and identifiable assets
attributable to each of UGI’s reportable business segments, and to the geographic areas in which we
operate, for the 2007, 2006 and 2005 fiscal years appears in Note 16 to the Consolidated Financial
Statements included in Item 8 of this Report and is incorporated herein by reference.
EMPLOYEES
At September 30, 2007, UGI and its subsidiaries had approximately 9,500 employees.
ITEM 1A. RISK FACTORS
Decreases in the demand for our energy products and services because of warmer-than-normal
heating season weather may adversely affect our results of operations.
Because many of our customers rely on our energy products and services to heat their homes and
businesses, our results of operations are adversely affected by warmer-than-normal heating season
weather. Weather conditions have a significant impact on the demand for our energy products and
services for both heating and agricultural purposes. Accordingly, the volume of our energy products
sold is at its highest during the five-month peak heating season of
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November through March and is directly affected by the severity of the winter weather. For
example, historically, approximately 55% to 60% of AmeriGas Partners’ annual retail propane volume
has been sold during these months and approximately 55% to 60% of our natural gas throughput (the
total volume of gas sold to or transported for customers within our distribution system) occurs
during these months. Antargaz’ sales volume is similarly seasonal. There can be no assurance that
normal winter weather in our market areas will occur in the future.
Our holding company structure could limit our ability to pay dividends or debt service.
We are a holding company whose material assets are the stock of our subsidiaries and interests
in joint ventures. Accordingly, we conduct all of our operations through our subsidiaries and joint
venture affiliates. Our ability to pay dividends on our common stock and to pay principal and
accrued interest on our debt, if any, depends on the payment of dividends to us by our principal
subsidiaries, AmeriGas, Inc., UGI Utilities, Inc. and UGI Enterprises, Inc. (including Antargaz).
Payments to us by those subsidiaries, in turn, depend upon their consolidated results of operations
and cash flows and, in the case of AmeriGas Partners, the provisions of its partnership agreement.
The operations of our subsidiaries are affected by conditions beyond our control, including
weather, competition in national and international markets we serve, the costs and availability of
propane, butane, natural gas, electricity and other energy sources and changes in capital market
conditions. The ability of our subsidiaries to make payments to us is also affected by the level of
indebtedness of our subsidiaries, which is substantial, and the restrictions on payments to us
imposed under the terms of such indebtedness.
Our profitability is subject to propane pricing and inventory risk.
The retail propane business is a “margin-based” business in which gross profits are dependent
upon the excess of the sales price over the propane supply costs. Propane is a commodity, and, as
such, its unit price is subject to volatile fluctuations in response to changes in supply or other
market conditions. We have no control over these market conditions. Consequently, the unit price of
the propane that our subsidiaries and other marketers purchase can change rapidly over a short
period of time. Most of our domestic propane product supply contracts permit suppliers to charge
posted prices at the time of delivery or the current prices established at major U.S. storage
points such as Mont Belvieu, Texas or Conway, Kansas. Most of our international propane supply
contracts are based on internationally quoted market prices. Because our subsidiaries’
profitability is sensitive to changes in wholesale propane supply costs, it will be adversely
affected if we cannot pass on increases in the cost of propane to our customers. Due to competitive
pricing in the propane industry, our subsidiaries, may not be able to pass on product cost
increases to our customers when product costs rise rapidly, or when our competitors do not raise
their product prices. Finally, market volatility may cause our subsidiaries to sell propane at less
than the price at which they purchased it, which would adversely affect our operating results.
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Energy efficiency and technology advances, as well as price induced customer conservation,
may result in reduced demand for our energy products and services.
The trend toward increased conservation and technological advances, including installation of
improved insulation and the development of more efficient furnaces and other heating devices, may
reduce the demand for energy products. Prices for propane and natural gas are subject to volatile
fluctuations in response to changes in supply and other market conditions. During periods of high
energy commodity costs, our prices generally increase which may lead to customer conservation. We
cannot predict the materiality of the effect of future conservation measures or the effect that any
technological advances in heating, conservation, energy generation or other devices might have on
our operations.
Supplier defaults may have a negative effect on our operating results.
When the Company enters into fixed — price sales contracts with customers, it also enters into
fixed — price purchase contracts with suppliers. Depending on changes in the market prices of
products compared to the prices secured in our contracts with suppliers of LPG, electricity and
natural gas, a default of one or more of our suppliers under such contracts could cause us to
purchase LPG, electricity and natural gas at higher prices which would have a negative impact on
our operating results.
Changes in commodity market prices may have a negative effect on our liquidity.
Depending on the terms of our contracts with suppliers and some large customers, and for all
of our contracts with the NYMEX, a change in the market price of LPG, electricity or natural gas
could create a margin payment obligation for the Company or one of its subsidiaries and expose us
to an increased liquidity risk.
Our operations may be adversely affected by competition from other energy sources.
Our energy products and services face competition from other energy sources, some of which are
less costly for equivalent energy value. In addition, we cannot predict the effect that the
development of alternative energy sources might have on our operations.
Our propane businesses compete for customers against suppliers of electricity, fuel oil and
natural gas. Electricity is a major competitor of propane, but propane generally enjoys a
competitive price advantage over electricity for space heating, water heating and cooking. Fuel oil
is also a major competitor of propane and is generally less expensive than propane. Furnaces and
appliances that burn propane will not operate on fuel oil and vice versa, and, therefore, a
conversion from one fuel to the other requires the installation of new equipment. Our customers
generally have an incentive to switch to fuel oil only if fuel oil becomes significantly less
expensive than propane. Except for certain industrial and commercial applications, propane is
generally not competitive with natural gas in areas where natural gas pipelines already exist
because natural gas is generally a less expensive source of energy than propane. The gradual
expansion of natural gas distribution systems in our service areas has resulted, and may continue
to result, in the availability of natural gas in some areas that previously depended upon propane.
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As long as natural gas remains a less expensive energy source than propane, our propane business
will lose customers in each region into which natural gas distribution systems are expanded. In
France, the state-owned natural gas monopoly, Gaz de France, has in the past extended France’s
natural gas grid.
Our natural gas businesses compete primarily with electricity and fuel oil, and, to a lesser
extent, with propane and coal. Competition among these fuels is primarily a function of their
comparative price and the relative cost and efficiency of fuel utilization equipment. There can be
no assurance that our natural gas revenues will not be adversely affected by this competition.
Our ability to increase revenues is adversely affected by the maturity of the retail propane
industry.
The retail propane industry in the U.S., France and Austria is mature, with only modest growth
in total demand for the product foreseen. Given this limited growth, we expect that year-to-year
industry volumes will be principally affected by weather patterns. Therefore, our ability to grow
within the propane industry is dependent on our ability to acquire other retail distributors and to
achieve internal growth, which includes expansion of the AmeriGas Cylinder Exchange and Strategic
Accounts programs, as well as the success of our sales and marketing programs designed to attract
and retain customers. Any failure to retain and grow our customer base would have an adverse effect
on our results.
Our ability to grow our businesses will be adversely affected if we are not successful in
making acquisitions or integrating the acquisitions we have made.
One of our strategies is to grow through acquisitions in the United States and in
international markets. We may choose to finance future acquisitions with debt, equity, cash or a
combination of the three. We can give no assurances that we will find attractive acquisition
candidates in the future, that we will be able to acquire such candidates on economically
acceptable terms, that any acquisitions will not be dilutive to earnings or that any additional
debt incurred to finance an acquisition will not affect our ability to pay dividends.
In addition, the restructuring of the energy markets in the United States and internationally,
including the privatization of government-owned utilities and the sale of utility-owned assets, is
creating opportunities for, and competition from, well-capitalized competitors, which may affect
our ability to achieve our business strategy.
To the extent we are successful in making acquisitions, such acquisitions involve a number of
risks, including, but not limited to, the assumption of material liabilities, the diversion of
management’s attention from the management of daily operations to the integration of operations,
difficulties in the assimilation and retention of employees and difficulties in the assimilation of
different cultures and practices, as well as in the assimilation of broad and geographically
dispersed personnel and operations. The failure to successfully integrate acquisitions could have
an adverse effect on our business, financial condition and results of operations.
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Our need to comply with comprehensive, complex, and sometimes unpredictable government
regulations may increase our costs and limit our revenue growth, which may result in reduced
earnings.
While we generally refer to our Gas Utility and Electric Utility segments as our “regulated
segments,” there are many governmental regulations that have an impact on our businesses. Existing
statutes and regulations may be revised or reinterpreted and new laws and regulations may be
adopted or become applicable to the Company which may affect our businesses in ways that we cannot
predict.
In our Gas Utility and Electric Utility segments, our operations are subject to regulation by
the PUC. The PUC, among other things, approves the rates that UGI Utilities and UGIPNG may charge
to its utility customers, thus impacting the returns that UGI Utilities and UGIPNG may earn on the
assets that are dedicated to those operations. If UGI Utilities or UGIPNG are required in a rate
proceeding to reduce the rates they charge their utility customers, or if UGI Utilities or UGIPNG
are unable to obtain approval for rate increases from the PUC, particularly when necessary to cover
increased costs, UGI Utilities’ and UGIPNG’s revenue growth will be limited and their earnings may
decrease.
We are subject to operating and litigation risks that may not be covered by insurance.
Our business operations in the U.S. and other countries are subject to all of the operating
hazards and risks normally incidental to the handling, storage and distribution of combustible
products, such as LPG, propane and natural gas, and the generation of electricity. 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. As a result, we
are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of
business. We believe that we are adequately insured for claims in excess of our self-insurance;
however, certain types of damages, such as punitive damages and penalties, if any, may not be
covered by insurance. There can be no assurance that our insurance will be adequate to protect us
from all material expenses related to pending and future claims or that such levels of insurance
will be available in the future at economical prices.
We may be unable to respond effectively to competition, which may adversely affect our
operating results.
We may be unable to timely respond to changes within the energy and utility sectors that may
result from regulatory initiatives to further increase competition within our industry. Such
regulatory initiatives may create opportunities for additional competitors to enter our markets
and, as a result, we may be unable to maintain our revenues or continue to pursue our current
business strategy.
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Our net income will decrease if we are required to incur additional costs to comply with new
governmental safety, health, transportation and environmental regulations.
We are subject to extensive and changing international, federal, state and local safety,
health, transportation and environmental laws and regulations governing the storage, distribution
and transportation of our energy products.
New regulations, or a change in the interpretation of existing regulations, could result in
increased expenditures. In addition, for many of our operations, we are required to obtain permits
from regulatory authorities. Failure to comply with these permits or applicable laws could result
in civil and criminal fines or the cessation of the operations in violation. Governmental
regulations and policies in the United States and Europe may provide for subsidies or incentives to
customers who use alternative fuels instead of carbon fuels. These subsidies and incentives may
result in reduced demand for our energy products and services.
We are investigating and remediating contamination at a number of present and former operating
sites in the U.S., including former sites where we or our former subsidiaries operated manufactured
gas plants. We have also received claims from third parties that allege that we are responsible for
costs to clean up properties where we or our former subsidiaries operated a manufactured gas plant
or conducted other operations. Costs we incur to remediate sites outside of Pennsylvania cannot be
recovered in future UGI Utilities’ rate proceedings, and insurance may not cover all or even part
of these costs. Our actual costs to clean up these sites may exceed our current estimates due to
factors beyond our control, such as:
| • | the discovery of presently unknown conditions; |
||
| • | changes in environmental laws and regulations; |
||
| • | judicial rejection of our legal defenses to the third-party claims; or |
||
| • | the insolvency of other responsible parties at the sites at which we are involved. |
In addition, if we discover additional contaminated sites, we could be required to incur
material costs, which would reduce our net income.
The expansion of our international business means that we will face increased risks, which
may negatively affect our business results.
Our acquisition of Antargaz in March of 2004 significantly increased our international
presence. As we continue to add new subsidiaries and enter into new joint ventures in countries
around the world, we face risks in doing business abroad that we do not face domestically. Certain
aspects inherent in transacting business internationally could negatively impact our operating
results, including:
| • | costs and difficulties in staffing and managing international operations; |
||
| • | tariffs and other trade barriers; |
||
| • | difficulties in enforcing contractual rights; |
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| • | longer payment cycles; |
||
| • | local political and economic conditions; |
||
| • | potentially adverse tax consequences, including restrictions on
repatriating earnings and the threat of “double taxation”; |
||
| • | fluctuations in currency exchange rates, which can affect demand and
increase our costs; and |
||
| • | regulatory requirements and changes in regulatory requirements, including
French and EU competition laws that may adversely affect the terms of contracts with
customers, and stricter regulations applicable to the storage and handling of LPG. |
In June 2005, officials from France’s General Division of Competition, Consumption and Fraud
Punishment (“DGCCRF”) conducted an unannounced inspection of, and obtained documents from,
Antargaz’ headquarters building. Management believes that the DGCCRF performed similar unannounced
inspections and document seizures at the locations of other distributors of LPG in France, as well
as the industry association, Comite Francais du Butane et du Propane (“CFBP”). The DGCCRF
apparently sought evidence of unlawful anticompetitive activities affecting the packaged LPG (i.e.,
cylinder) business in northern France.
Antargaz did not have any further contact with the DGCCRF regarding this matter until February
2007, when it received a letter from the DGCCRF requesting documents and information relating to
Antargaz’ pricing policies and practices. In March 2007 and then in August 2007, the DGCCRF
requested additional information from Antargaz and three joint ventures in which it participates.
Based on these requests, it appears that the DGCCRF has expanded the scope of its investigation to
include both bulk and cylinder markets throughout France. We do not believe Antargaz is in
violation of France’s competition laws.
Based on a March 2007 newspaper article, we believe that France’s Conseil de la Concurrence
(“Competition Council”) is conducting a related investigation regarding alleged concerted behavior
among certain distributors of LPG in France. The article stated that one of the companies under
investigation had applied for leniency, pursuant to the French law that allows a company to offer
evidence of anti-competitive behavior in exchange for partial or total amnesty from financial
sanctions. The company seeking leniency may present testimony or other evidence of anti-competitive
activities that are adverse to Antargaz’ interests. As a part of any investigation, the Competition
Council and the DGCCRF may uncover information from other sources, including customers, suppliers
or employees of Antargaz and other LPG companies, that may be adverse to Antargaz’ interests.
Management intends to continue to cooperate with the DGCCRF investigation and any
investigation that may be initiated. At this time, the French authorities have not made any claim
against Antargaz. However, in the event a claim is made against Antargaz and it is found to have
violated the competition laws in France, it would be subject to civil penalties up to a maximum of
10% of the total annual revenues of UGI.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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ITEM 3. LEGAL PROCEEDINGS
With the exception of the matters set forth below, no material legal proceedings are pending
involving UGI, any of its subsidiaries, or any of their properties, and no such proceedings are
known to be contemplated by governmental authorities other than claims arising in the ordinary
course of business.
Environmental Matters — Manufactured Gas Plants
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and
operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural
gas. Some constituents of coal tars and other residues of the manufactured gas process are today
considered hazardous substances under the Superfund Law and may be present on the sites of former
MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in
Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement.
Pursuant to the requirements of the Public Utility Holding Company Act of 1935, UGI Utilities
divested all of its utility operations other than those which now constitute UGI Gas and Electric
Utility by the early 1950s.
UGI Utilities does not expect its costs for investigation and remediation of hazardous
substances at Pennsylvania MGP sites to be material to its results of operations because UGI
Utilities (excluding UGIPNG) is currently permitted to include in rates, through future base rate
proceedings, prudently incurred remediation costs associated with such sites. In accordance with
the terms of the UGIPNG base rate case order which became effective December 2, 2006,
site-specified environmental investigation and remediation costs associated with UGIPNG
incurred prior to December 2, 2006 are amortized as removal costs over five-year periods. Such
costs incurred after December 2, 2006 are expensed as incurred.
As a result of the acquisition of PG Energy by UGI Utilities’ wholly owned subsidiary, UGIPNG,
UGIPNG became party to a Multi-site Remediation Consent Order and Agreement between PG Energy and
the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site
Agreement”). The Multi-Site Agreement requires UGIPNG to perform annually a specified level of
activities associated with environmental investigation and remediation work at 11 currently owned
properties on which MGP-related facilities were operated (“Properties”). Under the Multi-Site
Agreement, environmental expenditures, including costs to perform work on the Properties, are
capped at $1.1 million in any calendar year. Costs related to investigation and remediation of one
property formerly owned by UGIPNG are also included in this cap. The Multi-Site Agreement
terminates in 2019 but may be terminated by either party at the end of any two-year
period beginning with the effective date.
UGI Utilities has been notified of several sites outside Pennsylvania on which private parties
allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by its former
subsidiaries. Such parties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities is currently litigating four claims against it
relating to out-of-state sites.
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City of Bangor, Maine v. Citizens Communications Co. In April 2003, Citizens
Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party
defendant in a civil action pending in the United States District Court for the District of Maine.
In that action, the plaintiff, City of Bangor, Maine (“City”), sued Citizens to recover
environmental response costs associated with MGP wastes generated at a plant allegedly operated by
Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities
and ten other third-party defendants alleging that the third-party defendants are responsible for
an equitable share of costs Citizens may be required to pay to the City for cleaning up tar
deposits in the Penobscot River. Citizens alleges that UGI Utilities and its predecessors owned and
operated the plant from 1901 to 1928. Studies conducted by the City and Citizens suggest that it
could cost up to $18 million to clean up the river. Citizens’ third-party claims have been stayed
pending a resolution of the City’s suit against Citizens, which was tried in September 2005.
Maine’s Department of Environmental Protection (“DEP”) informed UGI Utilities in March of 2005 that
it considers UGI Utilities to be a potentially responsible party for costs incurred by the State of
Maine related to gas plant contaminants at this site. On June 27, 2006, the court issued an order
finding Citizens responsible for 60% of the cleanup costs. Citizens and the City subsequently
entered into a settlement agreement pursuant to which Citizens agreed to pay $7.6 million in
exchange for a release of its and all predecessors’ liabilities. UGI Utilities is evaluating what
effect the settlement agreement would have on any claims against it. UGI Utilities believes that
it has good defenses to any claim that the DEP may bring to recover its costs, and is defending the Citizens’ suit.
Consolidated Edison Company of New York v. UGI Utilities, Inc. On September 20, 2001,
Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the United
States District Court for the Southern District of New York, seeking contribution from UGI
Utilities for an allocated share of response costs associated with investigating and assessing gas
plant related contamination at former MGP sites in Westchester County, New York. The complaint
alleges that UGI Utilities “owned and operated” the MGPs prior to 1904. The complaint also seeks a
declaration that UGI Utilities is responsible for an allocated percentage of future investigative
and remedial costs at the sites.
The trial court granted UGI Utilities’ motion for summary judgment and dismissed ConEd’s
complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed and on
September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and reversed in
part the decision of the trial court. The appellate panel affirmed the trial court’s decision
dismissing claims that UGI Utilities was liable under CERCLA as an operator of MGPs owned and
operated by its former subsidiaries. The appellate panel reversed the trial court’s decision that
UGI Utilities was released from liability at three sites where UGI Utilities operated MGPs under
lease. ConEd claims that the cost of remediation of the three sites would be approximately $14
million. On October 7, 2005, UGI Utilities filed for reconsideration of the panel’s order, which
was denied by the Second Circuit Court of Appeals on January 17, 2006. On April 14, 2006, UGI
Utilities filed a petition requesting that the United States Supreme Court review the decision of
the Second Circuit Court of Appeals. On June 18, 2007, the United States Supreme Court denied UGI
Utilities’ petition. This case has been remanded back to the trial court. UGI Utilities is defending the suit.
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Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”)
informed UGI Utilities that KeySpan has spent $2.3 million and expects to spend
another $11 million to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes
that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI
Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated
June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has
approved a remedy for the site that is estimated to cost approximately $10 million. KeySpan
believes that the cost could be as high as $20 million. UGI Utilities is in the process of
reviewing the information provided by KeySpan and is investigating this claim.
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities,
Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services
Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities, (together the
“Northeast Companies”) in the United States District Court for the District of Connecticut seeking
contribution from UGI Utilities for past and future remediation costs related to MGP operations on
thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The
Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to
1941. The Northeast Companies estimate that remediation costs for all of the sites would total
approximately $215 million and assert that UGI Utilities is responsible for approximately $103
million of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’
own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury
North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast
Companies’ estimate that remediation costs at Waterbury North could total $23 million. UGI
Utilities is defending the suit.
South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006,
South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit
against UGI Utilities in the United States District Court for the District of South Carolina
seeking contribution from UGI Utilities for past and future remediation costs related to the
operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant
operated from 1855 to 1954 and alleges that UGI Utilities controlled operations of the plant from
1910 to 1926 and is liable for 47% of the costs associated with the site. SCE&G asserts that it has
spent approximately $22 million in remediation costs and $26 million in third-party claims relating
to the site and estimates that future remediation costs could be as high as $2.5 million. SCE&G
further asserts that it has received a demand from the United States Justice Department for natural
resource damages. UGI Utilities is defending the suit.
Other Matters
Swiger, et al. v. UGI/AmeriGas, Inc. et al. Plaintiffs Samuel and Brenda Swiger and
their son (the “Swigers”) sustained personal injuries and property damage as a result of a fire
that occurred when propane that leaked from an underground line ignited. In July 1998, the Swigers
filed a class action lawsuit against AmeriGas Propane L.P. (named incorrectly as “UGI/AmeriGas,
Inc.”), in the Circuit Court of Monongalia County, West Virginia (Civil Action No. 98-C-298), in
which they sought to recover an unspecified amount of compensatory and punitive damages and
attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants
had installed propane gas lines, allegedly resulting from the defendants’ failure to install
underground propane lines at depths required by applicable safety standards. In
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2003, AmeriGas Propane, L.P. settled the individual personal injury and property damage claims of
the Swigers. In 2004, the court granted the plaintiffs’ motion to include customers acquired from
Columbia Propane in August 2001 as additional potential class members, and the plaintiffs amended
their complaint to name additional parties pursuant to such ruling. Subsequently, in March 2005,
AmeriGas Propane, L.P. filed a cross-claim against Columbia Energy Group, former owner of Columbia
Propane, seeking indemnification for conduct undertaken by Columbia Propane prior to AmeriGas
Propane, L.P’s acquisition. Class counsel has indicated that the class is seeking compensatory
damages in excess of $12 million plus punitive damages, civil penalties and attorneys’ fees. The
defendants believe they have good defenses to the claims of the class members and intend to
vigorously defend against the remaining claims in this lawsuit.
Antargaz Competition Authority Matter. In June 2005, officials from France’s General
Division of Competition, Consumption and Fraud Punishment (“DGCCRF”) conducted an unannounced
inspection of, and obtained documents from, Antargaz’ headquarters building. Management believes
that the DGCCRF performed similar unannounced inspections and document seizures at the locations of
other distributors of LPG in France, as well as the industry association, Comite Francais du Butane
et du Propane (“CFBP”). The DGCCRF apparently sought evidence of unlawful anticompetitive
activities affecting the packaged LPG (i.e., cylinder) business in northern France.
Antargaz did not have any further contact with the DGCCRF regarding this matter until February
2007, when it received a letter from the DGCCRF requesting documents and information relating to
Antargaz’ pricing policies and practices. In March 2007, and again in August 2007, the DGCCRF
requested additional information from Antargaz and three joint ventures in which it participates.
Based on these requests, it appears that the DGCCRF has expanded the scope of its investigation to
include both bulk and cylinder markets throughout France. We do not believe Antargaz is in
violation of France’s competition laws.
Based on a March 2007 newspaper article, we believe that France’s Conseil de la Concurrence
(“Competition Council”) is conducting a related investigation regarding alleged concerted behavior
among certain distributors of LPG in France. The article stated that one of the companies under
investigation had applied for leniency, pursuant to the French law that allows a company to offer
evidence of anti-competitive behavior in exchange for partial or total amnesty from financial
sanctions. The company seeking leniency may present testimony or other evidence of anti-competitive
activities that are adverse to Antargaz’ interests. As part of any investigation, the Competition
Council and the DGCCRF may uncover information from other sources, including customers, suppliers
or employees of Antargaz and other LPG companies, that may be adverse to Antargaz’ interests.
Management intends to continue to cooperate with the DGCCRF investigation and any
investigation that may be initiated. At this time, the French authorities have not made any claim
against Antargaz. However, in the event a claim is made against Antargaz and it is found to have
violated the competition laws in France, it would be subject to civil penalties up to a maximum of
10% of the total annual revenues of UGI.
37
Table of Contents
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the last fiscal quarter of fiscal
year 2007.
EXECUTIVE OFFICERS
Information regarding our executive officers is included in Part III of this Report and is
incorporated in Part I by reference.
PART II:
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES |
Market Information
Our Common Stock is traded on the New York and Philadelphia Stock Exchanges under the symbol
“UGI.” The following table sets forth the high and low sales prices for the Common Stock on the New
York Stock Exchange Composite Transactions tape as reported in
The
Wall Street Journal for each
full quarterly period within the two most recent fiscal years:
| 2007 Fiscal Year | High | Low | ||||||
4th Quarter |
$ | 28.30 | $ | 22.75 | ||||
3rd Quarter |
29.63 | 25.77 | ||||||
2nd Quarter |
27.94 | 24.10 | ||||||
1st Quarter |
29.00 | 24.26 | ||||||
| 2006 Fiscal Year | High | Low | ||||||
4th Quarter |
$ | 25.73 | $ | 23.74 | ||||
3rd Quarter |
24.75 | 20.93 | ||||||
2nd Quarter |
22.85 | 20.60 | ||||||
1st Quarter |
28.64 | 20.21 | ||||||
38
Table of Contents
Dividends
Quarterly dividends on our Common Stock were paid in the 2007 and 2006 fiscal years as
follows:
| 2007 Fiscal Year | Amount | |||
4th Quarter |
$ | 0.18500 | ||
3rd Quarter |
0.17625 | |||
2nd Quarter |
0.17625 | |||
1st Quarter |
0.17625 | |||
| 2006 Fiscal Year | Amount | |||
4th Quarter |
$ | 0.17625 | ||
3rd Quarter |
0.16875 | |||
2nd Quarter |
0.16875 | |||
1st Quarter |
0.16875 | |||
Record Holders
On November 23, 2007, UGI had 8,500 holders of record of Common Stock.
39
Table of Contents
ITEM 6. SELECTED FINANCIAL DATA
| Year Ended | ||||||||||||||||||||
| September 30, | ||||||||||||||||||||
| 2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
| (Millions of dollars, except per share amounts) | ||||||||||||||||||||
FOR THE PERIOD: |
||||||||||||||||||||
Income statement data: |
||||||||||||||||||||
Revenues |
$ | 5,476.9 | $ | 5,221.0 | $ | 4,888.7 | $ | 3,784.7 | $ | 3,026.1 | ||||||||||
Net income |
$ | 204.3 | $ | 176.2 | $ | 187.5 | $ | 111.6 | $ | 98.9 | ||||||||||
Earnings per common share: |
||||||||||||||||||||
Basic net income |
$ | 1.92 | $ | 1.67 | $ | 1.81 | $ | 1.18 | $ | 1.17 | ||||||||||
Diluted net income |
$ | 1.89 | $ | 1.65 | $ | 1.77 | $ | 1.15 | $ | 1.14 | ||||||||||
Cash dividends declared per common share |
$ | 0.723 | $ | 0.690 | $ | 0.650 | $ | 0.598 | $ | 0.565 | ||||||||||
AT PERIOD END: |
||||||||||||||||||||
Balance sheet data: |
||||||||||||||||||||
Total assets |
$ | 5,502.7 | $ | 5,080.5 | $ | 4,571.5 | $ | 4,242.6 | $ | 2,795.2 | ||||||||||
Capitalization: |
||||||||||||||||||||
Debt: |
||||||||||||||||||||
Bank loans — UGI Utilities |
$ | 190.0 | $ | 216.0 | $ | 81.2 | $ | 60.9 | $ | 40.7 | ||||||||||
Bank loans — other |
8.9 | 9.4 | 16.2 | 17.2 | 15.9 | |||||||||||||||
Long-term debt (including current maturities): |
||||||||||||||||||||
AmeriGas Propane |
933.1 | 933.7 | 913.5 | 901.4 | 927.3 | |||||||||||||||
Antargaz |
544.9 | 483.5 | 431.1 | 474.5 | — | |||||||||||||||
UGI Utilities |
512.0 | 512.0 | 237.0 | 217.2 | 217.3 | |||||||||||||||
Other |
63.5 | 67.7 | 62.9 | 76.9 | 78.9 | |||||||||||||||
Total debt |
2,252.4 | 2,222.3 | 1,741.9 | 1,748.1 | 1,280.1 | |||||||||||||||
Minority interests, principally in AmeriGas Partners |
192.2 | 139.5 | 206.3 | 178.4 | 134.6 | |||||||||||||||
UGI Utilities preferred shares subject
to mandatory redemption |
— | — | — | 20.0 | 20.0 | |||||||||||||||
Common stockholders’ equity |
1,321.9 | 1,099.6 | 997.6 | 834.1 | 498.7 | |||||||||||||||
Total capitalization |
$ | 3,766.5 | $ | 3,461.4 | $ | 2,945.8 | $ | 2,780.6 | $ | 1,933.4 | ||||||||||
Ratio of capitalization: |
||||||||||||||||||||
Total debt |
59.8 | % | 64.2 | % | 59.1 | % | 62.9 | % | 66.2 | % | ||||||||||
Minority interests, principally in AmeriGas Partners |
5.1 | % | 4.0 | % | 7.0 | % | 6.4 | % | 7.0 | % | ||||||||||
UGI Utilities preferred shares subject
to mandatory redemption |
— | — | — | 0.7 | % | 1.0 | % | |||||||||||||
Common stockholders’ equity |
35.1 | % | 31.8 | % | 33.9 | % | 30.0 | % | 25.8 | % | ||||||||||
| 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | |||||||||||
40
Table of Contents
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Business Overview
UGI Corporation (“UGI”) is a holding company that, through subsidiaries and joint-venture
affiliates, distributes and markets energy products and related services. We are a domestic
and international distributor of propane and butane which are liquefied petroleum gases
(“LPG”); a provider of natural gas and electric service through regulated local distribution
utilities; a generator of electricity through our ownership interests in electric generation
facilities; a regional marketer of energy commodities; and a regional provider of heating,
air conditioning, refrigeration and electrical services.
We conduct a national propane distribution business through AmeriGas Partners, L.P.
(“AmeriGas Partners”) and its principal operating subsidiaries AmeriGas Propane, L.P. and
AmeriGas Eagle Propane, L.P. At September 30, 2007, UGI, through its wholly owned
second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”), held an approximate
44% effective interest in AmeriGas Partners. We refer to AmeriGas Partners and its
subsidiaries together as the “Partnership” and the General Partner and its subsidiaries,
including the Partnership, as “AmeriGas Propane.”
Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries (1)
conducts an LPG distribution business in France; (2) conducts LPG distribution businesses
and participates in an LPG joint-venture business in central and eastern Europe
(collectively, “Flaga”); and (3) participates in an LPG joint-venture business in the
Nantong region of China. Our LPG distribution business in France is conducted through
Antargaz, an operating subsidiary of AGZ Holding (“AGZ”), and its operating subsidiaries
(collectively, “Antargaz”). We refer to our foreign operations collectively as
“International Propane.”
Our natural gas and electric distribution utility businesses are conducted through UGI
Utilities, Inc. and its subsidiary, UGI Penn Natural Gas, Inc. (“UGIPNG”). The term “UGI
Utilities” is used herein as an abbreviated reference to UGI Utilities, Inc., or UGI
Utilities, Inc. and its subsidiaries collectively, including UGIPNG. UGI Utilities owns and
operates (1) natural gas distribution utilities in eastern and northeastern Pennsylvania
(“UGI Gas” and “PNG Gas,” respectively) and (2) an electric distribution utility in
northeastern Pennsylvania (“Electric Utility”). UGI Gas and PNG Gas are collectively
referred to herein as “Gas Utility.” On August 24, 2006, UGI Utilities, Inc., through
UGIPNG, acquired the natural gas utility business of PG Energy, an operating division of
Southern Union Company (the “PG Energy Acquisition”). The acquired natural gas distribution
business now comprises PNG Gas. Gas Utility and Electric Utility are subject to regulation
by the Pennsylvania Public Utility Commission (“PUC”).
Through other subsidiaries, Enterprises also conducts an energy marketing business
primarily in the Eastern United States (collectively, “Energy Services”). Energy Services’
wholly owned subsidiary UGI Development Company (“UGID”) owns and operates a 48-megawatt
coal-fired electric generation station located in northeastern Pennsylvania and owns an
approximate 6% interest in a 1,711-megawatt coal-fired electric generation station located
in western Pennsylvania. In addition, Energy Services’ wholly owned subsidiary UGI Asset
Management, Inc., through its subsidiary Atlantic Energy, Inc. (collectively, “Asset
Management”), owns a propane storage terminal located in Chesapeake, Virginia. Energy
Services also owns and operates a natural gas liquefaction, storage and vaporization
facility, and propane storage and propane-air mixing assets. Through other Enterprises’ and
UGI Utilities’ subsidiaries, we own and operate heating, ventilation, air-conditioning,
refrigeration and electrical contracting services businesses in the Middle Atlantic states
(“HVAC/R”).
This financial review should be read in conjunction with our Consolidated Financial
Statements and Notes to Consolidated Financial Statements including the reportable segment
information included in Note 16.
41
Table of Contents
Executive Overview
Our financial results over the three fiscal years ended September 30, 2007 reflect the
benefits of our commitment to grow through acquisitions as well as our continued focus on
executing our strategies in our business units. Our financial results for the year ended
September 30, 2007 (“fiscal 2007”) reflect the full-year effects of two significant
transactions completed during fiscal 2006. Those two transactions include the August 2006
$567 million acquisition of PG Energy and the February 2006 formation of our joint venture,
Zentraleuropa LPG Holding GmbH (“ZLH”), to distribute LPG in Eastern Europe. Fiscal 2007
financial results reflect better financial performance from our domestic businesses,
including the full-year results of PNG Gas, greater income contributions from AmeriGas
Propane and
Energy Services, and higher net income from Electric Utility. Even though fiscal 2007
weather in our domestic service territories was colder than fiscal 2006, it remained warmer
than normal. Despite the improved operating performance from our domestic businesses in
fiscal 2007, the effects of record-setting warm temperatures in our European International
Propane service territories resulted in significantly lower International Propane results.
Similar to our domestic operations, heating-season temperatures in our International Propane
service territories have a significant influence on operating performance. In our European
LPG markets, the combination of the significantly warmer than normal weather and
historically high and volatile commodity prices resulted in lower customer consumption and
increased competitive pressures from other LPG distributors and alternative fuels.
Although weather in our domestic service territories was generally colder than in the prior
year, the warmer than normal weather reduced our expected heating-related sales volumes and
the full earnings benefits from the PG Energy Acquisition. However, the negative sales
impact from the warmer than normal weather was offset by the effect on net income of the
Partnership’s July 2007 sale of its Arizona LPG storage facility, higher average AmeriGas
Propane unit margins and higher unit margins from Energy Services’ natural gas marketing
business. Energy Services’ improved performance in fiscal 2007 also reflects greater income
from storage management and peaking supply services, and more profitable utilization of
energy commodity storage assets. Electric Utility’s fiscal 2007 results were higher,
notwithstanding greater per-unit purchased power costs, due in large part to the
implementation of higher Provider of Last Resort (“POLR”) rates effective January 1, 2007.
Although total interest expense was higher in fiscal 2007 primarily due to
acquisition-related debt associated with the PG Energy Acquisition, our total interest
expense benefited from the full-year effects of AmeriGas Partners’ and to a lesser extent,
Antargaz’ debt refinancings, completed during the first half of fiscal 2006. Our fiscal
2007 effective income tax rate was higher than in fiscal 2006 principally because fiscal
2006’s effective tax rate reflected management’s lower estimate of taxes to be paid
associated with planned repatriation of foreign earnings.
As in prior years, fiscal 2008 financial results will be significantly influenced by
heating-season temperatures in our domestic and international service territories, the
effects of commodity prices on customer consumption of our products and competition in the
markets we serve. In order to continue our strategy of growing our businesses in markets in
which we have core competencies, we expect to continue to pursue growth through
acquisitions, extend our presence in the markets we serve with new and innovative products
and services, and control our operating costs throughout the organization.
Results of Operations
The following analyses compare the Company’s results of operations for (1) fiscal 2007 with
fiscal 2006 and (2) fiscal 2006 with the year ended September 30, 2005 (“fiscal 2005”).
Fiscal 2007 Compared with Fiscal 2006
Consolidated Results
Consolidated Results
| Variance- Favorable | ||||||||||||||||||||||||
| 2007 | 2006 | (Unfavorable) | ||||||||||||||||||||||
| % of Total | % of Total | |||||||||||||||||||||||
| Net | Net | Net | Net | Net | % | |||||||||||||||||||
| (Millions of dollars) | Income | Income | Income | Income | Income | Change | ||||||||||||||||||
AmeriGas Propane |
$ | 53.2 | 26.0 | % | $ | 25.1 | 14.2 | % | $ | 28.1 | 112.0 | % | ||||||||||||
International Propane |
44.9 | 22.0 | % | 67.1 | 38.1 | % | (22.2 | ) | (33.1 | )% | ||||||||||||||
Gas Utility |
59.0 | 28.9 | % | 38.1 | 21.6 | % | 20.9 | 54.9 | % | |||||||||||||||
Electric Utility |
13.7 | 6.7 | % | 10.5 | 6.0 | % | 3.2 | 30.5 | % | |||||||||||||||
Energy Services |
34.5 | 16.9 | % | 31.3 | 17.8 | % | 3.2 | 10.2 | % | |||||||||||||||
Corporate & Other |
(1.0 | ) | (0.5 | )% | 4.1 | 2.3 | % | (5.1 | ) | N.M. | ||||||||||||||
| $ | 204.3 | 100.0 | % | $ | 176.2 | 100.0 | % | $ | 28.1 | 15.9 | % | |||||||||||||
N.M. — Variance is not meaningful.
42
Table of Contents
Highlights — Fiscal 2007 versus Fiscal 2006
| • | The full-year benefit of the PG Energy Acquisition completed in August 2006
increased fiscal 2007 net income from our Gas Utility. |
||
| • | AmeriGas Propane operating income benefited from a $46.1 million gain on the sale
of its Arizona LPG storage facility adding $12.5 to UGI net income. |
||
| • | Our European International Propane operations experienced record-setting warm
temperatures which reduced volumes and margin and increased competitive pressures in
the markets they serve. |
||
| • | Greater average unit margins and sales volumes from AmeriGas Propane and Energy
Services increased domestic operations’ results in fiscal 2007. |
||
| • | New POLR rates effective January 2007 increased earnings from our Electric
Utility. |
||
| • | Our effective income tax rate in fiscal 2007 was higher than in fiscal 2006 as
the fiscal 2006 effective tax rate reflected management’s lower estimate of taxes to
be paid associated with planned repatriation of foreign earnings. |
||
| • | Absence of losses recorded in fiscal 2006 associated with debt extinguishments
were offset by the absence of the gain recorded in fiscal 2006 from the sale of our
investment in Hunlock Creek Energy Ventures. |
| AmeriGas Propane | 2007 | 2006 | Increase | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 2,277.4 | $ | 2,119.3 | $ | 158.1 | 7.5 | % | ||||||||
Total margin (a) |
$ | 840.2 | $ | 775.5 | $ | 64.7 | 8.3 | % | ||||||||
Partnership EBITDA (b) |
$ | 338.7 | $ | 237.9 | $ | 100.8 | 42.4 | % | ||||||||
Operating income |
$ | 265.8 | $ | 184.1 | $ | 81.7 | 44.4 | % | ||||||||
Retail gallons sold (millions) |
1,006.7 | 975.2 | 31.5 | 3.2 | % | |||||||||||
Degree days — % warmer
than normal (c) |
6.5 | % | 10.2 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Partnership EBITDA (earnings before interest expense, income taxes
and depreciation and amortization) should not be considered as an
alternative to net income (as an indicator of operating
performance) or as an alternative to cash flow (as a measure of
liquidity or ability to service debt obligations) and is not a
measure of performance or financial condition under accounting
principles generally accepted in the United States of America.
Management uses Partnership EBITDA as the primary measure of
segment profitability for the AmeriGas Propane reportable segment
(see Note 16 to Consolidated Financial Statements). |
|
| (c) | Deviation from average heating degree days for the 30-year period
1971-2000 based upon national weather statistics provided by the
National Oceanic and Atmospheric Administration (“NOAA”) for 335
airports in the United States, excluding Alaska. |
Temperatures in the Partnership’s service territories based upon heating
degree days during fiscal 2007 were 6.5% warmer than normal compared with temperatures that
were 10.2% warmer than normal during fiscal 2006. Retail propane volumes sold increased
approximately 3.2% reflecting greater demand attributable to the colder weather and the
effects of higher sales in our AmeriGas Cylinder Exchange program.
Retail propane revenues increased $142.5 million reflecting a $83.8 million increase
due to higher average selling prices and $58.7 million due to the higher volumes sold.
Wholesale propane revenues decreased slightly reflecting a $2.6 million decrease due to
lower volumes sold largely offset by a $2.5 million increase due to higher average selling
prices. In fiscal 2007, our average retail propane product cost per retail gallon sold was
approximately 4% higher than in fiscal 2006 resulting in higher year-over-year prices to
our customers. Total cost of sales increased to $1,437.2 million in fiscal 2007 from
$1,343.8 million in fiscal 2006 primarily reflecting the increase in propane product costs
and the increased volumes sold. Total margin increased $64.7 million principally due to
the higher volumes, higher average retail propane margins per gallon and increased fee
income in response to increases in operating and administrative expenses.
43
Table of Contents
Partnership EBITDA during fiscal 2007 increased $100.8 million as a result of the
previously mentioned increase in total margin, a $46.1 million gain from the sale of the
Partnership’s storage facility in Arizona, and the absence of a $17.1 million loss on early
extinguishments of debt recorded in fiscal 2006 partially offset by a $27.2 million
increase in operating and administrative expenses. The $17.1 million loss on early
extinguishments of debt incurred during fiscal 2006 was associated with the refinancings of
AmeriGas Propane, L.P.’s (“AmeriGas OLP’s”) Series A and Series C First Mortgage Notes
totaling $228.8 million, and AmeriGas Partners’ 10% Senior Notes totaling $59.6 million,
with $350 million of 7.125% AmeriGas Partners’ Senior Notes due 2016. The Partnership also
used a portion of the proceeds from the issuance of the 7.125% Senior Notes to repay
AmeriGas OLP’s $35 million term loan. The increase in fiscal 2007 operating and
administrative expenses principally resulted from higher (1) employee compensation and
benefits, (2) vehicle costs and (3) maintenance and repair expenses. Both fiscal 2007 and
2006 benefited from favorable expense reductions related to general insurance primarily
reflecting improved claims experience.
Operating income increased $81.7 million mainly reflecting the previously mentioned
$64.7 million increase in Partnership margin and the $46.1 million gain from the sale of
the Partnership’s storage facility in Arizona partially offset by the increase in operating
and administrative expenses and depreciation expense.
| International Propane | 2007 | 2006 | Decrease | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 800.4 | $ | 945.5 | $ | (145.1 | ) | (15.3 | )% | |||||||
Total margin (a) |
$ | 411.8 | $ | 428.3 | $ | (16.5 | ) | (3.9 | )% | |||||||
Operating income |
$ | 94.5 | $ | 119.3 | $ | (24.8 | ) | (20.8 | )% | |||||||
Income before income taxes |
$ | 64.1 | $ | 93.9 | $ | (29.8 | ) | (31.7 | )% | |||||||
(Millions of euros) |
||||||||||||||||
Revenues |
€ | 602.4 | € | 776.5 | € | (174.1 | ) | (22.4 | )% | |||||||
Total margin (a) |
€ | 309.8 | € | 350.5 | € | (40.7 | ) | (11.6 | )% | |||||||
Operating income |
€ | 73.3 | € | 99.9 | € | (26.6 | ) | (26.6 | )% | |||||||
Income before income taxes |
€ | 51.4 | € | 79.8 | € | (28.4 | ) | (35.6 | )% | |||||||
Antargaz retail gallons
sold (millions) |
269.1 | 315.2 | (46.1 | ) | (14.6 | )% | ||||||||||
Degree days — % warmer
than normal — Antargaz (b) |
21.1 | % | 3.6 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Deviation from average heating degree days for the 30-year period 1971-2000 at 34 locations in our French
service territory. |
Based upon heating degree day data, temperatures in Antargaz’ service
territory were approximately 21% warmer than normal in fiscal 2007 compared to temperatures
that were approximately 3.6% warmer than normal in fiscal 2006. Flaga experienced similar
record-setting warm weather across its service territories during fiscal 2007. Antargaz’
retail LPG volumes sold decreased to 269.1 million gallons in fiscal 2007 from 315.2 million
gallons in fiscal 2006. The decrease in Antargaz retail volumes sold occurred across all of
Antargaz’ customer classes and was in large part the result of significantly warmer weather
and, to a lesser extent, customer conservation and increased competitive pressures from
other LPG marketers and alternate fuels. Flaga’s volumes declined largely reflecting the
absence of volumes from its previously consolidated Czech Republic and Slovakia businesses
which were contributed to ZLH in February 2006. Flaga’s 50% ownership interest in ZLH has
been accounted for under the equity method since its formation in February 2006.
International base-currency results are translated into U.S. dollars based upon exchange
rates experienced during the reporting periods. During fiscal 2007, the monthly average
currency translation rate was $1.34 per euro compared to a rate of $1.23 per euro during
fiscal 2006.
International Propane euro-based revenues decreased €174.1 million during fiscal 2007
primarily reflecting (1) a decline of approximately €90.8 million principally due to
Antargaz’ lower retail volumes sold at slightly lower average prices, (2) approximately
€46.7 million in lower revenues from Antargaz’ low-margin wholesale sales, (3) the absence
of revenues from Flaga’s Czech Republic and Slovakia businesses subsequent to the formation
of ZLH in February 2006 and lower revenues from Flaga’s wholly owned Austrian business, and
(4) lower ancillary sales and services. International Propane’s total cost of sales
decreased to €388.6 million in fiscal 2007 from €517.2 million in fiscal 2006 largely
reflecting the effects of the lower retail volumes sold, LPG product costs that were lower
than in fiscal 2006 and the decline in low-margin wholesale sales. Although LPG product
costs were lower in fiscal 2007 than in fiscal 2006, they were volatile and remained at
historically high levels.
44
Table of Contents
Total margin decreased €40.7 million or 11.6% in fiscal 2007 largely reflecting (1) the
lower retail volumes sold partially offset by higher average margins per retail gallon and
(2) lower margin from ancillary sales and services. In U.S. dollars, total margin declined a
less dramatic 3.9% reflecting the effects of the stronger euro versus the U.S. dollar during
fiscal 2007.
International Propane operating income declined €26.6 million in fiscal 2007
principally reflecting the lower total margin partially offset by a €10.7 million decrease
in operating and administrative expenses. The decrease in operating and administrative
expenses is largely the result of decreases in Antargaz’ employee compensation and benefits
expenses and vehicle costs and decreases in Flaga’s expenses due in large part to the
absence of expenses from the businesses contributed to ZLH in February 2006 and thus
subsequently reflected on the equity method.
The decrease in International Propane income before income taxes principally reflects
the previously described decrease in operating income as slightly lower base-currency
interest expense and the absence of a loss on extinguishment of debt recorded in fiscal 2006
were largely offset by changes in minority interest. The decrease in interest expense is
attributable to interest savings as a result of our refinancings which are discussed further
in Financial Condition and Liquidity. The changes in minority interest reflect the minority
interest holder’s share of costs associated with the shut-down of one of Antargaz’
majority-owned filling centers in fiscal 2006.
| Gas Utility | 2007 | 2006 | Increase | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 1,044.9 | $ | 724.0 | $ | 320.9 | 44.3 | % | ||||||||
Total margin (a) |
$ | 303.4 | $ | 201.1 | $ | 102.3 | 50.9 | % | ||||||||
Operating income |
$ | 136.6 | $ | 84.2 | $ | 52.4 | 62.2 | % | ||||||||
Income before income taxes |
$ | 96.7 | $ | 62.4 | $ | 34.3 | 55.0 | % | ||||||||
System throughput —
billions of cubic feet (“bcf”) |
131.8 | 82.6 | 49.2 | 59.6 | % | |||||||||||
Degree days — % warmer
than normal (b) |
4.7 | % | 8.7 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Deviation from average heating degree days for the 30-year period
1975-2004 based upon weather statistics provided by NOAA for
airports located within Gas Utility’s service territory. |
Temperatures in Gas Utility’s service territory based upon heating degree days were 4.7%
warmer than normal in fiscal 2007 compared with temperatures that were 8.7% warmer than
normal in fiscal 2006. Total distribution system throughput increased 49.2 bcf reflecting a
43.4 bcf increase from the full-year results of PNG Gas and greater UGI Gas distribution
system throughput. The greater UGI Gas distribution system throughput primarily reflects (1)
greater interruptible delivery service throughput and (2) increased sales to firm-
residential, commercial and industrial (“retail core-market”) customers as a result of the
colder fiscal 2007 weather and year-over-year growth in the number of UGI Gas customers.
Gas Utility revenues increased $320.9 million during fiscal 2007 principally reflecting
$308.9 million of incremental revenues attributable to the full year results of PNG Gas and a
$37.5 million increase in UGI Gas revenues from greater low-margin off-system sales. These
increases were partially offset by a $30.7 million decrease in revenues from UGI Gas’ retail
core-market customers as a result of lower average PGC rates. Increases or decreases in
retail core-market customer revenues and cost of sales principally result from changes in
retail core-market volumes and the level of gas costs collected through the PGC recovery
mechanism. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated
with sales to retail core-market customers at amounts included in PGC rates. The difference
between actual gas costs and the amount included in rates is deferred on the balance sheet as
a regulatory asset or liability and represents amounts to be collected from or refunded to
customers in a future period. As a result of this PGC recovery mechanism, increases or
decreases in the cost of gas associated with retail core-market customers have no direct
effect on retail core-market margin. Gas Utility’s cost of gas was $741.5 million in fiscal
2007 compared to $522.9 million in fiscal 2006 largely reflecting the effects of the
full-year results of PNG Gas and greater cost of gas associated with the higher UGI Gas
off-system sales partially offset by the effects of the previously mentioned lower average
UGI Gas PGC rates.
45
Table of Contents
Gas Utility total margin in fiscal 2007 increased $102.3 million primarily reflecting
$93.0 million of incremental margin from the full-year results of PNG Gas and a $9.3 million
increase in UGI Gas’ total margin. The increase in UGI Gas’ total margin in fiscal 2007
principally reflects greater margin from retail core-market customers on higher volumes and
higher average interruptible delivery service unit margins reflecting higher natural gas
versus oil price spreads.
Gas Utility operating income increased to $136.6 million in fiscal 2007 from $84.2
million in fiscal 2006 principally reflecting the previously mentioned increase in total
margin and slightly higher other income partially offset by a $39.5 million increase in
operating and administrative expenses and $14.1 million higher depreciation and amortization
expense. The increase in total operating and administrative expenses and depreciation and
amortization expense principally reflects the full-year results of PNG Gas.
The increase in Gas Utility income before income taxes reflects the higher operating
income partially offset by an increase of $18.1 million in interest expense. The increase in
interest expense is principally due to higher long- and short-term debt outstanding,
primarily as a result of the PG Energy Acquisition, and higher short-term interest rates.
| Electric Utility | 2007 | 2006 | Increase | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 121.9 | $ | 98.0 | $ | 23.9 | 24.4 | % | ||||||||
Total margin (a) |
$ | 47.3 | $ | 41.7 | $ | 5.6 | 13.4 | % | ||||||||
Operating income |
$ | 26.0 | $ | 20.7 | $ | 5.3 | 25.6 | % | ||||||||
Income before income taxes |
$ | 23.6 | $ | 18.2 | $ | 5.4 | 29.7 | % | ||||||||
Distribution sales — millions
of kilowatt hours (“gwh”) |
1,010.6 | 1,005.0 | 5.6 | 0.6 | % | |||||||||||
| (a) | Total margin represents total revenues less total cost of sales
and revenue-related taxes, i.e. gross receipts taxes of $6.8
million and $5.3 million in fiscal 2007 and fiscal 2006,
respectively. For financial statement purposes, revenue-related
taxes are included in “Utility taxes other than income taxes” on
the Consolidated Statements of Income. |
Electric Utility’s fiscal 2007 kilowatt-hour sales were approximately equal to
those of fiscal 2006. Electric Utility revenues increased $23.9 million in fiscal 2007
largely reflecting the effects of higher POLR rates. In accordance with the terms of our
June 2006 POLR Settlement, Electric Utility increased its POLR rates effective January 1,
2007. This increase raised the average cost to residential customers by approximately 35%
over costs in effect during calendar year 2006. Electric Utility’s cost of sales increased
to $67.8 million in fiscal 2007 from $51.0 million in fiscal 2006 principally reflecting
higher per unit purchased power costs.
Electric Utility total margin increased $5.6 million during fiscal 2007 principally
reflecting the effects of the higher POLR rates partially offset by the higher per-unit
purchased power costs.
The increase in fiscal 2007 Electric Utility operating income and income before income taxes
principally reflects the increase in total margin partially offset by slightly higher
operating and administrative expenses.
| Increase | ||||||||||||||||
| Energy Services | 2007 | 2006 | (Decrease) | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 1,336.1 | $ | 1,414.3 | $ | (78.2 | ) | (5.5 | )% | |||||||
Total margin (a) |
$ | 100.9 | $ | 86.1 | $ | 14.8 | 17.2 | % | ||||||||
Operating income |
$ | 57.4 | $ | 53.1 | $ | 4.3 | 8.1 | % | ||||||||
Income before income taxes |
$ | 57.4 | $ | 53.1 | $ | 4.3 | 8.1 | % | ||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Notwithstanding the effects of a 4% increase in natural gas volumes sold and
higher electric generation kilowatt-hour sales, Energy Services revenues decreased to
$1,336.1 million in fiscal 2007 from $1,414.3 million in fiscal 2006 principally reflecting
the revenue effects of lower natural gas prices.
Total margin increased to $100.9 million in fiscal 2007 from $86.1 million in fiscal
2006. The increase in total margin is primarily attributable to higher natural gas unit
margins, the previously mentioned increase in natural gas volumes sold, and improved
results from storage management and peaking supply services.
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Table of Contents
The increase in Energy Services operating income and income before income taxes
principally reflects the increase in total margin largely offset by the absence of a $9.1
million pre-tax gain on the sale of Energy Ventures recorded in fiscal 2006 and increased
operating and administrative expenses due in part to the full-year consolidation of the
Hunlock Creek Electric Generation station acquired as a result of the sale of Energy
Ventures in March 2006 and greater compensation and benefits costs.
Interest Expense and Income Taxes. Consolidated interest expense increased to $139.6 million
in fiscal 2007 from $123.6 million in fiscal 2006 principally due to higher interest expense
associated with the PG Energy Acquisition debt partially offset by the full-year benefits of
AmeriGas Partners debt refinancing in fiscal 2006. Our effective income tax rate in fiscal
2007 was higher than in fiscal 2006 as the fiscal 2006 effective tax rate reflected
management’s lower estimate of taxes to be paid associated with planned repatriation of
foreign earnings.
Fiscal 2006 Compared with Fiscal 2005
Consolidated Results
Consolidated Results
| Variance - Favorable | ||||||||||||||||||||||||
| 2006 | 2005 | (Unfavorable) | ||||||||||||||||||||||
| % of Total | % of Total | |||||||||||||||||||||||
| Net | Net | Net | Net | Net | % | |||||||||||||||||||
| (Millions of dollars) | Income | Income | Income | Income | Income | Change | ||||||||||||||||||
AmeriGas Propane |
$ | 25.1 | 14.2 | % | $ | 17.6 | 9.4 | % | $ | 7.5 | 42.6 | % | ||||||||||||
International Propane |
67.1 | 38.1 | % | 99.4 | 53.0 | % | (32.3 | ) | (32.5 | )% | ||||||||||||||
Gas Utility |
38.1 | 21.6 | % | 39.3 | 21.0 | % | (1.2 | ) | (3.1 | )% | ||||||||||||||
Electric Utility |
10.5 | 6.0 | % | 11.5 | 6.1 | % | (1.0 | ) | (8.7 | )% | ||||||||||||||
Energy Services |
31.3 | 17.8 | % | 21.7 | 11.6 | % | 9.6 | 44.2 | % | |||||||||||||||
Corporate & Other |
4.1 | 2.3 | % | (2.0 | ) | (1.1 | )% | 6.1 | N.M. | |||||||||||||||
| $ | 176.2 | 100.0 | % | $ | 187.5 | 100.0 | % | $ | (11.3 | ) | (6.0 | )% | ||||||||||||
N.M. — Variance is not meaningful.
Highlights — Fiscal 2006 versus Fiscal 2005
| • | A decline in International Propane results as Antargaz experienced more normal
unit margins in fiscal 2006 from unusually high unit margins in fiscal 2005. Fiscal
2005 Antargaz results also benefited from the reversal of certain non-income tax
reserves. |
||
| • | Results in fiscal 2006 reflect warmer heating-season weather in our AmeriGas
Propane and Gas Utility service territories and the effects of price-induced
customer conservation. |
||
| • | Energy Services’ fiscal 2006 results benefited from greater unit margins, greater
services income and a gain from the sale of its joint-venture interest in Hunlock Creek Energy Ventures. |
||
| • | UGI Utilities completed the acquisition of PG Energy on August 24, 2006 and
International Propane expanded its presence in central and eastern Europe through
its 50% interest in Zentraleuropa LPG Holding GmbH (“ZLH”). |
||
| • | The Company recorded lower losses in fiscal 2006 from early extinguishments of
debt. |
||
| • | Our effective income tax rate in fiscal 2006 was lower than in fiscal 2005 as the
fiscal 2006 effective tax rate reflected management’s lower estimate of taxes to be
paid associated with planned repatriation of foreign earnings. |
47
Table of Contents
| Increase | ||||||||||||||||
| AmeriGas Propane | 2006 | 2005 | (Decrease) | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 2,119.3 | $ | 1,963.3 | $ | 156.0 | 7.9 | % | ||||||||
Total margin (a) |
$ | 775.5 | $ | 743.3 | $ | 32.2 | 4.3 | % | ||||||||
Partnership EBITDA (b) |
$ | 237.9 | $ | 215.9 | $ | 22.0 | 10.2 | % | ||||||||
Operating income |
$ | 184.1 | $ | 168.1 | $ | 16.0 | 9.5 | % | ||||||||
Retail gallons sold (millions) |
975.2 | 1,034.9 | (59.7 | ) | (5.8 | )% | ||||||||||
Degree days — % warmer
than normal (c) |
10.2 | % | 6.9 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Partnership EBITDA (earnings before interest expense, income taxes
and depreciation and amortization) should not be considered as an
alternative to net income (as an indicator of operating
performance) or as an alternative to cash flow (as a measure of
liquidity or ability to service debt obligations) and is not a
measure of performance or financial condition under accounting
principles generally accepted in the United States of America.
Management uses Partnership EBITDA as the primary measure of
segment profitability for the AmeriGas Propane reportable segment
(see Note 16 to Consolidated Financial Statements). |
|
| (c) | Deviation from average heating degree days for the 30-year period
1971-2000 based upon national weather statistics provided by NOAA for 335
airports in the United States, excluding Alaska. |
Temperatures in AmeriGas Propane’s service territories based upon heating
degree days during fiscal 2006 were 10.2% warmer than normal compared with temperatures that
were 6.9% warmer than normal during fiscal 2005.
Retail propane volumes sold decreased approximately 5.8% principally due to the warmer
winter weather and the negative effects of customer conservation driven by continued high
propane selling prices.
Retail propane revenues increased $136.8 million reflecting a $233.8 million increase
due to higher average selling prices partially offset by a $97.0 million decrease due to the
lower retail volumes sold. Wholesale propane revenues decreased $2.8 million reflecting a
$27.4 million decrease due to lower volumes sold largely offset by a $24.6 million increase
due to higher average selling prices. In fiscal 2006, our average retail propane product
cost per retail gallon sold was approximately 18% higher than in fiscal 2005 resulting in
higher year-over-year prices to our customers. The average wholesale cost per gallon of
propane during fiscal 2006 at Mont Belvieu, one of the major supply points in the United
States, was approximately 21% greater than the average cost per gallon during fiscal 2005.
Total cost of sales increased to $1,343.8 million in fiscal 2006 from $1,220.0 million in
fiscal 2005 primarily reflecting the increase in propane product costs partially offset by
the decreased volumes sold. Total margin increased $32.2 million principally due to higher
average propane margins per gallon and higher fees in response to increases in operating and
administrative expenses.
Partnership EBITDA during fiscal 2006 increased $22.0 million compared to fiscal 2005
as a result of the previously mentioned increase in total margin and a $16.5 million
decrease in losses from early extinguishments of debt ($17.1 million of such losses in
fiscal 2006 compared to $33.6 million in fiscal 2005). These favorable year-over-year
changes were partially offset by a $17.1 million increase in operating and administrative
expenses and a $9.5 million decrease in other income. Other income in fiscal 2005 benefited
from a $9.1 million pre-tax gain on the sale of AmeriGas Propane’s 50% ownership interest in
Atlantic Energy, Inc. to Energy Services. The increase in operating and administrative
expenses in fiscal 2006 principally resulted from higher (1) vehicle fuel and lease costs,
(2) employee compensation and benefits costs and (3) maintenance and repairs expenses. These
operating expense increases were partially offset by a $7.2 million favorable net expense
reduction related to general insurance and litigation claims, primarily reflecting improved
claims history. During fiscal 2006, the Partnership recovered significant increases in
certain costs, such as vehicle fuel, through delivery surcharges.
Operating income increased $16.0 million reflecting the previously mentioned increase
in total margin and a $1.2 million decrease in depreciation expense largely offset by the
aforementioned $17.1 million increase in operating and administrative expenses and decrease
in other income.
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Table of Contents
| Increase | ||||||||||||||||
| International Propane | 2006 | 2005 | (Decrease) | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 945.5 | $ | 943.9 | $ | 1.6 | 0.2 | % | ||||||||
Total margin (a) |
$ | 428.3 | $ | 499.8 | $ | (71.5 | ) | (14.3 | )% | |||||||
Operating income |
$ | 119.3 | $ | 193.8 | $ | (74.5 | ) | (38.4 | )% | |||||||
Income before income taxes |
$ | 93.9 | $ | 159.0 | $ | (65.1 | ) | (40.9 | )% | |||||||
(Millions of euros) |
||||||||||||||||
Revenues |
€ | 776.5 | € | 731.9 | € | 44.6 | 6.1 | % | ||||||||
Total margin (a) |
€ | 350.5 | € | 387.8 | € | (37.3 | ) | (9.6 | )% | |||||||
Operating income |
€ | 99.9 | € | 148.2 | € | (48.3 | ) | (32.6 | )% | |||||||
Income before income taxes |
€ | 79.8 | € | 121.5 | € | (41.7 | ) | (34.3 | )% | |||||||
Antargaz retail gallons
sold (millions) |
315.2 | 338.4 | (23.2 | ) | (6.9 | )% | ||||||||||
Degree days — % warmer
than normal — Antargaz (b) |
3.6 | % | 3.9 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Deviation from average heating degree days for the 30-year period
1971-2000 at 34 locations in our French service territory. |
Temperatures in International Propane’s service territories based upon heating degree
days during fiscal 2006 were generally comparable to the prior year. The monthly average
currency translation rate was $1.23 per euro during fiscal 2006 compared to $1.27 per euro
during fiscal 2005. Antargaz’ retail LPG volumes sold decreased to 315.2
million gallons in fiscal 2006 from 338.4 million gallons in fiscal 2005 due in large part
to the late onset of winter weather in December, lower agricultural volumes sold and the
effects of customer conservation on volumes sold.
International Propane revenues increased slightly as approximately $12 million of
increased revenues from Antargaz were largely offset by a decline in Flaga’s revenues. The
increase in Antargaz’ revenues reflects higher retail LPG selling prices largely offset by
the effects of the stronger dollar versus the euro. The decrease in Flaga’s revenues largely
reflects the effects of Flaga’s Czech Republic and Slovakia businesses being contributed to
ZLH in February of 2006 and subsequently being reflected on the equity method.
International Propane’s total cost of sales increased to $517.2 million in fiscal 2006 from
$444.1 million in fiscal 2005 reflecting higher LPG product costs on lower retail volumes
sold partially offset by the beneficial effects of the stronger dollar compared to the euro.
Total International Propane margin declined $71.5 million in fiscal 2006 compared to
fiscal 2005 primarily (1) reflecting both the decline in Antargaz’ volumes and its unusually
high LPG unit margins in fiscal 2005 and (2) due to the stronger dollar versus the euro.
Antargaz’ total base currency margin declined €33.0 million reflecting the lower volumes
sold and lower unit margins.
The decrease in International Propane operating income principally reflects the decline
in total margin, the absence of $18.8 million of income from the reversal of certain of
Antargaz’ non-income tax related reserves recorded in fiscal 2005 (see discussion in
“Antargaz Tax Matters”) partially offset by a decrease of $19.0 million in operating and
administrative expenses. The decrease in operating and administrative expenses reflects the
beneficial effects of the stronger dollar and lower euro-based operating and administrative
expenses at Antargaz and Flaga. The decline in Flaga’s operating and administrative expenses
largely reflects the absence of operating expenses subsequent to the contribution of certain
of its businesses to ZLH in February 2006.
The decrease in International Propane income before income taxes reflects the decrease
in operating income and a $1.4 million loss on early extinguishment of debt, partially
offset by approximately $6.7 million of lower interest expense and changes in minority
interest. The decrease in interest expense is attributable to interest savings resulting
from Antargaz’ debt refinancings which are discussed further in Financial Condition and
Liquidity. The changes in minority interest reflect the minority interest holder’s share of
costs associated with the shut-down of one of Antargaz’ majority owned filling centers.
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Table of Contents
| Increase | ||||||||||||||||
| Gas Utility | 2006 | 2005 | (Decrease) | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 724.0 | $ | 585.1 | $ | 138.9 | 23.7 | % | ||||||||
Total margin (a) |
$ | 201.1 | $ | 195.0 | $ | 6.1 | 3.1 | % | ||||||||
Operating income |
$ | 84.2 | $ | 81.6 | $ | 2.6 | 3.2 | % | ||||||||
Income before income taxes |
$ | 62.4 | $ | 65.0 | $ | (2.6 | ) | (4.0 | )% | |||||||
System throughput -
billions of cubic feet (“bcf”) |
82.6 | 84.7 | (2.1 | ) | (2.5 | )% | ||||||||||
Degree days — % warmer
than normal (b) |
8.7 | % | 2.0 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Deviation from average heating degree days for the 30-year period
1975-2004 based upon weather statistics provided by NOAA for
airports located within Gas Utility’s service territory. |
Temperatures in Gas Utility’s service territory based upon heating degree days
were 8.7% warmer than normal in fiscal 2006 compared with temperatures that were 2.0% warmer
than normal in fiscal 2005. Total distribution system throughput declined 2.1 bcf in fiscal
2006 despite 2.7 bcf of throughput contributed by PNG Gas’ operations during the period from
August 24, 2006 through September 30, 2006. Notwithstanding year-over-year growth in the
number of UGI Gas’ retail core-market customers, its fiscal 2006 system throughput was
approximately 6% lower than in fiscal 2005 primarily due to a reduction in retail
core-market customer usage largely resulting from warmer weather and customer conservation
in response to the pass-through of higher natural gas costs.
The increase in Gas Utility revenues during fiscal 2006 is principally the result of an
$86.6 million increase in UGI Gas’ retail core-market revenues reflecting higher average PGC
rates; $43.0 million of higher revenues from UGI Gas’ low-margin off-system sales; and, to a
much lesser extent, revenues from PNG Gas subsequent to the PG Energy Acquisition. Gas
Utility’s cost of gas was $522.9 million in fiscal 2006 compared to $390.1 million in fiscal
2005 largely
reflecting the effects of the higher PGC rates, the higher low-margin off-system sales and,
to a much lesser extent, cost of gas associated with PNG Gas’ operations subsequent to the
PG Energy Acquisition.
The $6.1 million increase in Gas Utility total margin in fiscal 2006 principally
reflects greater margin generated from higher average interruptible delivery service unit
margins and margin from PNG Gas partially offset by lower retail core-market margin. The
increase in average interruptible delivery service unit margins reflects an increase in the
spread between delivered prices for natural gas and alternative fuels, principally oil. The
lower gross margin from retail core-market customers largely reflects the previously
mentioned lower average usage per customer.
Gas Utility operating income increased $2.6 million in fiscal 2006 as the $6.1 million
increase in total margin was partially offset by a $2.6 million increase in depreciation and
amortization expense, including depreciation expense associated with PNG Gas, and slightly
higher operating and administrative expenses. Fiscal 2006 operating and administrative
expenses were slightly higher than in fiscal 2005 reflecting operating and administrative
expenses from PNG Gas and higher uncollectible accounts and customer assistance expense
partially offset by lower distribution system expenses resulting in large part from the mild
heating-season weather and lower stock-based compensation expense.
The decrease in Gas Utility income before income taxes in fiscal 2006 reflects the
increase in operating income which was more than offset by higher interest expense. The
higher interest expense resulted from higher average short-term debt outstanding, higher
short-term interest rates and interest on long-term debt associated with the PG Energy
Acquisition
| Increase | ||||||||||||||||
| Electric Utility | 2006 | 2005 | (Decrease) | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 98.0 | $ | 96.1 | $ | 1.9 | 2.0 | % | ||||||||
Total margin (a) |
$ | 41.7 | $ | 43.1 | $ | (1.4 | ) | (3.2 | )% | |||||||
Operating income |
$ | 20.7 | $ | 21.6 | $ | (0.9 | ) | (4.2 | )% | |||||||
Income before income taxes |
$ | 18.2 | $ | 19.9 | $ | (1.7 | ) | (8.5 | )% | |||||||
Distribution sales — millions
of kilowatt hours (“gwh”) |
1,005.0 | 1,021.8 | (16.8 | ) | (1.6 | )% | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales
and revenue-related taxes, i.e. gross receipts taxes of $5.3
million and $5.2 million in fiscal 2006 and fiscal 2005,
respectively. For financial statement purposes, revenue-related
taxes are included in “Utility taxes other than income taxes” on
the Consolidated Statements of Income. |
50
Table of Contents
Electric Utility’s fiscal 2006 kilowatt-hour sales decreased 1.6% principally
reflecting the effects of warmer heating-season weather. Electric Utility revenues increased
2.0% principally reflecting the effects of a 3.0% increase in its POLR electric generation
rates effective January 1, 2006 partially offset by the lower kilowatt-hour sales. Electric
Utility’s cost of sales increased to $51.0 million in fiscal 2006 from $47.8 million in
fiscal 2005 as a result of higher per-unit purchased power costs partially offset by the
lower kilowatt-hour sales. Electric Utility total margin in fiscal 2006 decreased $1.4
million principally as a result of the lower kilowatt-hour sales and the increase in
per-unit purchased power costs.
Electric Utility operating income decreased $0.9 million reflecting the decrease in
total margin and slightly higher depreciation and amortization expense slightly offset by
lower operating and administrative expenses. The decrease in Electric Utility income before
income taxes in fiscal 2006 reflects the decrease in operating income and higher interest
expense resulting from higher average short-term debt outstanding and higher short-term
interest rates.
| Energy Services | 2006 | 2005 | Increase | |||||||||||||
(Millions of dollars) |
||||||||||||||||
Revenues |
$ | 1,414.3 | $ | 1,355.0 | $ | 59.3 | 4.4 | % | ||||||||
Total margin (a) |
$ | 86.1 | $ | 73.6 | $ | 12.5 | 17.0 | % | ||||||||
Operating income |
$ | 53.1 | $ | 37.5 | $ | 15.6 | 41.6 | % | ||||||||
Income before income taxes |
$ | 53.1 | $ | 37.5 | $ | 15.6 | 41.6 | % | ||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Energy Services revenues increased to $1,414.3 million in fiscal 2006 from
$1,355.0 million in fiscal 2005 despite an approximate 22% decline in natural gas volumes
sold. Approximately $20 million of the total increase in revenues reflects a 5.5% increase
in propane volumes sold combined with higher propane selling prices resulting from higher
propane product costs. The decline in natural gas volumes sold largely reflects the effects
of customer losses associated with, among other things, maintenance of our credit risk
management policy in a high natural gas cost environment. The increase in propane volumes
sold reflects, in part, the full-year ownership of its 20 million gallon propane storage
terminal located in Chesapeake, Virginia. The propane terminal was purchased through two
separate transactions with ConocoPhillips Company and AmeriGas Propane in November 2004.
Energy Services total margin increased $12.5 million resulting from higher natural gas
margins, including winter storage and peaking services, and, to a lesser extent, higher
margin from its propane storage terminal.
The increase in Energy Services operating income and income before income taxes
principally reflects the previously mentioned increase in total margin and a $9.1 million
gain on the March 2006 sale of its 50% ownership interest in Energy Ventures partially
offset by higher operating and administrative expenses. The increased operating and
administrative expenses were largely associated with electric generation. As part of the
consideration for the sale of our 50% ownership interest, Energy Ventures transferred its
48-megawatt coal-fired electric generation station to UGID. As a result, UGID is no longer
incurring cost of sales associated with purchasing a portion of its power needs from Energy
Ventures, but is incurring operating and administrative expenses associated with the
operation of the electric generation station.
Interest Expense and Income Taxes. Interest expense decreased to $123.6 million in fiscal
2006 from $130.2 million in fiscal 2005 principally due to $12.4 million lower interest
expense largely associated with International Propane and AmeriGas Propane debt refinancings
partially offset by higher interest expense associated with greater short-term borrowings at
UGI Utilities. Our effective income tax rate in fiscal 2006 was lower than in fiscal 2005 as
the fiscal 2006 effective tax rate reflected management’s lower estimate of taxes to be paid
associated with planned repatriation of foreign earnings.
Financial Condition and Liquidity
Capitalization and Liquidity
Total cash, cash equivalents and short-term investments were $264.6 million at
September 30, 2007 compared with $201.0 million (including $0.6 million of short-term
investments included in other current assets) at September 30, 2006. Excluding cash, cash
equivalents and short-term investments that reside at UGI’s operating subsidiaries, at
September 30, 2007 and 2006, we had $47.4 million and $16.6 million, respectively, of cash,
cash equivalents and short-term investments. The primary sources of UGI’s cash are the dividends and other cash
payments made to UGI or its corporate subsidiaries by its principal business units.
51
Table of Contents
AmeriGas Propane’s ability to pay dividends to UGI is dependent upon distributions it
receives from AmeriGas Partners. At September 30, 2007, our 44% effective ownership interest
in the Partnership consisted of approximately 24.7 million Common Units and its combined 2%
general partner interests. Approximately 45 days after the end of each fiscal quarter, the
Partnership distributes all of its Available Cash (as defined in the Third Amended and
Restated Agreement of Limited Partnership of AmeriGas Partners, as amended, the “Partnership
Agreement”) relating to such fiscal quarter. The ability of the Partnership to pay
distributions depends upon a number of factors. These factors include (1) the level of
Partnership earnings; (2) the cash needs of the Partnership’s operations (including cash
needed for maintaining and increasing operating capacity); (3) changes in operating working
capital; and (4) the ability of the Partnership to borrow under its Credit Agreement, to
refinance maturing debt and to increase its long-term debt. Some of these factors are
affected by conditions beyond our control including weather, competition in markets we
serve, the cost of propane and changes in capital market conditions.
During fiscal 2007, 2006 and 2005, our principal business units paid dividends and made
cash payments to UGI and its subsidiaries as follows:
| Year Ended September 30, | 2007 | 2006 | 2005 | |||||||||
(Millions of dollars) |
||||||||||||
AmeriGas Propane |
$ | 53.8 | $ | 38.3 | $ | 45.4 | ||||||
UGI Utilities |
40.0 | 37.6 | 38.5 | |||||||||
International Propane |
68.4 | 104.6 | 22.5 | |||||||||
Energy Services |
6.1 | 34.8 | 9.0 | |||||||||
Total |
$ | 168.3 | $ | 215.3 | $ | 115.4 | ||||||
Dividends and other cash distributions are available to pay dividends on UGI
Common Stock and for investment purposes. The higher dividend from AmeriGas Propane in
fiscal 2007 reflects the benefit of a one-time $0.25 per limited partner unit increase in
the Partnership’s August 2007 quarterly distribution and the associated increased General
Partner distribution resulting from the July 2007 sale of the Partnership’s 3.5 million
barrel LPG storage facility (See Note 2 to Consolidated Financial Statements). The higher
dividend and cash payments from International Propane in fiscal 2006 largely reflect the
effects of Antargaz’ significantly higher earnings in fiscal 2005 and its December 2005
refinancing. Energy Services dividends in fiscal 2006 included, in part, dividends of
proceeds from the sale of Energy Ventures.
On April 24, 2007, UGI’s Board of Directors approved an increase in the quarterly
dividend rate on UGI Common Stock to $0.185 per share or $0.74 per share on an annual basis,
which was effective with the dividend payable on July 1, 2007 to shareholders of record on
June 15, 2007. On April 23, 2007, AmeriGas Propane’s Board of Directors approved an increase
in the quarterly distribution rate on AmeriGas Partners Common Units to $0.61 per Common
Unit ($2.44 annually) from $0.58 per Common Unit ($2.32 annually) previously. The increase
in AmeriGas Partners’ distribution was effective with the payment of its distribution for
the quarter ended June 30, 2007.
AmeriGas Partners. The Partnership’s debt outstanding at September 30, 2007 totaled $933.1
million. There were no amounts outstanding under AmeriGas OLP’s Credit Agreement at
September 30, 2007.
AmeriGas OLP’s Credit Agreement expires on October 15, 2011 and consists of (1) a $125
million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving
Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The
Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 million to
finance the purchase of propane businesses or propane business assets or, to the extent it
is not so used, for working capital and general purposes, subject to restrictions in the
AmeriGas Partners Senior Notes indentures. Issued and outstanding letters of credit under
the Revolving Credit Facility, which reduce the amount available for borrowings, totaled
$58.0 million at September 30, 2007 and $58.9 million at September 30, 2006. Approximately
the same amounts were outstanding under these letters of credit throughout each of the
respective fiscal years. AmeriGas OLP’s short-term borrowing needs are seasonal and are typically
greatest during the fall and winter heating-season months due to the need to fund higher
levels of working capital. The average daily and peak bank loan borrowings outstanding
under the Revolving Credit Facility in fiscal 2007 were $1.6 million and $92.0 million,
respectively. There were no significant borrowings outstanding under the Revolving Credit
Facility during fiscal 2006.
AmeriGas Partners periodically issues equity securities and may continue to do so.
Proceeds from the Partnership’s equity offerings have generally been used by the Partnership
to reduce indebtedness and for general Partnership purposes, including funding acquisitions.
AmeriGas Partners has an effective unallocated debt and equity
shelf registration statement with the U.S. Securities and Exchange Commission (“SEC”) under
which it may issue Common Units or Senior Notes due 2016 in underwritten public offerings.
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AmeriGas OLP must meet certain financial covenants in order to borrow under its Credit
Agreement including, but not limited to, a minimum interest coverage ratio, a maximum debt
to EBITDA ratio and a minimum EBITDA, as defined. AmeriGas OLP’s financial covenants
calculated as of September 30, 2007 permitted it to borrow up to the maximum amount
available under the Credit Agreement. For a more detailed discussion of the Partnership’s
credit facilities, see Note 3 to Consolidated Financial Statements. Based upon existing cash
balances, cash expected to be generated from operations and borrowings available under its
Credit Agreement, the Partnership’s management believes that the Partnership will be able to
meet its anticipated contractual commitments and projected cash needs during fiscal 2008.
International Propane. At September 30, 2007, Antargaz had total debt outstanding of €382.1
million ($544.9 million). There were no amounts borrowed under the revolving portion of the
Senior Facilities Agreement during fiscal 2007.
In December 2005, AGZ executed a five-year floating-rate Senior Facilities Agreement
that expires on March 31, 2011 and consists of (1) a €380 million variable-rate term loan
and (2) a €50 million revolving credit facility. AGZ executed interest rate swap agreements
to fix the underlying euribor or libor rate of interest on the term loan at approximately
3.25% for the duration of the loan. The effective interest rate on Antargaz’ term loan at
September 30, 2007 was 4.05%. The proceeds from the new term loan were used to repay its
€175 million term loan, to fund the redemption of its €165 million High Yield Bonds and for
general purposes.
The Senior Facilities term loan has been collateralized by substantially all of
Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivable.
Antargaz’ management believes that it will be able to meet its anticipated contractual
commitments and projected cash needs during fiscal 2008 principally with cash generated from
operations.
The Senior Facilities Agreement restricts the ability of AGZ to, among other things,
incur additional indebtedness and make investments. For a more detailed discussion of
Antargaz’ debt, see Note 3 to Consolidated Financial Statements.
At September 30, 2007, Flaga had total debt outstanding of €48.3 million ($68.9
million). On July 26, 2006, Flaga entered into a euro-based term loan facility in the amount
of €48 million and a working capital facility with a major European bank for up to €8
million both of which expire in September 2011. Borrowings under the working capital
facility commitment totaled €6.3 million ($8.9 million) at September 30, 2007. Generally,
principal payments on the term loan of €3 million are due semi-annually on March 31 and
September 30 each year with final payments totaling €24.0 million due in 2011. In November
2006, Flaga effectively fixed the euribor component of its interest rate on a substantial
portion of its term loan through September 2011 at 3.91% by entering into an interest rate
swap agreement. The effective interest rate on Flaga’s term loan at September 30, 2007 was
4.43%. Debt issued under these agreements is guaranteed by UGI. Flaga’s joint venture, ZLH,
has multi-currency working capital facilities that provide for borrowings up to a total of
€16 million, half of which is guaranteed by UGI. For a more detailed discussion of Flaga’s
debt, see Note 3 to Consolidated Financial Statements.
UGI Utilities. UGI Utilities’ debt outstanding totaled $702.0 million at September 30, 2007.
Included in this amount is $190.0 million of bank loans outstanding. In June 2007, UGI
Utilities refinanced $20 million of its maturing 7.17% Medium-Term Notes with proceeds from
the issuance of $20 million of 6.17% Medium-Term Notes due June 2017.
UGI Utilities has a revolving credit agreement under which it may borrow up to a total
of $350 million. This agreement expires in August 2011. At September 30, 2007, there was
$190.0 million outstanding under the revolving credit agreement. From time to time, UGI
Utilities has entered into short-term borrowings under uncommitted arrangements with major
banks in order to meet liquidity needs. Short-term borrowings, including amounts outstanding
under the revolving credit agreements, are classified as bank loans on the Consolidated
Balance Sheets. UGI Utilities’ credit agreement requires it to maintain a maximum ratio of
Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. During fiscal
2007 and 2006, average daily bank loan borrowings were $163.7 million and $118.4 million,
respectively, and peak bank loan borrowings totaled $259.0 million and $219.0 million,
respectively. Peak borrowings typically occur during the peak heating season months of
December and January when the Company’s investment in working capital is generally greatest.
The increase in average and peak bank loan borrowings during fiscal 2007 reflects, in large
part, borrowings to fund increased working capital primarily resulting from borrowings
related to the working capital of PNG Gas.
UGI Utilities has a shelf registration statement with the SEC under which it may issue
up to an additional $55 million of Medium-Term Notes or other debt securities subject to the
financial ratio covenant in its Revolving Credit Agreement.
Based upon cash expected to be generated from Gas Utility and Electric Utility
operations, borrowings available under its revolving credit agreement and the availability
of its Medium-Term Notes program, UGI Utilities’
management believes that it will be able to meet its anticipated contractual and projected
cash commitments during fiscal 2008. For a more detailed discussion of UGI Utilities’
long-term debt and revolving credit facility, see Note 3 to Consolidated Financial
Statements.
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Energy Services. UGI Energy Services, Inc. (“ESI”) has a $200 million receivables purchase
facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper
expiring in April 2009, although the Receivables Facility may terminate prior to such date
due to the termination of commitments of the Receivables Facility’s back-up purchasers.
Prior to September 2006, ESI’s Receivables Facility was $150 million.
Under the Receivables Facility, ESI transfers, on an ongoing basis and without
recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary,
Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement
purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time
sell, an undivided interest in the receivables to a commercial paper conduit of a major
bank. ESFC was created and has been structured to isolate its assets from creditors of ESI
and its affiliates, including UGI. This two-step transaction is accounted for as a sale of
receivables following the provisions of Statement of Financial Accounting Standards (“SFAS”)
No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities.” ESI continues to service, administer and collect trade receivables on behalf
of the commercial paper issuer and ESFC. At September 30, 2007, the outstanding balance of
ESFC trade receivables was $65.7 million which is net of $16.0 million that was sold to the
commercial paper conduit and removed from the balance sheet. During fiscal 2007 and 2006,
peak borrowings totaled $76.0 million and $145.0 million, respectively. Based upon cash
expected to be generated from operations and borrowings available under its Receivables
Facility, management believes that Energy Services will be able to meet its anticipated
contractual and projected cash commitments during fiscal 2008.
A major bank has committed to issue up to $50 million of standby letters of credit,
secured by cash or marketable securities (“LC Facility”). At September 30, 2007, there were
no letters of credit outstanding. Energy Services expects to fund the collateral
requirements with borrowings under its Receivables Facility. The LC Facility expires in
April 2008.
Cash Flows
Operating Activities. Due to the seasonal nature of the Company’s businesses, cash flows
from operating activities are generally strongest during the second and third fiscal
quarters when customers pay for natural gas, LPG, electricity and other energy products
consumed during the peak heating season months. Conversely, operating cash flows are
generally at their lowest levels during the first and fourth fiscal quarters when the
Company’s investment in working capital, principally inventories and accounts receivable,
is generally greatest. AmeriGas Propane and UGI Utilities primarily use bank loans to
satisfy their seasonal operating cash flow needs. Energy Services uses its Receivables
Facility to satisfy its operating cash flow needs. Antargaz has historically been successful
funding its operating cash flow needs without using its revolver. Changes in cash flow from
operations from year to year can also be affected by changes in operating working capital
especially during periods of volatile energy commodity prices.
Cash
flow provided by operating activities was $456.2 million in fiscal 2007, $279.4 million
in fiscal 2006 and $437.7 million in fiscal 2005. Cash flow from operating activities
before changes in operating working capital was $518.4 million
in fiscal 2007, $404.6
million in fiscal 2006 and $426.5 million in fiscal 2005. The increase in cash flow from
operating activities in fiscal 2007 largely reflects greater cash flow from UGI Utilities,
reflecting the full-year effects of PNG Gas and lower cash used for working capital
purposes, and greater cash flow from AmeriGas Propane principally reflecting the cash flow
effects of improved fiscal 2007 financial performance.
Investing Activities. Investing activity cash flow is principally affected by investments
in property, plant and equipment, cash paid for acquisitions of businesses, changes in
short-term investments and proceeds from sales of assets. Net cash flow used in investing
activities was $223.8 million in fiscal 2007, $707.5 million in fiscal 2006 and $196.3
million in fiscal 2005. The higher fiscal 2006 cash flow used by investing activities
reflects in large part the $580 million paid at settlement for the PG Energy Acquisition.
Cash flow for acquisitions in fiscal 2007, principally Partnership propane business
acquisitions, totaled $78.8 million. During fiscal 2007, the Partnership received
$49.0 million in cash proceeds from the sale of its Arizona storage facility and UGI Utilities
received $23.7 million in settlement of its working capital adjustment associated with the
PG Energy Acquisition. During fiscal 2007, 2006 and 2005, we spent $223.1 million, $191.7
million and $158.4 million, respectively, for property, plant and equipment. The higher
fiscal 2007 expenditures include higher Gas Utility capital expenditures associated with PNG
Gas and greater International Propane capital expenditures.
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Financing Activities. Cash flow (used) provided by financing activities was $(178.5)
million, $299.7 million and $(72.6) million in fiscal 2007, 2006 and 2005, respectively.
Changes in cash flow from financing activities are primarily
due to issuances and repayments of long-term debt, net bank loan borrowings, dividends and
distributions on UGI Common Stock and AmeriGas Partners Common Units and proceeds from
public offerings of AmeriGas Partners Common Units and UGI Common Stock.
Fiscal 2007 issuances of long-term debt include $20 million of UGI Utilities’ 6.17%
Medium-Term Notes the proceeds of which were used to repay UGI Utilities maturing 7.17%
Medium Term Notes. We also made scheduled repayments of €6 million of Flaga’s term loan
during fiscal 2007. Long-term debt issuances in fiscal 2006 were affected by a number of
significant financing transactions including the issuance of $275 million of UGI Utilities
Senior Notes associated with the PG Energy Acquisition; a €380 million term loan entered
into by Antargaz; and $350 million of Senior Notes issued by AmeriGas Partners. The
proceeds from the Antargaz €380 million term loan were used to repay the then-existing
€75 million Antargaz Senior Facilities term loan, redeem Antargaz €165 million High Yield
Bonds and for general corporate purposes. The proceeds of the AmeriGas Partners Senior
Notes were used to refinance AmeriGas OLP’s $160 million Series A and $68.8 million Series C
First Mortgage Notes, including a make-whole premium, its $35 million term loan due October
1, 2006, and $59.6 million of the Partnership’s 10% Senior Notes.
Pension Plans
UGI Utilities sponsors two defined benefit pension plans (“Pension Plans”) for employees of
UGI Utilities, UGIPNG, UGI, and certain of UGI’s other subsidiaries. The fair value of the
Pension Plans’ assets totaled $290.1 million and $274.6 million at September 30, 2007 and
2006, respectively. At September 30, 2007 and 2006, the Pension Plans’ projected benefit
obligations (“PBOs”) exceeded the Pension Plans assets by $9.3 million and $31.7 million,
respectively.
The Company believes it is in compliance with regulations governing defined benefit pension
plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and
regulations, and does not anticipate it will be required to make a contribution to the
Pension Plans in fiscal 2008. Pension expense associated with our Pension Plans in fiscal
2007, 2006 and 2005 was not material. Pension expense associated with our Pension Plans in
fiscal 2008 is not expected to be material.
SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans
— an amendment of FASB Statements No. 87, 88, 106 and 132(R),” (“SFAS 158”), became
effective for us as of September 30, 2007 and requires recognition of an asset or liability
in the statement of financial position reflecting the funded status of pension and other
postretirement benefit plans such as retiree health and life, with current year changes
recognized in shareholders’ equity. SFAS 158 did not change the existing criteria for
measurement of periodic benefit costs, plan assets or benefit obligations. In conjunction
with our adoption of SFAS 158, we adjusted certain amounts on our September 30, 2007
Consolidated Balance Sheet relating to the Pension Plans, unfunded supplemental executive
retirement plans, domestic other postretirement benefit plans and certain pension and other
postretirement benefit plans of Antargaz. As a result of the adoption of SFAS 158, we
recorded an after-tax charge to Common Stockholders’ Equity of $11.2 million. For a more
detailed discussion of the adoption of SFAS 158, see Note 1 to Consolidated Financial
Statements.
Capital Expenditures
In the following table, we present capital expenditures (which exclude acquisitions) by our
business segments for fiscal 2007, 2006 and 2005. We also provide amounts we expect to spend
in fiscal 2008. Increases in capital expenditures are in support of growth and new marketing
initiatives. We expect to finance fiscal 2008 capital expenditures principally from cash
generated by operations and borrowings under our credit facilities.
| Year Ended September 30, | 2008 | 2007 | 2006 | 2005 | ||||||||||||
(Millions of dollars) |
(estimate) | |||||||||||||||
AmeriGas Propane |
$ | 69.8 | $ | 73.8 | $ | 70.7 | $ | 62.6 | ||||||||
International Propane |
74.2 | 64.3 | 55.5 | 42.0 | ||||||||||||
Gas Utility |
60.6 | 66.2 | 49.2 | 38.8 | ||||||||||||
Electric Utility |
5.8 | 7.2 | 9.0 | 7.5 | ||||||||||||
Energy Services |
13.6 | 10.7 | 7.0 | 6.2 | ||||||||||||
Other |
2.6 | 0.9 | 0.3 | 1.3 | ||||||||||||
Total |
$ | 226.6 | $ | 223.1 | $ | 191.7 | $ | 158.4 | ||||||||
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Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond fiscal 2007. Such
obligations include scheduled repayments of long-term debt, interest on long-term fixed-rate
debt, operating lease payments, unconditional purchase obligations for pipeline capacity,
pipeline transportation and natural gas storage services and commitments to purchase natural
gas, LPG and electricity. The following table presents contractual cash obligations under
agreements existing as of September 30, 2007.
| Payments Due by Period | ||||||||||||||||||||
| Fiscal | Fiscal | Fiscal | ||||||||||||||||||
| (Millions of dollars) | Total | 2008 | 2009-2010 | 2011-2012 | Thereafter | |||||||||||||||
Long-term debt |
$ | 2,052.6 | $ | 14.2 | $ | 184.5 | $ | 616.4 | $ | 1,237.5 | ||||||||||
Interest on long-term
fixed rate debt |
1,020.1 | 129.7 | 237.1 | 176.5 | 476.8 | |||||||||||||||
Operating leases |
256.9 | 57.9 | 86.1 | 57.1 | 55.8 | |||||||||||||||
AmeriGas Propane
supply contracts |
25.8 | 25.8 | — | — | — | |||||||||||||||
International Propane
supply contracts |
121.8 | 61.7 | 60.1 | — | — | |||||||||||||||
Energy Services
supply contracts |
509.9 | 462.6 | 47.3 | — | — | |||||||||||||||
Gas Utility and Electric Utility
supply, storage and
transportation contracts |
1,019.5 | 478.9 | 293.5 | 125.5 | 121.6 | |||||||||||||||
Total |
$ | 5,006.6 | $ | 1,230.8 | $ | 908.6 | $ | 975.5 | $ | 1,891.7 | ||||||||||
Related Party Transactions
During fiscal 2007, 2006 and 2005, we did not enter into any related-party transactions that
had a material effect on our financial condition, results of operations or cash flows.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements that are expected to have a material
effect on our financial condition, change in financial condition, revenues or expenses,
results of operations, liquidity, capital expenditures or capital resources.
Utility Regulatory Matters
As a result of Pennsylvania’s Natural Gas Choice and Competition Act (the “Gas Competition
Act”), since July 1, 1999, all natural gas consumers in Pennsylvania, including residential
and smaller commercial and industrial customers (“core-market customers”), have been able to
purchase gas supplies from entities other than natural gas distribution companies (“NGDCs”).
Under the Gas Competition Act, NGDCs, like UGI Gas and PNG Gas, continue to serve as the
supplier of last resort for all core-market customers, and such sales of gas, as well as the
distribution service provided by NGDCs, continue to be subject to rate regulation by the
PUC. As of September 30, 2007, fewer than 2% of Gas Utility’s core-market customers purchase
their gas from alternate suppliers.
In an order entered on November 30, 2006, the PUC approved a settlement of a PNG Gas
base rate proceeding. The settlement authorized PNG Gas to increase its base rates $12.5
million annually, or approximately 4%, effective December 2, 2006.
As a result of the Electricity Generation Customer Choice and Competition Act (the
“Electric Competition Act”) that became effective January 1, 1997, all of Electric Utility’s
customers are permitted to acquire their electricity from entities other than Electric
Utility. As of September 30, 2007, none of Electric Utility’s customers have chosen an
alternative electricity generation supplier. Electric Utility remains the provider of last
resort, or default service provider, for its customers that are not served by an alternate
electric generation provider. The terms and conditions under which Electric Utility provides
POLR service, and rules governing the rates that may be charged for such service, have been
established in a series of PUC approved settlements, the latest of which became effective
June 23, 2006 (collectively, the “POLR Settlement”).
Electric Utility’s POLR service rules provide for annual shopping periods during which
customers may elect to remain on POLR service or choose an alternate supplier. Customers who
do not select an alternate supplier are obligated to remain on POLR service until the next
shopping period. Residential customers who return to POLR service must remain on POLR
service until the date of the second open shopping period after returning. Commercial and
industrial customers who return to POLR service must remain on POLR service until the next
open shopping period and may, in certain circumstances, be subject to generation rate
surcharges.
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In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up
to certain limits through December 31, 2009. Consistent with the terms of the POLR
Settlement, Electric Utility’s POLR rates increased 4.5% on January 1, 2005 and 3% on
January 1, 2006. Electric Utility also increased its POLR rates effective January 1, 2007,
which increased the average cost to a residential heating customer by approximately 35% over
such costs in effect during calendar 2006.
Effective January 1, 2008, total average residential rates will increase
approximately 5.5%. Electric Utility is also permitted to and has entered into multiple-year
fixed-rate POLR service contracts with certain of its customers. New PUC default
service regulations became effective on September 15, 2007, but do not disturb Electric
Utility’s POLR Settlement through 2009. Under the default service regulations, Electric
Utility will be required to file a default service plan with the PUC in 2008 that will
establish the terms and conditions under which it will offer POLR service commencing 2010.
We account for the operations of Gas Utility and Electric Utility in accordance with
SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). SFAS
71 requires us to record the effects of rate regulation in the financial statements. SFAS 71
allows us to defer expenses and revenues on the balance sheet as regulatory assets and
liabilities when it is probable that those expenses and income will be allowed in the
ratemaking process in a period different from the period in which they would have been
reflected in the income statement of an unregulated company. These deferred assets and
liabilities are then flowed through the income statement in the period in which the same
amounts are included in rates and recovered from or refunded to customers. As required by
SFAS 71, we monitor our regulatory and competitive environments to determine whether the
recovery of our regulatory assets continues to be probable. If we were to determine that
recovery of these regulatory assets is no longer probable, such assets would be written off
against earnings. We believe that SFAS 71 continues to apply to our regulated operations and
that the recovery of our regulatory assets is probable.
Manufactured Gas Plants
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned
and operated a number of manufactured gas plants (“MGPs”) prior to the general availability
of natural gas. Some constituents of coal tars and other residues of the manufactured gas
process are today considered hazardous substances under the Superfund Law and may be present
on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of
subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of
some gas companies under agreement. Pursuant to the requirements of the Public Utility
Holding Company Act of 1935, UGI Utilities divested all of its utility operations other than
those which now constitute UGI Gas and Electric Utility by the early 1950s.
UGI Utilities does not expect its costs for investigation and remediation of hazardous
substances at Pennsylvania MGP sites to be material to its results of operations because UGI
Gas is currently permitted to include in rates,
through future base rate proceedings, prudently incurred remediation costs associated with
such sites. In accordance with the terms of the PNG Gas base rate case order which became effective on December 2, 2006, site-specific
environmental investigation and remediation costs associated with PNG Gas incurred prior to
December 2, 2006 are amortized as removal costs over five-year periods. Such costs
incurred after December 1, 2006 are expensed as incurred.
As a result of the acquisition of PG Energy by UGI Utilities’ wholly-owned subsidiary,
UGIPNG, UGIPNG became party to a Multi-Site Remediation Consent Order and Agreement between
PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004
(“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform annually a
specified level of activities associated with environmental investigation and remediation
work at 11 currently owned properties on which MGP-related facilities were operated
(“Properties”). Under the Multi-Site Agreement, environmental expenditures, including
costs to perform work on the Properties, are capped at $1.1 million in any calender year. Costs related to investigation and remediation of one
property formerly owned by UGIPNG are also included in this cap. The Multi-Site Agreement
terminates in 2019 but may be terminated by either party effective at the end of any
two-year period beginning with the effective date.
UGI Utilities has been notified of several sites outside Pennsylvania on which private
parties allege MGPs were formerly owned or operated by it or owned or operated by its former
subsidiaries. Such parties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities is currently litigating four claims
against it relating to out-of-state sites. We accrue environmental investigation and cleanup
costs when it is probable that a liability exists and the amount or range of amounts can be
reasonably estimated.
Management believes that under applicable law UGI Utilities should not be liable in
those instances in which a former subsidiary owned or operated an MGP. There could be,
however, significant future costs of an uncertain amount associated with environmental
damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that
were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude
that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities
should be considered to have been an operator because of its conduct with respect to its
subsidiary’s MGP.
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South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006,
South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a
lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution
from UGI Utilities for past and future remediation costs related to the operations of a
former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from
1855 to 1954 and alleges that UGI Utilities controlled operations of the plant from 1910 to
1926 and is liable for 47% of the costs associated with the site. SCE&G asserts that it has
spent approximately $22 million in remediation costs and $26 million in third-party claims
relating to the site and estimates that future remediation costs could be as high
as $2.5 million. SCE&G further asserts that it has received a demand from the United States
Justice Department for natural resource damages. UGI Utilities is defending the suit.
City of Bangor, Maine v. Citizens Communications Co. In April 2003, Citizens
Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party
defendant in a civil action pending in the United States District Court for the District of Maine.
In that action, the plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover
environmental response costs associated with MGP wastes generated at a plant allegedly
operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently
joined UGI Utilities and ten other third-party defendants alleging that the third-party
defendants are responsible for an equitable share of costs Citizens may be required to pay
to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI
Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies
conducted by the City and Citizens suggest that it could cost up to $18 million to clean up
the river. Citizens’ third party claims have been stayed pending a resolution of the City’s
suit against Citizens, which was tried in September 2005. Maine’s Department of
Environmental Protection (“DEP”) informed UGI Utilities in March 2005 that it considers UGI
Utilities to be a potentially responsible party for costs incurred by the State of Maine
related to gas plant contaminants at this site. On June 27, 2006, the court issued an order
finding Citizens responsible for 60% of the cleanup costs. On February 14, 2007, Citizens
and the City entered into a Settlement agreement pursuant to which Citizens agreed to pay
$7.6 million in exchange for a release of its liabilities. UGI Utilities is evaluating what
effect, if any, the settlement agreement would have on claims against it. UGI Utilities
believes that it has good defenses to any claim that the DEP may bring to recover its costs,
and is defending the Citizens’ suit.
Consolidated Edison Company of New York v. UGI Utilities, Inc. On September 20, 2001,
Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the
United States District Court for the Southern District of New York, seeking contribution
from UGI Utilities for an allocated share of response costs associated with investigating
and assessing gas plant related contamination at former MGP sites in Westchester County, New
York. The complaint alleges that UGI Utilities “owned and operated” the MGPs prior to 1904.
The complaint also seeks a declaration that UGI Utilities is responsible for an allocated
percentage of future investigative and remedial costs at the sites.
The trial court granted UGI Utilities’ motion for summary judgment and dismissed
ConEd’s complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed
and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and
reversed in part the decision of the trial court. The appellate panel affirmed the trial
court’s decision dismissing claims that UGI Utilities was liable under CERCLA as an operator
of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the
trial court’s decision that UGI Utilities was released from liability at three sites where
UGI Utilities operated MGPs under lease. ConEd claims the cost of remediation for the three
sites would be approximately $14 million. On October 7, 2005, UGI Utilities filed for
reconsideration of the panel’s order, which was denied by the Second Circuit Court of
Appeals on January 17, 2006. On April 14, 2006, Utilities filed a petition requesting that
the United States Supreme Court review the decision of the Second Circuit Court of Appeals.
On June 18, 2007, the United States Supreme Court denied UGI Utilities’ petition. The case has now been
remanded back to the trial court. UGI Utilities is defending the suit.
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”)
informed UGI Utilities that KeySpan has spent $2.3 million and expects to spend another $11
million to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI
Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’
alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June
6, 2006, KeySpan reported that the New York Department of Environmental Conservation has
approved a remedy for the site that is estimated to cost approximately $10 million. KeySpan
believes that the cost could be as high as $20 million. UGI Utilities is in the process of
reviewing the information provided by KeySpan and is investigating this claim.
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Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities,
Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services
Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities,
(together the “Northeast Companies”), in the United States District Court for the District
of Connecticut seeking contribution from UGI Utilities for past and future remediation costs
related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities
in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled
operations of the plants from 1883 to 1941. The Northeast Companies estimated that
remediation costs for all of the sites would total approximately $215 million and asserted
that UGI Utilities is responsible for approximately $103 million of this amount. Based on
information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI
Utilities believes that it may have operated one of the sites, Waterbury North, under lease
for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’
estimate that remediation costs at Waterbury North could total $23 million. UGI Utilities is
defending the suit.
Antargaz Tax Matters
French tax authorities levy various taxes on legal entities and individuals regularly
operating a business in France which are commonly referred to collectively as “business
tax.” The amount of business tax charged annually is generally dependent upon the value of
the entity’s tangible fixed assets. Prior to the Antargaz Acquisition, Antargaz filed suit
against French tax authorities in connection with the assessment of business tax related to
the tax treatment of certain of its owned tanks at customer locations. Elf Antar France and
Elf Aquitaine, now Total France, former owners of Antargaz, agreed to indemnify Antargaz for
all payments that would have been due from Antargaz in respect of the tax related to its
tanks for the period from January 1, 1997 through December 31, 2000. Antargaz has recorded
liabilities for business taxes related to various classes of equipment. On February 4, 2005,
Antargaz received a letter concerning the business tax that was issued by the French
government to the French Committee of Butane and Propane (“CFBP”), a butane/propane industry
group that eliminated the requirement for Antargaz to pay business tax associated with tanks
at certain customer locations. In addition, during fiscal 2005, resolution was reached
relating to business taxes relating to a prior year. Our fiscal 2005 Consolidated Statement of
Income includes a pre-tax gain of $18.8 million and a net after-tax gain of $14.2 million
associated with the resolution of certain business tax matters related principally to prior
years. Further changes in the French government’s interpretation of the tax laws or in the
tax laws themselves could have either an adverse or a favorable effect on our results of
operations.
Market Risk Disclosures
Our primary market risk exposures are (1) market prices for LPG, natural gas and
electricity; (2) changes in interest rates; and (3) foreign currency exchange rates.
The risk associated with fluctuations in the prices the Partnership and our
International Propane operations pay for LPG is principally a result of market forces
reflecting changes in supply and demand for LPG and other energy commodities. Their
profitability is sensitive to changes in LPG supply costs. Increases in supply costs are
generally passed on to customers. International Propane and the Partnership may not,
however, always be able to pass on product cost increases fully or on a timely basis,
particularly when product costs rise rapidly. In order to reduce the volatility of LPG
market price risk, the Partnership uses contracts for the forward purchase or sale of
propane, propane fixed-price supply agreements, and over-the-counter derivative commodity
instruments including price swap
and option contracts. In addition, Antargaz hedges a portion of its anticipated U.S. dollar
denominated LPG product purchases through the use of forward foreign exchange contracts.
Antargaz may also enter into other contracts, similar to those used by the Partnership.
Flaga has used and may use derivative commodity instruments to reduce market risk associated
with a portion of its propane purchases. Currently, Flaga’s hedging activities are not
material to the Company’s financial position or results of operations. Over-the-counter
derivative commodity instruments utilized to hedge forecasted purchases of propane are
generally settled at expiration of the contract. In order to minimize credit risk associated
with derivative commodity contracts, we monitor established credit limits with the contract
counterparties. Although we use derivative financial and commodity instruments to reduce
market price risk associated with forecasted transactions, we do not use derivative
financial and commodity instruments for speculative or trading purposes.
Gas Utility’s tariffs contain clauses that permit recovery of substantially all of the
prudently incurred costs of natural gas it sells to its customers. The recovery clauses
provide for periodic adjustments for the difference between the total amounts actually
collected from customers through PGC rates and the recoverable costs incurred. Because of
this ratemaking mechanism, there is limited commodity price risk associated with our Gas
Utility operations. Gas Utility may enter into natural gas futures and option contracts to
reduce volatility in the cost of gas it purchases for retail core-market customers. At
September 30, 2007 and 2006, Gas Utility had $6.6 million and $2.7 million, respectively, of
restricted cash associated with natural gas futures accounts with brokers.
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Electric Utility purchases its electric power needs from electricity suppliers under
fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market.
Wholesale prices for electricity can be volatile especially during periods of high demand or
tight supply. As previously mentioned and in accordance with POLR settlements approved by
the PUC, Electric Utility may increase its POLR rates up to certain limits through December
31, 2009. Electric Utility’s fixed-price contracts with electricity suppliers mitigate most
risks associated with the POLR service rate limits in effect through December 31, 2009. With
respect to its existing fixed-price power contracts, should any of the counterparties fail
to provide electric power under the terms of such contracts, any increases in the cost of
replacement power could negatively impact Electric Utility results. In order to reduce this
nonperformance risk, Electric Utility has diversified its purchases across several suppliers
and entered into bilateral collateral arrangements with certain of them. From time to time,
Electric Utility enters into electric price swap agreements to reduce the volatility in the
cost of a portion of its anticipated electricity requirements. At September 30, 2007,
Electric Utility had an electric price swap agreement associated with purchases of a portion
of electricity anticipated to occur through December 2007.
In order to manage market price risk relating to substantially all of Energy Services’
fixed-price sales contracts for natural gas, Energy Services purchases exchange-traded and
over-the-counter natural gas futures contracts or enters into fixed-price supply
arrangements. Energy Services’ exchange-traded natural gas futures contracts are guaranteed
by the New York Mercantile Exchange (“NYMEX”) and have nominal credit risk. The change in
market value of these contracts generally requires daily cash deposits in margin
accounts with brokers. At September 30, 2007 and 2006, Energy Services had $6.2 million and
$11.5 million, respectively, of restricted cash on deposit in such margin accounts. Although
Energy Services’ fixed-price supply arrangements mitigate most risks associated with its
fixed-price sales contracts, should any of the natural gas suppliers under these
arrangements fail to perform, increases, if any, in the cost of replacement natural gas
would adversely impact Energy Services’ results. In order to reduce this risk of supplier
nonperformance, Energy Services has diversified its purchases across a number of suppliers.
UGID has entered into fixed-price sales agreements for a portion of the electricity
expected to be generated by its interests in electric generation assets. In the event that
these generation assets would not be able to produce all of the electricity needed to supply
electricity under these agreements, UGID would be required to purchase such electricity on
the spot market or under contract with other electricity suppliers. Accordingly, increases
in the cost of replacement power could negatively impact the Company’s results.
Asset Management has entered and may continue to enter into fixed-price sales
agreements for a portion of its propane sales. In order to manage the market price risk
relating to substantially all of its fixed-price sales contracts for propane, Asset
Management enters into price swap and option contracts.
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the
cash flows of variable-rate debt but generally do not impact its fair value. Conversely,
changes in interest rates impact the fair value of fixed-rate debt but do not impact their
cash flows.
Our variable-rate debt includes borrowings under AmeriGas OLP’s Credit Agreement, UGI
Utilities’ revolving credit agreement and a substantial portion of Antargaz’ and Flaga’s
debt. These debt agreements have interest rates that are generally indexed to short-term
market interest rates. As previously mentioned, Antargaz has effectively fixed the
underlying euribor interest rate on its variable-rate debt through March 2011 and Flaga has
fixed the underlying euribor interest rate on a substantial portion of its term loan through
September 2011 through the use of interest rate swaps. At September 30, 2007 and 2006,
combined borrowings outstanding under agreements, excluding Antargaz’ and Flaga’s
effectively fixed-rate debt, totaled $199.0 million and $287.0 million, respectively.
Excluding the fixed
portions of Antargaz’ and Flaga’s variable-rate debt, and based upon weighted average
borrowings outstanding under variable-rate agreements during fiscal 2007 and fiscal 2006, an
increase in short-term interest rates of 100 basis points (1%) would have increased our
fiscal 2007 interest expense by $1.8 million and $2.1 million, respectively.
The remainder of our debt outstanding is subject to fixed rates of interest. A 100
basis point increase in market interest rates would result in decreases in the fair value of
this fixed-rate debt of $88.4 million and $97.5 million at September 30, 2007 and 2006,
respectively. A 100 basis point decrease in market interest rates would result in increases
in the fair value of this fixed-rate debt of $98.1 million and $109.1 million at September
30, 2007 and 2006, respectively.
Long-term debt associated with our domestic businesses is typically issued at fixed
rates of interest based upon market rates for debt having similar terms and credit ratings.
As these long-term debt issues mature, we may refinance such debt with new debt having
interest rates reflecting then-current market conditions. This debt may have an interest
rate that is more or less than the refinanced debt. In order to reduce interest rate risk
associated with near to medium term forecasted issuances of fixed-rate debt, we may enter
into interest rate protection agreements.
Our primary exchange rate risk is associated with the U.S. dollar versus the euro. The
U.S. dollar value of our foreign-denominated assets and liabilities will fluctuate with
changes in the associated foreign currency exchange rates. We use derivative instruments to
hedge portions of our net investment in foreign subsidiaries (“net investment hedges”).
Realized gains or losses associated with net investments in foreign operations remain in
other comprehensive income until such foreign operations are liquidated. With respect to
our net investments in Flaga and Antargaz, a 10% decline in the value of the euro versus the
U.S. dollar, excluding the effects of any net investment hedges, would reduce their
aggregate net book value by approximately $56.1 million, which amount would be reflected in
other comprehensive income.
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The following table summarizes the fair values of unsettled market risk sensitive
derivative instruments held at September 30, 2007 and 2006. Fair values reflect the
estimated amounts that we would receive or (pay) to terminate the contracts at the reporting
date based upon quoted market prices or the fair value of comparable contracts at September
30, 2007 and 2006, respectively. The table also includes the changes in fair value that
would result if there were a 10% adverse change in (1) the market price of propane; (2) the
market price of natural gas; (3) the market price of electricity; (4) the three-month LIBOR
and the three- and six-month Euribor and; (5) the value of the euro versus the U.S. dollar.
Gas Utility’s exchange traded natural gas call option and futures contracts are excluded
from the table below because any associated net gains or losses are included in Gas
Utility’s PGC recovery mechanism.
| Change in | ||||||||
| Fair Value | Fair Value | |||||||
(Millions of dollars) |
||||||||
September 30, 2007: |
||||||||
Propane commodity price risk |
$ | 18.3 | $ | (18.5 | ) | |||
Natural gas commodity price risk |
(1.4 | ) | (8.6 | ) | ||||
Electricity commodity price risk |
0.8 | (0.3 | ) | |||||
Interest rate risk |
21.3 | (12.6 | ) | |||||
Foreign currency exchange rate risk |
(14.7 | ) | (27.1 | ) | ||||
September 30, 2006: |
||||||||
Propane commodity price risk |
$ | (26.4 | ) | $ | (21.2 | ) | ||
Natural gas commodity price risk |
(6.0 | ) | (10.4 | ) | ||||
Electricity commodity price risk |
5.2 | (1.3 | ) | |||||
Interest rate risk |
14.4 | (12.9 | ) | |||||
Foreign currency exchange rate risk |
2.4 | (13.8 | ) | |||||
Because the Company’s derivative instruments generally qualify as hedges under SFAS
133, we expect that changes in the fair value of derivative instruments used to manage
commodity, currency or interest rate market risk would be substantially offset by gains or
losses on the associated anticipated transactions.
Critical Accounting Policies and Estimates
The preparation of financial statements and related disclosures in compliance with
accounting principles generally accepted in the United States of America requires the
selection and application of accounting principles appropriate to the relevant facts and
circumstances of the Company’s operations and the use of estimates made by management. The
Company has identified the following critical accounting policies and estimates that are
most important to the portrayal of the Company’s financial condition and results of
operations. Changes in these policies and estimates could have a material effect on the
financial statements. The application of these accounting policies and estimates necessarily
requires management’s most subjective or complex judgments regarding estimates and projected
outcomes of future events which could have a material impact on the financial statements.
Management has reviewed these critical accounting policies, and the estimates and
assumptions associated with them, with the Company’s Audit Committee. In addition,
management has reviewed the following disclosures regarding the application of these
critical accounting policies and estimates with the Audit Committee.
Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation
regarding pending claims and legal actions that arise in the normal course of our
businesses. In addition, UGI Utilities and its former subsidiaries owned and operated a
number of MGPs in Pennsylvania and elsewhere, and UGIPNG owned and operated a number of MGP
sites located in Pennsylvania, at which hazardous substances may be present. In accordance
with accounting principles generally accepted in the United States of America, the Company
establishes reserves for pending claims and legal actions or environmental remediation
obligations when it is probable that a liability exists and the amount or range of amounts
can be reasonably estimated. Reasonable estimates involve management judgments based on a
broad range of information and prior experience. These judgments are reviewed quarterly as
more information is received and the amounts reserved are updated as necessary. Such
estimated reserves may differ materially from the actual liability and such reserves may
change materially as more information becomes available and estimated reserves are adjusted.
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Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to
regulation by the PUC. In accordance with SFAS 71, we record the effects of rate regulation
in our financial statements as regulatory assets or regulatory liabilities. We continually
assess whether the regulatory assets are probable of future recovery by evaluating the
regulatory environment, recent rate orders and public statements issued by the PUC, and the
status of any pending deregulation legislation. If future recovery of regulatory assets
ceases to be probable, the elimination of those regulatory assets would adversely impact our
results of operations and cash flows. As of September 30, 2007, our regulatory assets
totaled $103.8 million. See Note 1 to the Consolidated Financial Statements.
Depreciation and Amortization of Long-lived Assets. We compute depreciation on UGI
Utilities’ property, plant and equipment on a straight-line basis over the average remaining
lives of its various classes of depreciable property and on our other property, plant and
equipment on a straight-line basis over estimated useful lives generally ranging from 2 to
40 years. We also use amortization methods and determine asset values of intangible assets
other than goodwill using reasonable assumptions and projections. Changes in the estimated
useful lives of property, plant and equipment and changes in intangible asset amortization
methods or values could have a material effect on our results of operations. As of September
30, 2007, our net property, plant and equipment totaled $2,397.4 million and we recorded
depreciation expense of $150.6 million during fiscal 2007. As of September 30, 2007, our net
intangible assets totaled $173.1 million and we recorded intangible amortization expense of
$16.9 million during fiscal 2007.
Purchase Price Allocation. From time to time, the Company enters into material business
combinations. In accordance with SFAS No. 141, “Business Combinations” (“SFAS 141”), the
purchase price is allocated to the various assets acquired and liabilities assumed at their
estimated fair value. Fair values of assets acquired and liabilities assumed are based upon
available information and we may involve an independent third party to perform an appraisal.
Estimating fair values can be a complex and judgmental area and most commonly impacts
property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, if necessary,
up to one year from the acquisition date to finalize the purchase price allocation.
Impairment of Goodwill. Certain of the Company’s business units have goodwill resulting from
purchase business combinations. In accordance with SFAS No. 142, “Goodwill and Other
Intangible Assets” (“SFAS 142”), each of our reporting units with goodwill is required to
perform impairment tests annually or whenever events or circumstances indicate that the
value of goodwill may be impaired. In order to perform these impairment tests, management
must determine the reporting unit’s fair value using quoted market prices or, in the absence
of quoted market prices, valuation techniques which use discounted estimates of future cash
flows to be generated by the reporting unit. These cash flow estimates involve management
judgments based on a broad range of information and historical results. To the extent
estimated cash flows are revised downward, the reporting unit may be required to write down
all or a portion of its goodwill which would adversely impact our results of operations. As
of September 30, 2007, our goodwill totaled $1,498.8 million.
Pension Plan Assumptions. The costs of providing benefits under our Pension Plans is
dependent on historical information such as employee age, length of service, level of
compensation and the actual rate of return on plan assets. In addition, certain assumptions
relating to the future are used to determine pension expense including the discount rate
applied to benefit obligations, the expected rate of return on plan assets and the rate of
compensation increase, among others. Assets of the Pension Plans are held in trust and
consist principally of equity and fixed income mutual funds. Changes in plan assumptions as
well as fluctuations in actual equity or bond market returns could have a material impact on
future pension costs. We believe the two most critical assumptions are the expected rate of
return on plan assets and the discount rate. A decrease in the expected rate of return on
plan assets of 50 basis points to a rate of 8.0% would result in an increase in pre-tax
pension expense of approximately $1.8 million in fiscal 2008. A decrease in the discount
rate of 50 basis points to a rate of 5.9% would result in an increase in pre-tax pension
expense of approximately $1.7 million in fiscal 2008.
Income Taxes. We use the asset and liability method of accounting for income taxes. Under
this method, income tax expense is recognized for the amount of taxes payable or refundable
for the current year and for deferred tax liabilities and assets for the future tax
consequences of events that have been recognized in our financial statements or tax returns.
We use assumptions, judgments and estimates to determine our current provision for income
taxes. We also use assumptions, judgments and estimates to determine our deferred tax assets
and liabilities and any valuation allowance to be recorded against a deferred tax asset. Our
assumptions, judgments and estimates relative to the current provision for income tax give
consideration to current tax laws, our interpretation of current tax laws and possible
outcomes of current and future audits conducted by foreign and domestic tax authorities.
Changes in tax law or our interpretation of such and the resolution of current and future
tax audits could significantly impact the amounts provided for income taxes in our
consolidated financial statements. Our assumptions, judgments and estimates relative to the
amount of deferred income taxes take into account estimates of the amount of future taxable
income. Actual taxable income or future estimates of taxable income could render our current
assumptions, judgments and estimates inaccurate. Changes in the assumptions, judgments and
estimates mentioned above could cause our actual income tax obligations to differ
significantly from our estimates. As of September 30, 2007, our net deferred tax liabilities
totaled $515.8 million.
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Recently Issued Accounting Pronouncements
Below is a listing of recently issued accounting pronouncements by the Financial Accounting
Standards Board. See Note 1 to the Consolidated Financial Statements for additional
discussion of these pronouncements.
| Title of Guidance | Month of Issue | Effective Date | ||||||
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-Including
an amendment of FASB Statement No. 115” |
February 2007 | fiscal 2009 | ||||||
SFAS No. 157, “Fair Value Measures” |
September 2006 | fiscal 2009 | ||||||
FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” |
June 2006 | fiscal 2008 | ||||||
Forward-Looking Statements
Information contained in this Report may
contain forward-looking statements within the meaning of Section 27A of the Securities Act
of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use
forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans,
strategies, events or developments that we expect or anticipate will or may occur in the
future.
A forward-looking statement may include a statement of the assumptions or bases
underlying the forward-looking statement. We believe that we have chosen these assumptions
or bases in good faith and that they are reasonable. However, we caution you that actual
results almost always vary from assumed facts or bases, and the differences between actual
results and assumed facts or bases can be material, depending on the circumstances. When
considering forward-looking statements, you should keep in mind the following important
factors which could affect our future results and could cause those results to differ
materially from those expressed in our forward-looking statements: (1) adverse weather
conditions resulting in reduced demand; (2) cost volatility and availability of propane and
other LPG, oil, electricity, and natural gas and the capacity to transport product to our
market areas; (3) changes in domestic and foreign laws and regulations, including safety,
tax and accounting matters; (4) the impact of pending and future legal proceedings; (5)
competitive pressures from the same and alternative energy sources; (6) failure to acquire
new customers thereby reducing or limiting any increase in revenues; (7) liability for
environmental claims; (8) increased customer conservation measures due to high energy prices
and improvements in energy efficiency and technology resulting in reduced demand; (9)
adverse labor relations; (10) large customer, counter-party or supplier defaults; (11)
liability in excess of insurance coverage for personal injury and property damage arising
from explosions and other catastrophic events, including acts of terrorism, resulting from
operating hazards and risks incidental to generating and distributing electricity and
transporting, storing and distributing natural gas, propane and LPG; (12) political,
regulatory and economic conditions in the United States and in foreign countries, including
foreign currency exchange rate fluctuations, particularly the euro; (13) reduced access to
capital markets and interest rate fluctuations; (14) reduced distributions from
subsidiaries; and (15) the timing and success of the Company’s efforts to develop new
business opportunities.
These factors are not necessarily all of the important factors that could cause actual
results to differ materially from those expressed in any of our forward-looking statements.
Other unknown or unpredictable factors could also have material adverse effects on future
results. We undertake no obligation to update publicly any forward-looking statement whether
as a result of new information or future events except as required by the federal securities
laws.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
“Quantitative and Qualitative Disclosures About Market Risk” are contained in Item 7 -
Management’s Discussion and Analysis of Financial Condition and Results of Operations under the
caption “Market Risk Disclosures” and are incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management’s Annual Report on Internal Control Over Financial Reporting and the financial
statements and financial statement schedules referred to in the Index contained on page F-2 of this
Report are incorporated herein by reference.
ITEM
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
| (a) | The Company’s management, with the participation of the Company’s Chief
Executive Officer and Chief Financial Officer, evaluated the effectiveness of the
Company’s disclosure controls and procedures as of the end of the period covered by
this Report. Based on that evaluation, the Chief Executive Officer and Chief Financial
Officer concluded that the Company’s disclosure controls and procedures as of the end
of the period covered by this Report were designed and functioning effectively to
provide reasonable assurance that the information required to be disclosed by the
Company in reports filed under the Securities Exchange Act of 1934, as amended, is (i)
recorded, processed, summarized and reported within the time periods specified in the
SEC’s rules and forms and (ii) accumulated and communicated to our management,
including the Chief Executive Officer and Chief Financial Officer, as appropriate to
allow timely decisions regarding disclosure. |
||
| (b) | For “Management’s Annual Report on Internal Control Over Financial Reporting”
see Item 8 of this Report (which information is incorporated herein by reference). |
||
| (c) | No change in the Company’s internal control over financial reporting occurred
during the Company’s most recent fiscal quarter that has materially affected, or is
reasonably likely to materially affect, the Company’s internal control over financial
reporting. |
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ITEM 9B. OTHER INFORMATION
None.
PART III:
ITEMS 10 THROUGH 14.
In accordance with General Instruction G(3), and except as set forth below, the information
required by Items 10, 11, 12, 13 and 14 is incorporated in this Report by reference to the
following portions of UGI’s Proxy Statement, which will be filed with the Securities and Exchange
Commission by January 28, 2008.
| Captions of Proxy Statement | ||||
| Information | Incorporated by Reference | |||
|
Item 10.
|
Directors, Executive Officers and Corporate Governance | Election of Directors – Nominees; Corporate Governance; Communications with the Board; Board Committees and Meeting Attendance; Securities Ownership of Management – Section 16(a) – Beneficial Ownership Reporting Compliance; Report of the Audit Committee of the Board of Directors | ||
| The Code of Ethics for the Chief Executive Officer and Senior Financial Officers of UGI Corporation is available without charge on the Company’s website, www.ugicorp.com or by writing to Robert W. Krick, Vice President and Treasurer, UGI Corporation, P. O. Box 858, Valley Forge, PA 19482. | ||||
|
Item 11.
|
Executive Compensation | Compensation of Directors; Report of the Compensation and Management Development Committeee of the Board of Directors; Compensation Discussion and Analysis; Compensation of Executive Officers; Compensation Committee Interlocks and Insider Participation | ||
|
Item 12.
|
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | Securities Ownership of Certain Beneficial Owners; Securities Ownership of Management | ||
|
Item 13.
|
Certain Relationships and Related Transactions, and Director Independence | Election of Directors – Board Committees and Meeting Attendance; Policy for Approval of Related Person Transactions | ||
|
Item 14.
|
Principal Accountant Fees and Services | The Independent Registered Public Accountants |
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Equity Compensation Table
The following table sets forth information as of the end of our 2007 fiscal year
with respect to compensation plans under which our equity securities are authorized for issuance.
| Number of securities | ||||||||||||
| Number of securities to be | Weighted average | remaining available for future | ||||||||||
| issued upon exercise of | exercise price of | issuance under equity | ||||||||||
| outstanding options, | outstanding options, | compensation plans | ||||||||||
| warrants and rights | warrants and rights | (excluding securities reflected | ||||||||||
| Plan category | (a) | (b) | in column (a)) (c) | |||||||||
Equity compensation
plans approved by
security holders
(1) |
6,031,504 | $ | 20.11 | |||||||||
| 879,000 | $ | 0 | 8,399,397 | |||||||||
Equity compensation
plans not approved
by security holders
(2) |
326,575 | $ | 11.59 | 0 | ||||||||
Total |
7,237,079 | $ | 19.651 | (3) | 8,399,397 | |||||||
| (1) | Column (a) represents 6,031,504 stock options under the 1997 Stock Option and Dividend
Equivalent Plan, the 2000 Directors’ Stock Option Plan, the 2000 Stock Incentive Plan and the
2004 Omnibus Equity Compensation Plan, as amended, and 879,000 phantom share units under the 2004
Omnibus Equity Compensation Plan, as amended. |
|
| (2) | Column (a) represents 326,575 stock options under the 1992 and 2002 Non-Qualified
Stock Option Plans. Under the 1992 and 2002 Non-Qualified Stock Option Plans, the option
exercise price is not less than 100% of the fair market value of the Company’s common stock on
the date of grant. Generally, options become exercisable in three equal annual installments
beginning on the first anniversary of the grant date. All options are non-transferable and
generally exercisable only while the holder is employed by the Company or an affiliate, with
exceptions for exercise following retirement, disability and death. Options are subject to
adjustment in the event of recapitalization, stock splits, mergers and other similar
corporate transactions affecting the Company’s common stock. |
|
| (3) | Weighted-average exercise price of outstanding options; excludes phantom share units. |
66
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The information concerning the Company’s executive officers required by Item 10 is set forth
below.
EXECUTIVE OFFICERS
| Name | Age | Position | ||||
Lon R. Greenberg
|
57 | Chairman and Chief Executive Officer | ||||
John L. Walsh
|
52 | President and Chief Operating Officer | ||||
Eugene V.N. Bissell
|
54 | President and Chief Executive Officer, AmeriGas Propane, Inc. | ||||
Michael J. Cuzzolina
|
62 | Vice President — Accounting and Financial Control and Chief Risk Officer | ||||
Bradley C. Hall
|
54 | Vice President — New Business Development | ||||
Robert H. Knauss
|
54 | Vice President and General Counsel and Assistant Secretary | ||||
Peter Kelly
|
50 | Vice President — Finance and Chief Financial Officer | ||||
David W. Trego
|
49 | President and Chief Executive Officer, UGI Utilities, Inc. | ||||
François Varagne
|
52 | Chairman of the Board and Chief Executive Officer of Antargaz | ||||
All officers, except Mr. Varagne, are elected for a one-year term at the organizational
meetings of the respective Boards of Directors held each year. Mr. Varagne was appointed as
Chairman of the Board of Antargaz on January 26, 2005. His term of office is five years.
There are no family relationships between any of the officers or between any of the officers
and any of the directors.
Lon R. Greenberg
Mr. Greenberg was elected Chairman of UGI effective August 1, 1996, having been elected Chief
Executive Officer effective August 1, 1995. He held the office of President of UGI from 1994 to
2005. He was elected Director of UGI and UGI Utilities in July 1994. He was elected a Director of
AmeriGas Propane, Inc. in 1994 and has been Chairman since 1996. He
also served as President and Chief Executive Officer of AmeriGas Propane (1996 to 2000). Mr.
Greenberg was Senior Vice President — Legal and Corporate Development (1989 to 1994). He joined the
Company in 1980 as Corporate Development Counsel. Mr. Greenberg is also a director of Aqua
America, Inc.
John L. Walsh
Mr. Walsh is President and Chief Operating Officer and a Director (since April 2005). He is
also Vice Chairman and Director of both AmeriGas Propane, Inc. and UGI Utilities, Inc. (since April
2005). He previously served as Chief Executive of the Industrial and Special Products division and
executive director of BOC Group PLC, an industrial gases company (2001-2005). From 1986 to 2001, he
held various senior management positions with the BOC Group. Prior to joining BOC Group, Mr. Walsh
was a Vice President of UGI’s industrial gas division prior to its sale to BOC Group in 1989. From
1981 until 1986, Mr. Walsh held several management positions with affiliates of UGI.
67
Table of Contents
Eugene V.N. Bissell
Mr. Bissell is President, Chief Executive Officer and a Director of AmeriGas Propane, Inc.
(since July 2000), having served as Senior Vice President — Sales and Marketing (1999 to 2000) and
Vice President — Sales and Operations (1995 to 1999). Previously, he was Vice President -
Distributors and Fabrication, BOC Gases (1995), having been Vice President — National Sales (1993
to 1995) and Regional Vice President (Southern Region) for Distributor and Cylinder Gases Division,
BOC Gases (1989 to 1993). From 1981 to 1987, Mr. Bissell held various positions with the Company
and its subsidiaries, including Director, Corporate Development. Mr. Bissell is a member of the
Board of Directors of the National Propane Gas Association and a member of the Kalamazoo College
Board of Trustees.
Michael J. Cuzzolina
Mr. Cuzzolina was elected Vice President — Accounting and Financial Control and Chief Risk
Officer of the Company in July 2003. He served as President and Chief Operating Officer of Flaga
GmbH from 1999 to 2004. Mr. Cuzzolina joined the Company in 1974 and previously served as Vice
President – Accounting and Financial Control (1984 to 1999).
Bradley C. Hall
Mr. Hall is Vice President — New Business Development (since October 1994). He also serves as
President of UGI Enterprises, Inc. (since 1994). He joined the Company in 1982 and held various
positions in UGI Utilities, Inc., including Vice President — Marketing and Rates.
Robert H. Knauss
Mr. Knauss was elected Vice President and General Counsel and Assistant Secretary on September
30, 2003. He previously served as Vice President – Law and Associate General Counsel of AmeriGas
Propane, Inc. (1996 to 2003), and Group Counsel – Propane of UGI (1989
to 1996). He joined the Company in 1985. Previously, Mr. Knauss was an associate at the firm of
Ballard, Spahr, Andrews & Ingersoll in Philadelphia.
Peter Kelly
Mr. Kelly is Vice President – Finance and Chief Financial Officer (since September 2007). He
previously served as Executive Vice President and Chief Financial Officer of Agere Systems, Inc., a
global manufacturer of semiconductors, a position in which he served from 2005 to 2007. Mr. Kelly
served as Executive Vice President-Global Operations for Agere Systems, Inc. (2001-2005). Mr. Kelly
currently serves on the board of directors and audit committee of Plexus Corp., an electronics
manufacturing services company.
68
Table of Contents
David W. Trego
Mr. Trego is President and Chief Executive Officer of UGI Utilities, Inc. (since October
2004). He previously served as Vice President-Electric Distribution (2002 to 2004). Prior to that
assignment, Mr. Trego served in a number of capacities in the Gas Utility Division, including
marketing, operations, customer relations and engineering. He joined UGI Utilities in 1987.
François Varagne
Mr. Varagne is Chairman of the Board and Chief Executive Officer of Antargaz (since 2001).
Before joining Antargaz, Mr. Varagne was Chairman of the Board and Chief Executive Officer of VIA
GTI, a common carrier in France (1998-2001). Prior to that, Mr. Varagne was Chairman of the Board
and Chief Executive Officer of Brink’s France, a funds carrier (1997 to 1998).
PART IV:
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents filed as part of this report:
(1) Financial Statements:
Included under Item 8 are the following financial statements and supplementary
data:
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of September 30, 2007 and 2006
Consolidated Statements of Income for the years ended September 30, 2007,
2006 and 2005
Consolidated Statements of Cash Flows for the years ended September 30,
2007, 2006 and 2005
Consolidated Statements of Stockholders’ Equity for the years ended
September 30, 2007, 2006 and 2005
Notes to Consolidated Financial Statements
(2) Financial Statement Schedules:
I – Condensed Financial Information of Registrant (Parent Company)
II – Valuation and Qualifying Accounts for the years ended
September 30, 2007, 2006 and 2005
We have omitted all other financial statement schedules because the required
information is (1) not present; (2) not present in amounts sufficient to
require submission of the schedule; or (3) included elsewhere in the
financial statements or related notes. |
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Table of Contents
| (3) | List of Exhibits: |
||
The exhibits filed as part of this report are as follows (exhibits incorporated
by reference are set forth with the name of the registrant, the type of report
and registration number or last date of the period for which it was filed, and
the exhibit number in such filing): |
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
3.1
|
(Second) Amended and Restated Articles of Incorporation of the Company as amended through June 6, 2005 | UGI | Form 10-Q (6/30/05) | 3.1 | ||||||
3.2
|
Bylaws of UGI as amended through September 28, 2004 | UGI | Form 8-K (9/28/04) | 3.2 | ||||||
4
|
Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of long-term debt not required to be filed pursuant to Item 601(b)(4) of Regulation S-K) | |||||||||
4.1
|
[Intentionally Omitted] | |||||||||
4.2
|
The description of the Company’s Common Stock contained in the Company’s registration statement filed under the Securities Exchange Act of 1934, as amended | UGI | Form 8-B/A (4/17/96) | 3. | (4) | |||||
4.3
|
UGI’s (Second) Amended and Restated Articles of Incorporation and Bylaws referred to in 3.1 and 3.2 above | |||||||||
70
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
4.4
|
Third Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of December 1, 2004 | AmeriGas Partners, L.P. | Form 8-K (12/1/04) | 3.1 | ||||||
4.4 (a)
|
Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. effective October 15, 2007 | AmeriGas Partners, L.P. | Form 8-K (10/15/07) | 3.1 | ||||||
4.5
|
Indenture, dated May 3, 2005, by and among AmeriGas Partners, L.P., a Delaware limited partnership, AmeriGas Finance Corp., a Delaware corporation, and Wachovia Bank, National Association, as trustee | AmeriGas Partners, L.P. | Form 8-K (5/3/05) | 4.1 | ||||||
4.6
|
Indenture, dated January 26, 2006, by and among AmeriGas Partners, L.P., a Delaware limited partnership, AP Eagle Finance Corp., a Delaware corporation, and U.S. Bank National Association, as trustee | AmeriGas Partners, L.P. | Form 8-K (1/26/06) | 4.1 | ||||||
4.7
|
Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994 | Utilities | Registration Statement No. 33-77514 (4/8/94) | 4 | (c) | |||||
4.8
|
Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association | Utilities | Form 8-K (9/12/06) | 4.2 | ||||||
4.9
|
Form of Fixed Rate Medium-Term Note | Utilities | Form 8-K (8/26/94) | 4 | (i) | |||||
4.10
|
Form of Fixed Rate Series B Medium-Term Note | Utilities | Form 8-K (8/1/96) | 4 | (i) | |||||
4.11
|
Form of Floating Rate Series B Medium-Term Note | Utilities | Form 8-K (8/1/96) | 4(ii) | ||||||
4.12
|
Officer’s Certificate establishing Medium-Term Notes Series | Utilities | Form 8-K (8/26/94) | 4(iv) | ||||||
71
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
4.13
|
Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture | Utilities | Form 8-K (8/1/96) | 4(iv) | ||||||
4.14
|
Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture | Utilities | Form 8-K (5/21/02) | 4.2 | ||||||
10.1
|
Service Agreement (Rate FSS) dated as of November 1, 1989 between Utilities and Columbia, as modified pursuant to the orders of the Federal Energy Regulatory Commission at Docket No. RS92-5-000 reported at Columbia Gas Transmission Corp., 64 FERC ¶61,060 (1993), order on rehearing, 64 FERC ¶61,365 (1993) | UGI | Form 10-K (9/30/95) | 10.5 | ||||||
10.2**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan Directors Stock Unit Grant Letter dated as of January 2006 | UGI | Form 8-K (12/6/05) | 10.2 | ||||||
10.3**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan Directors Nonqualified Stock Option Grant Letter dated as of January 1, 2006 | UGI | Form 8-K (12/6/05) | 10.3 | ||||||
10.4**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan Utilities Employees Performance Unit Grant Letter dated as of January 1, 2006 | UGI | Form 10-K (9/30/06) | 10.4 | ||||||
10.5**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Employees Stock Unit Grant Letter | UGI | Form 8-K (12/6/05) | 10.9 | ||||||
10.6**
|
UGI Corporation Directors Deferred Compensation Plan Amended and Restated as of January 1, 2000 | UGI | Form 10-K (9/30/00) | 10.6 | ||||||
10.7**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Employees Performance Unit Grant Letter dated as of January 1, 2006 | UGI | Form 10-K (9/30/06) | 10.7 | ||||||
*10.8**
|
UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006 | |||||||||
72
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
10.9**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan AmeriGas Employees Nonqualified Stock Option Grant Letter dated as of January 1, 2006 | UGI | Form 8-K (12/6/05) | 10.6 | ||||||
10.10**
|
UGI Corporation 1997 Stock Option and Dividend Equivalent Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.10 | ||||||
10.11**
|
AmeriGas Propane, Inc. Executive Employee Severance Pay Plan, as amended December 6, 2004 | AmeriGas Partners, L.P. | Form 10-K (9/30/04) | 10.4 | ||||||
10.11(a)**
|
Description of AmeriGas Propane, Inc. Executive Employee Severance Pay Plan, amended July 24, 2006 | AmeriGas Partners, L.P. | Form 10-Q (6/30/06) | 10.1 | ||||||
10.12**
|
UGI Corporation Senior Executive Employee Severance Pay Plan as amended December 7, 2004 | UGI | Form 10-K (9/30/04) | 10.12 | ||||||
10.12(a)**
|
Description of UGI Corporation Senior Executive Employee Severance Pay Plan, as amended July 25, 2006 | UGI | Form 10-Q (6/30/06) | 10.1 | ||||||
10.13**
|
UGI Corporation 2000 Directors’ Stock Option Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.13 | ||||||
10.14**
|
UGI Corporation 2000 Stock Incentive Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.14 | ||||||
10.15**
|
Letter Agreement dated May 15, 2002 regarding severance arrangement for Mr. Varagne | UGI | Form 10-K (9/30/05) | 10.15 | ||||||
*10.16**
|
UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated on July 31, 2007 | |||||||||
10.17**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006. | UGI | Form 8-K (3/27/07) | 10.1 | ||||||
73
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
10.17(a)**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan, as amended December 7, 2004 – Terms and Conditions as amended December 6, 2005 | UGI | Form 8-K (12/6/05) | 10.10 | ||||||
10.18
|
Credit Agreement dated as of November 6, 2006 among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as Guarantor, Petrolane Incorporated, as Guarantor, Citigroup Global Markets Inc., as Syndication Agent, J.P. Morgan Securities Inc. and Credit Suisse Securities (USA) LLC, as Co- Documentation Agents, Wachovia Bank, National Association, as Agent, Issuing Bank and Swing Line Bank, and the other financial institutions party thereto | AmeriGas Partners, L.P. | Form 8-K (11/6/06) | 10.1 | ||||||
10.19
|
Credit Agreement, dated as of August 11, 2006, among UGI Utilities, Inc., as borrower, and Citibank, N.A., as agent, Wachovia Bank, National Association, as syndication agent, and Citizens Bank of Pennsylvania, Credit Suisse, Cayman Islands Branch, Deutsche Bank AG New York Branch, JPMorgan Chase Bank, N.A., Mellon Bank, N.A., PNC Bank, National Association, and the other financial institutions from time to time parties thereto | Utilities | Form 8-K (8/11/06) | 10.1 | ||||||
10.20**
|
Form of Confidentiality and Post-Employment Activities Agreement with AmeriGas Propane, Inc., in its own right and as general partner of AmeriGas Partners, L.P., for Messrs. Bissell, Katz and Knauss | AmeriGas Partners, L.P. | Form 10-Q (3/31/05) | 10.3 | ||||||
10.21**
|
Confidentiality and Post-Employment Activities Agreement with AmeriGas Propane, Inc., in its own right and as general partner of AmeriGas Partners, L.P., for Mr. Sheridan | AmeriGas Partners, L.P. | Form 8-K (8/15/05) | 10.1 | ||||||
10.22**
|
Summary of Director Compensation as of October 1, 2006 | UGI | Form 10-K (9/30/06) | 10.22 | ||||||
10.23
|
[Intentionally Omitted] | |||||||||
74
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
10.24
|
Restricted Subsidiary Guarantee by the Restricted Subsidiaries of AmeriGas Propane, L.P., as Guarantors, for the benefit of Wachovia Bank, National Association and the Banks dated as of November 6, 2006 | AmeriGas Partners, L.P. |
Form 10-K (9/30/06) | 10.2 | ||||||
10.25
|
Release of Liens and Termination of Security Documents dated as of November 6, 2006 by and among AmeriGas Propane, Inc., Petrolane Incorporated, AmeriGas Propane, L.P., AmeriGas Propane Parts & Service, Inc. and Wachovia Bank, National Association, as Collateral Agent for the Secured Creditors, pursuant to the Intercreditor and Agency Agreement dated as of April 19, 1995 | AmeriGas Partners, L.P. |
Form 10-K (9/30/06) | 10.3 | ||||||
10.26
|
[Intentionally Omitted] | |||||||||
10.27
|
Trademark License Agreement dated April 19, 1995 among UGI Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | AmeriGas Partners, L.P. |
Form 10-Q (3/31/95) | 10.6 | ||||||
10.28
|
Trademark License Agreement, dated April 19, 1995 among AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | AmeriGas Partners, L.P. |
Form 10-Q (3/31/95) | 10.7 | ||||||
10.29
|
Stock Purchase Agreement dated May 27, 1989, as amended and restated July 31, 1989, between Texas Eastern Corporation and QFB Partners | Petrolane
Incorporated/ AmeriGas Partners, L.P. |
Registration Statement No. 33-69450 | 10.16 | (a) | |||||
10.30**
|
Description of oral employment at-will arrangements for Messrs. Greenberg, Varagne and Walsh | UGI | Form 10-K (9/30/05) | 10.30 | ||||||
10.31**
|
Description of oral employment at-will arrangement for Mr. Bissell | AmeriGas Partners, L.P. | Form 10-K (9/30/05) | 10.30 | ||||||
10.32**
|
AmeriGas Propane, Inc. Supplemental Executive Retirement Plan, as Amended July 30, 2007 | AmeriGas Partners, L.P. | Form 10-K (9/30/07) | 10.25 | ||||||
10.33**
|
AmeriGas Propane, Inc. Executive Annual Bonus Plan, effective as of October 1, 2006 | AmeriGas Partners, L.P. | Form 10-K (9/30/07) | 10.19 | ||||||
75
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
10.34**
|
UGI Utilities, Inc. Executive Annual Bonus Plan effective as of October 1, 2006 | Utilities | Form 10-K (9/30/07) | 10.5 | ||||||
10.35**
|
Form of Change in Control Agreement for Messrs. Greenberg, Kelly and Walsh | UGI | Form 8-K (12/6/05) | 10.1 | ||||||
10.36**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Employees Nonqualified Stock Option Grant Letter dated as of January 1, 2006 | UGI | Form 8-K (12/6/05) | 10.4 | ||||||
10.36(a)**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Utilities Employees Nonqualified Stock Option Grant Letter dated as of January 1, 2006 | UGI | Form 8-K (12/6/05) | 10.5 | ||||||
10.37**
|
Form of Change in Control Agreement for Mr. Bissell | AmeriGas Partners, L.P. | Form 8-K (12/5/05) | 10.1 | ||||||
10.38**
|
2002 Non-Qualified Stock Option Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.38 | ||||||
10.39**
|
1992 Non-Qualified Stock Option Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.39 | ||||||
10.40**
|
AmeriGas Propane, Inc. Discretionary Long-Term Incentive Plan for Non-Executive Key Employees | AmeriGas Partners, L.P. | Form 10-K (9/30/02) | 10.2 | ||||||
10.41
|
Service Agreement for comprehensive delivery service (Rate CDS) dated February 23, 1999 between UGI Utilities, Inc. and Texas Eastern Transmission Corporation | UGI | Form 10-K (9/30/00) | 10.41 | ||||||
10.42
|
Purchase Agreement dated January 30, 2001 and Amended and Restated on August 7, 2001 by and among Columbia Energy Group, Columbia Propane Corporation, Columbia Propane, L.P., CP Holdings, Inc., AmeriGas Propane, L.P., AmeriGas Partners, L.P., and AmeriGas Propane, Inc. | AmeriGas Partners, L.P. | Form 8-K (8/8/01) | 10.1 | ||||||
10.43**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan, Sub-Plan for French Employees Stock Option Grant Letter dated as of 2004 | UGI | Form 10-K (9/30/04) | 10.43 | ||||||
76
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
10.44
|
Purchase Agreement by and among Columbia Propane, L.P., CP Holdings, Inc., Columbia Propane Corporation, National Propane Partners, L.P., National Propane Corporation, National Propane SPG, Inc., and Triarc Companies, Inc. dated as of April 5, 1999 | National Propane Partners, L.P. | Form 8-K (4/19/99) | 10.5 | ||||||
10.45
|
Capital Contribution Agreement dated as of August 21, 2001 by and between Columbia Propane, L.P. and AmeriGas Propane, L.P. acknowledged and agreed to by CP Holdings, Inc. | AmeriGas Partners, L.P. | Form 8-K (8/21/01) | 10.2 | ||||||
10.46
|
Promissory Note by National Propane L.P., a Delaware limited partnership in favor of Columbia Propane Corporation dated July 19, 1999 | AmeriGas Partners, L.P. | Form 10-K (9/30/01) | 10.39 | ||||||
10.47
|
Loan Agreement dated July 19, 1999, between National Propane, L.P. and Columbia Propane Corporation | AmeriGas Partners, L.P. | Form 10-K (9/30/01) | 10.40 | ||||||
10.48
|
First Amendment dated August 21, 2001 to Loan Agreement dated July 19, 1999 between National Propane, L.P. and Columbia Propane Corporation | AmeriGas Partners, L.P. | Form 10-K (9/30/01) | 10.41 | ||||||
10.49
|
Columbia Energy Group Payment Guaranty dated April 5, 1999 | AmeriGas Partners, L.P. | Form 10-K (9/30/01) | 10.42 | ||||||
10.50
|
Keep Well Agreement by and between AmeriGas Propane, L.P. and Columbia Propane Corporation dated August 21, 2001 | AmeriGas Partners, L.P. | Form 10-K (9/30/01) | 10.46 | ||||||
10.51**
|
AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., as amended December 15, 2003 (“AmeriGas 2000 Plan”). | AmeriGas Partners, L.P. | Form 10-Q (6/30/04) | 10.2 | ||||||
10.51(a)**
|
AmeriGas 2000 Plan Restricted Unit Grant Letter dated as of January 1, 2006 | AmeriGas Partners, L.P. | Form 10-K (9/30/06) | 10.20 | ||||||
10.52
|
Storage Transportation Service Agreement (Rate Schedule SST) between Utilities and Columbia dated November 1, 1993, as modified pursuant to orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.25 | ||||||
77
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
10.53
|
Gas Service Delivery and Supply Agreement between Utilities and UGI Energy Services, Inc. dated August 1, 2004 | Utilities | Form 10-K (9/30/04) | 10.32 | ||||||
10.54
|
No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern Transmission dated February 23, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.27 | ||||||
10.55
|
No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern Transmission dated October 31, 2000, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.28 | ||||||
10.56
|
Firm Transportation Service Agreement (Rate Schedule FT-1) between Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.29 | ||||||
10.57
|
Amendment No. 1 dated November 1, 2004, to the Service Agreement (Rate FSS) dated as of November 1, 1989 between Utilities and Columbia, as modified pursuant to the orders of the Federal Energy Regulatory Commission at Docket No. RS92-5-000 reported at Columbia Gas Transmission Corp., 64 FERC ¶61,060 (1993), order on rehearing, 64 FERC ¶61,365 (1993) | Utilities | Form 10-K (9/30/04) | 10.26 | ||||||
10.58
|
Firm Transportation Service Agreement (Rate Schedule FT) between Utilities and Transcontinental Gas Pipe Line dated October 1, 1996, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.31 | ||||||
78
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
10.58(a)
|
Amendment dated March 20, 2007 to the Firm Transportation Service Agreement (Rate Schedule FT) dated October 1, 1996 between UGI Utilities and Transcontinental Gas Pipe Line Corporation, as modified pursuant to various orders of the Federal Energy Regulatory Commission. | Utilities | Form 8-K (3/20/07) | 10.1 | ||||||
10.59
|
Amendment No. 1 dated November 1, 2004, to the No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern Transmission dated February 23, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/04) | 10.30 | ||||||
10.60
|
Amendment No. 1 dated November 1, 2004, to the Firm Transportation Service Agreement (Rate Schedule FT-1) between Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/04) | 10.33 | ||||||
10.61
|
Firm Transportation Service Agreement (Rate Schedule FTS) between Utilities and Columbia Gas Transmission dated November 1, 2004 | Utilities | Form 10-K (9/30/04) | 10.34 | ||||||
10.62
|
Purchase and Sale Agreement by and between Southern Union Company, as Seller, and UGI Corporation, as Buyer, dated as of January 26, 2006 (See Exhibit No. 10.64) | UGI | Form 8-K (1/26/06) | 10.1 | ||||||
10.63
|
Employee Agreement by and between Southern Union Company and UGI Corporation dated as of January 26, 2006 (See Exhibit No. 10.64) | UGI | Form 8-K (1/26/06) | 10.2 | ||||||
10.64
|
First Amendment Agreement, dated August 24, 2006, by and between Southern Union Company, as Seller, and UGI Corporation, as Buyer | Utilities | Form 8-K (8/24/06) | 10.2 | ||||||
10.65
|
Tax Consolidation Agreement, dated June 18, 2004, entered into by UGI Bordeaux Holding and its Subsidiaries named therein | UGI | Form 10-Q (6/30/04) | 10.8 | ||||||
79
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
10.65(a)
|
Amendment No. 1 dated as of June 24, 2004, to Tax Consolidation Agreement, dated June 18, 2004, as amended, entered into by UGI Bordeaux Holding and its Subsidiaries named therein | UGI | Form 10-Q (12/31/05) | 10.5 | ||||||
10.65(b)
|
Amendment No. 2 dated as of December 7, 2005 to Tax Consolidation Agreement, dated June 18, 2004, as amended, entered into by UGI Bordeaux Holding and its Subsidiaries named therein | UGI | Form 10-Q (12/31/05) | 10.6 | ||||||
10.66**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees effective December 6, 2005 | UGI | Form 10-K (9/30/06) | 10.66 | ||||||
10.66(a)**
|
UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees Performance Unit Grant Letter dated as of January 1, 2006 | UGI | Form 10-K (9/30/06) | 10.66 | (a) | |||||
10.67
|
Senior Facilities Agreement dated December 7, 2005 by and among AGZ Holding, as Borrower and Guarantor, Antargaz, as Borrower and Guarantor, Calyon, as Mandated Lead Arranger, Facility Agent and Security Agent and the Financial Institutions named therein | UGI | Form 10-Q (12/31/05) | 10.1 | ||||||
10.68
|
Pledge of Financial Instruments Account relating to Financial Instruments held by AGZ Holding in Antargaz, dated December 7, 2005, by and among AGZ Holding, as Pledgor, Calyon, as Security Agent, and the Lenders | UGI | Form 10-Q (12/31/05) | 10.2 | ||||||
10.69
|
Pledge of Financial Instruments Account relating to Financial Instruments held by Antargaz in certain subsidiary companies, dated December 7, 2005, by and among Antargaz, as Pledgor, Calyon, as Security Agent, and the Revolving Lenders | UGI | Form 10-Q (12/31/05) | 10.3 | ||||||
10.70
|
Letter of Undertakings dated December 7, 2005, by UGI Bordeaux Holding to AGZ Holding, the Parent of Antargaz, and Calyon, the Facility Agent, acting on behalf of the Lenders, (as defined within the Senior Facilities Agreement) | UGI | Form 10-Q (12/31/05) | 10.4 | ||||||
80
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
10.71
|
Seller’s Guarantee dated February 16, 2001 among Elf Antar France, Elf Aquitaine and AGZ Holding | UGI | Form 10-Q (3/31/04) | 10.5 | ||||||
10.72
|
Security Agreement for the Assignment of Receivables dated as of December 7, 2005 by and among AGZ Holding, as Assignor, Calyon, as Security Agent, and the Lenders named therein | UGI | Form 10-Q (12/31/05) | 10.7 | ||||||
10.73
|
Security Agreement for the Assignment of Receivables dated as of December 7, 2005 by and among Antargaz, as Assignor, Calyon, as Security Agent, and the Lenders named therein | UGI | Form 10-Q (12/31/05) | 10.8 | ||||||
10.74
|
Guarantee Agreement, dated July 26, 2006, between UGI Corporation, as Guarantor, and Raiffeisen Zentralbank Osterreich Aktiengesellschaft (“RZB”), as Beneficiary, relating to the Multi-Currency Working Capital Facility dated July 26, 2006 between Zentraleuropa LPG Holding GmbH (“ZLH”) and RZB | UGI | Form 10-Q (6/30/06) | 10.5 | ||||||
10.75
|
Guarantee Agreement, dated July 26, 2006, between UGI Corporation, as Guarantor, and RZB, as Beneficiary, relating to the Working Capital Facility dated July 26, 2006 between Flaga GmbH and RZB | UGI | Form 10-Q (6/30/06) | 10.6 | ||||||
10.76
|
Guarantee Agreement, dated July 26, 2006, between UGI Corporation, as Guarantor, and RZB, as Beneficiary, relating to the Term Loan Agreement dated July 26, 2006 between Flaga GmbH and RZB | UGI | Form 10-Q (6/30/06) | 10.7 | ||||||
10.77
|
Term Loan Agreement, dated July 26, 2006, between Flaga GmbH, as Borrower, and RZB, as Lender | UGI | Form 10-Q (6/30/06) | 10.8 | ||||||
10.78
|
Working Capital Facility Agreement, dated July 26, 2006, between Flaga GmbH, as Borrower, and RZB, as Lender | UGI | Form 10-Q (6/30/06) | 10.9 | ||||||
10.79
|
Multi-Currency Working Capital Facility Agreement, dated July 26, 2006, between ZLH, as Borrower, and RZB, as Lender | UGI | Form 10-Q (6/30/06) | 10.10 | ||||||
81
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
10.80
|
Assignment and Assumption Agreement, dated August 24, 2006, by and between UGI Corporation, as Assignor, and UGI Penn Natural Gas, Inc., as Assignee | Utilities | Form 8-K (8/24/06) | 10.1 | ||||||
10.81
|
[Intentionally Omitted] | |||||||||
10.82
|
Assignment and Assumption Agreement, dated August 24, 2006, by and between UGI Corporation, as Assignor, and UGI Utilities, Inc., as Assignee with respect to the Southern Union Company Pension | Utilities | Form 8-K (8/24/06) | 10.3 | ||||||
10.83
|
Service Agreement (Rate FSS) dated August 16, 2004 between Columbia Gas Transmission Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.4 | ||||||
10.84
|
Service Agreement (Rate SST) dated August 16, 2004 between Columbia Gas Transmission Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.5 | ||||||
10.85
|
Firm Transportation Service Agreement (Rate FT) dated February 1, 1992 between Transcontinental Gas Pipe Line Corporation and PG Energy (as successor to Pennsylvania Gas and Water Company) | Utilities | Form 8-K (8/24/06) | 10.6 | ||||||
10.86
|
Firm Transportation Service Agreement (Rate FT) dated July 10, 1997 between Transcontinental Gas Pipe Line Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.7 | ||||||
10.87
|
Firm Storage and Delivery Service Agreement (Rate GSS) dated July 1, 1996 between Transcontinental Gas Pipe Line Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.8 | ||||||
10.88**
|
AmeriGas Propane, Inc. Non-Qualified Deferred Compensation Plan effective February 1, 2007 | AmeriGas Partners, L.P. | Form 10-Q (3/31/07) |
10.1 | ||||||
10.89**
|
Description of oral employment at-will arrangement with Peter Kelly, Vice President – Finance and CFO | UGI | Form 8-K (6/21/07) | 10.1 | ||||||
82
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
*10.90
|
Extension of Guarantee Agreement dated July 26, 2006, between UGI Corporation, as Guarantor, and Raiffeisen Zentralbank Osterreich Aktiengesellschaft (“RZB”), as Beneficiary, relating to the extension of the Working Capital Facility Agreement dated July 26, 2006, between RZB and Flaga GmbH | |||||||||
10.91
|
Multi-Currency Facility Offer dated May 21, 2007 between Zentraleuropa LPG Holding GmbH and Raiffeisen Zentralbank Österreich Akteingesellschaft | UGI | Form 10-Q (6/30/07) |
10.1 | ||||||
10.92
|
Guarantee Agreement, dated May 21, 2007, between UGI Corporation, as Guarantor, and Raiffeisen Zentralbank Osterreich Aktiengesellschaft, as Beneficiary, relating to the Multi-Currency Working Capital Facility dated May 21, 2007 between Zentraleuropa LPG Holding GmbH and RZB | UGI | Form 10-Q (6/30/07) |
10.2 | ||||||
14
|
Code of Ethics for principal executive, financial and accounting officers | UGI | Form 10-K (9/30/03) | 14 | ||||||
*21
|
Subsidiaries of the Registrant | |||||||||
*23
|
Consent of PricewaterhouseCoopers LLP | |||||||||
*31.1
|
Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2007 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||||
*31.2
|
Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2007 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||||
83
Table of Contents
Incorporation by Reference
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||
*32
|
Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2007, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |||||||||
| * | Filed herewith. |
|
| ** | As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or
arrangement. |
84
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto
duly authorized.
| UGI CORPORATION |
||||
| Date: November 29, 2007 | By: | /s/ Peter Kelly | ||
| Peter Kelly | ||||
| Vice President - Finance | ||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been
signed below on November 27, 2007, by the following persons on behalf of the Registrant in the
capacities indicated.
| Signature | Title | |||
/s/ Lon R. Greenberg
|
Chairman and Chief Executive Officer (Principal Executive Officer) and Director | |||
/s/ John L. Walsh
|
President and Chief Operating Officer (Principal Operating Officer) and Director | |||
/s/ Peter Kelly
|
Vice President — Finance and Chief Financial Officer (Principal Financial Officer) | |||
/s/ Michael J. Cuzzolina
|
Vice President – Accounting and Financial Control and Chief Risk Officer (Principal Accounting Officer) | |||
/s/ Stephen D. Ban
|
Director | |||
/s/ Richard C. Gozon
|
Director |
85
Table of Contents
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been
signed below on November 27, 2007, by the following persons on behalf of the Registrant in the
capacities indicated.
| Signature | Title | |||
/s/ Ernest E. Jones
|
Director | |||
/s/ Anne Pol
|
Director | |||
/s/ Marvin O. Schlanger
|
Director | |||
/s/ James W. Stratton
|
Director | |||
/s/ Roger B. Vincent
|
Director |
86
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2007
F-1
Table of Contents
UGI CORPORATION
INDEX
TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULES
SCHEDULES
| Pages | ||
| F-3 | ||
Financial Statements: |
||
| F-4 to F-5 | ||
| F-6 to F-7 | ||
| F-8 | ||
| F-9 | ||
| F-10 | ||
| F-11 to F-40 | ||
Financial
Statement Schedules: |
||
For the years ended September 30, 2007, 2006 and 2005: |
||
| S-1 to S-3 | ||
| S-4 to S-5 |
Annual Report on Form 10-K/A
An Annual report on Form 10-K/A for the UGI Utilities, Inc., AmeriGas Propane, Inc. and
UGI HVAC Enterprises, Inc. savings plans will be filed by amendment within the time period
specified by Rule 15d-21(b).
We have omitted all other financial statement schedules because the required information is
either (1) not present; (2) not present in amounts sufficient to require submission of the
schedule; or (3) included elsewhere in the financial statements or related notes.
F-2
Table of Contents
Report of Management
Financial Statements
The Company’s consolidated financial statements and other financial information contained in
this Annual Report are prepared by management, which is responsible for their fairness,
integrity and objectivity. The consolidated financial statements and related information
were prepared in accordance with accounting principles generally accepted in the United
States of America and include amounts that are based on management’s best judgments and
estimates.
The Audit Committee of the Board of Directors is composed of three members, none of
whom is an employee of the Company. This Committee is responsible for overseeing the
financial reporting process and the adequacy of internal control and for monitoring the
independence and performance of the Company’s independent registered public accounting firm
and internal auditors. The Committee is also responsible for maintaining direct channels of
communication among the Board of Directors, management, and both the independent registered
public accounting firm and internal auditors.
PricewaterhouseCoopers LLP, our independent registered public accounting firm, is
engaged to perform audits of our consolidated financial statements. These audits are
performed in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Our independent registered public accounting firm was given unrestricted
access to all financial records and related data, including minutes of all meetings of the
Board of Directors and committees of the Board. The Company believes that all
representations made to the independent registered public accounting firm during their
audits were valid and appropriate.
Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over
financial reporting for the Company. In order to evaluate the effectiveness of internal
control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of
2002, management has conducted an assessment, including testing, of the Company’s internal
control over financial reporting, using the criteria in Internal Control — Integrated
Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission
(“COSO Framework”).
Internal control over financial reporting refers to the process designed by, and under
the supervision of, our Chief Executive Officer and Chief Financial Officer, to provide
reasonable, but not absolute, assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with accounting
principles generally accepted in the United States of America and includes policies and
procedures that, among other things, provide reasonable assurance that assets are
safeguarded and that transactions are executed in accordance with management’s authorization
and are properly recorded to permit the preparation of reliable financial information.
Because of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become inadequate due to changing
conditions, or the degree of compliance with the policies or procedures may deteriorate.
Based on its assessment, management has concluded that the Company maintained effective
internal control over financial reporting as of September 30, 2007, based on the COSO
Framework. In our 2006 Management’s Report on Internal Control over Financial Reporting, we
excluded the PG Energy business from our assessment of internal control over financial
reporting as of September 30, 2006 because it was acquired by a wholly owned subsidiary of the Company in a purchase
business combination on August 24, 2006. The PG Energy business total assets represented approximately 13% of total consolidated assets and
its total revenues represented less than 1% of total consolidated revenues as of and for the year ended
September 30, 2006. Such exclusion is permitted based upon guidance of the U.S. Securities
and Exchange Commission.
Lon R. Greenberg
Chief Executive Officer
Chief Executive Officer
Peter Kelly
Chief Financial Officer
Chief Financial Officer
Michael J. Cuzzolina
Chief Accounting Officer
Chief Accounting Officer
F-3
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of UGI Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated
statements of income, stockholders’ equity and cash flows present fairly, in all material respects,
the financial position of UGI Corporation and its subsidiaries at September 30, 2007 and 2006, and
the results of their operations and their cash flows for each of the three years in the period
ended September 30, 2007 in conformity with accounting principles generally accepted in the United
States of America. In addition, in our opinion, the financial statement schedules listed in the
index appearing under Item 15 (a)(2) present fairly, in all material respects, the information set
forth therein when read in conjunction with the related consolidated financial statements. Also in
our opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of September 30, 2007 based on criteria established in Internal Control -
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO). The Company’s management is responsible for these financial statements and financial
statement schedules, for maintaining effective internal control over financial reporting, and for
its assessment of the effectiveness of internal control over financial reporting included in
Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express
opinions on these financial statements, on the financial statement schedules and the Company’s
internal control based on our integrated audits. We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement and whether effective internal control over
financial reporting was maintained in all material respects. Our audits of the financial
statements included examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and significant estimates made
by management, and evaluating the overall financial statement presentation. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and testing and evaluating
the design and operating effectiveness of internal control based on the assessed risk. Our audits
also included performing such other procedures as we considered necessary in the circumstances. We
believe that our audits provide a reasonable basis for our opinions.
As discussed in Notes 1 and 5 to the consolidated financial statements, the Company changed the
manner in which it accounts for defined benefit pension and other postretirement plans as of
September 30, 2007 and, as discussed in Notes 1 and 8, the Company changed the manner in which it
accounts for equity-based compensation as of October 1, 2005.
A company’s internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
company’s internal control over financial reporting includes those policies and procedures that (i)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (iii) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
F-4
Table of Contents
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In the 2006 Management’s Report on Internal Control over Financial Reporting, management excluded
the PG Energy business from its assessment of internal control over financial reporting as of
September 30, 2006 because it was acquired by a wholly owned
subsidiary of the Company in a purchase business combination on
August 24, 2006. We had also excluded the PG Energy business from our audit of internal control
over financial reporting as of September 30, 2006. The PG Energy business total assets represented approximately
13% of total consolidated assets and its total revenues represented less than 1% of total consolidated revenues as of and for the year ended
September 30, 2006.
/s/ PricewaterhouseCoopers LLP
November 29, 2007
Philadelphia, Pennsylvania
November 29, 2007
Philadelphia, Pennsylvania
F-5
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
(Millions of dollars)
| September 30, | ||||||||
| 2007 | 2006 | |||||||
ASSETS |
||||||||
Current Assets |
||||||||
Cash and cash equivalents |
$ | 251.8 | $ | 186.2 | ||||
Restricted cash |
12.8 | 14.2 | ||||||
Accounts receivable (less allowances for doubtful accounts of
$37.7 and $38.0, respectively) |
459.8 | 387.2 | ||||||
Accrued utility revenues |
17.9 | 16.6 | ||||||
Inventories |
359.5 | 340.4 | ||||||
Deferred income taxes |
9.6 | 55.9 | ||||||
Income taxes recoverable |
7.8 | 11.0 | ||||||
Utility regulatory assets |
14.8 | — | ||||||
Derivative financial instruments |
20.3 | 5.8 | ||||||
Prepaid expenses and other current assets |
19.3 | 23.3 | ||||||
Total current assets |
1,173.6 | 1,040.6 | ||||||
Property, Plant and Equipment |
||||||||
AmeriGas Propane |
1,321.6 | 1,211.8 | ||||||
International Propane |
724.5 | 588.0 | ||||||
UGI Utilities |
1,620.0 | 1,553.9 | ||||||
Other |
118.5 | 107.6 | ||||||
| 3,784.6 | 3,461.3 | |||||||
Accumulated depreciation and amortization |
(1,387.2 | ) | (1,246.6 | ) | ||||
Net property, plant, and equipment |
2,397.4 | 2,214.7 | ||||||
Other Assets |
||||||||
Goodwill |
1,498.8 | 1,418.2 | ||||||
Intangible assets (less accumulated amortization of $84.2 and $62.8, respectively) |
173.1 | 163.3 | ||||||
Utility regulatory assets |
89.0 | 72.9 | ||||||
Investment in equity investees |
63.9 | 58.2 | ||||||
Other assets |
106.9 | 112.6 | ||||||
Total assets |
$ | 5,502.7 | $ | 5,080.5 | ||||
See accompanying notes to consolidated financial statements.
F-6
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
| September 30, | ||||||||
| 2007 | 2006 | |||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY |
||||||||
Current Liabilities |
||||||||
Current maturities of long-term debt |
$ | 14.7 | $ | 31.9 | ||||
UGI Utilities bank loans |
190.0 | 216.0 | ||||||
Other bank loans |
8.9 | 9.4 | ||||||
Accounts payable |
420.8 | 373.0 | ||||||
Employee compensation and benefits accrued |
79.4 | 75.4 | ||||||
Dividends and interest accrued |
38.5 | 31.1 | ||||||
Deposits and advances |
157.2 | 145.0 | ||||||
Derivative financial instruments |
14.3 | 27.6 | ||||||
Deferred income taxes |
19.0 | — | ||||||
Other current liabilities |
114.7 | 117.2 | ||||||
Total current liabilities |
1,057.5 | 1,026.6 | ||||||
Debt and Other Liabilities |
||||||||
Long-term debt |
2,038.8 | 1,965.0 | ||||||
Deferred income taxes |
506.4 | 491.5 | ||||||
Deferred investment tax credits |
6.4 | 6.8 | ||||||
Other noncurrent liabilities |
379.5 | 351.5 | ||||||
Total liabilities |
3,988.6 | 3,841.4 | ||||||
Commitments and contingencies (note 10) |
||||||||
Minority interests, principally in AmeriGas Partners |
192.2 | 139.5 | ||||||
Common Stockholders’ Equity |
||||||||
Common Stock, without par value (authorized - 300,000,000 shares;
issued - 115,152,994 shares) |
831.6 | 807.5 | ||||||
Retained earnings |
497.5 | 370.0 | ||||||
Accumulated other comprehensive income (loss) |
57.7 | (3.8 | ) | |||||
| 1,386.8 | 1,173.7 | |||||||
Treasury stock, at cost |
(64.9 | ) | (74.1 | ) | ||||
Total common stockholders’ equity |
1,321.9 | 1,099.6 | ||||||
Total liabilities and stockholders’ equity |
$ | 5,502.7 | $ | 5,080.5 | ||||
F-7
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
| Year Ended September 30, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
Revenues |
||||||||||||
AmeriGas Propane |
$ | 2,277.4 | $ | 2,119.3 | $ | 1,963.3 | ||||||
International Propane |
800.4 | 945.5 | 943.9 | |||||||||
UGI Utilities |
1,166.8 | 822.0 | 681.2 | |||||||||
Energy Services and other |
1,232.3 | 1,334.2 | 1,300.3 | |||||||||
| 5,476.9 | 5,221.0 | 4,888.7 | ||||||||||
Costs and Expenses |
||||||||||||
Cost of sales |
3,730.8 | 3,657.9 | 3,306.0 | |||||||||
Operating and administrative expenses |
1,055.8 | 969.2 | 966.6 | |||||||||
Utility taxes other than income taxes |
17.7 | 14.3 | 13.4 | |||||||||
Depreciation and amortization |
169.2 | 148.7 | 146.4 | |||||||||
Other income, net |
(77.9 | ) | (36.8 | ) | (46.7 | ) | ||||||
| 4,895.6 | 4,753.3 | 4,385.7 | ||||||||||
Operating Income |
581.3 | 467.7 | 503.0 | |||||||||
Loss from equity investees |
(3.8 | ) | (2.2 | ) | (2.6 | ) | ||||||
Loss on extinguishments of debt |
— | (18.5 | ) | (33.6 | ) | |||||||
Interest expense |
(139.6 | ) | (123.6 | ) | (130.2 | ) | ||||||
Income before Income Taxes and
Minority Interests |
437.9 | 323.4 | 336.6 | |||||||||
Income taxes |
(126.7 | ) | (98.5 | ) | (119.2 | ) | ||||||
Minority interests, principally in AmeriGas Partners |
(106.9 | ) | (48.7 | ) | (29.9 | ) | ||||||
Net Income |
$ | 204.3 | $ | 176.2 | $ | 187.5 | ||||||
Earnings Per Common Share: |
||||||||||||
Basic |
$ | 1.92 | $ | 1.67 | $ | 1.81 | ||||||
Diluted |
$ | 1.89 | $ | 1.65 | $ | 1.77 | ||||||
Average Common Shares Outstanding (millions): |
||||||||||||
Basic |
106.451 | 105.455 | 103.877 | |||||||||
Diluted |
107.941 | 106.727 | 105.723 | |||||||||
See accompanying notes to consolidated financial statements.
F-8
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
| Year Ended September 30, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||||||
Net income |
$ | 204.3 | $ | 176.2 | $ | 187.5 | ||||||
Reconcile to net cash provided by operating activities: |
||||||||||||
Depreciation and amortization |
169.2 | 148.7 | 146.4 | |||||||||
Gain on sale of Arizona storage facility |
(46.1 | ) | — | |||||||||
Minority interests principally in AmeriGas Partners |
106.9 | 48.7 | 29.9 | |||||||||
Deferred income taxes, net |
27.1 | 7.4 | 12.1 | |||||||||
Provision for uncollectible accounts |
26.7 | 25.0 | 25.1 | |||||||||
Loss on extinguishments of debt |
— | 18.5 | 33.6 | |||||||||
Tax benefit on exercise of stock options |
— | — | 10.2 | |||||||||
Stock-based compensation expense |
9.1 | 6.9 | — | |||||||||
Net change in settled accumulated other comprehensive income |
21.5 | (37.1 | ) | (3.8 | ) | |||||||
Other, net |
(0.3 | ) | 10.3 | (14.5 | ) | |||||||
Net change in: |
||||||||||||
Accounts receivable and accrued utility revenues |
(80.5 | ) | 34.8 | (81.5 | ) | |||||||
Inventories |
(9.1 | ) | (31.9 | ) | (29.4 | ) | ||||||
Deferred fuel costs |
(25.7 | ) | (17.9 | ) | 9.5 | |||||||
Accounts payable |
30.3 | (61.1 | ) | 70.0 | ||||||||
Other current assets and liabilities |
22.8 | (49.1 | ) | 42.6 | ||||||||
Net cash provided by operating activities |
456.2 | 279.4 | 437.7 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||||||
Expenditures for property, plant and equipment |
(223.1 | ) | (191.7 | ) | (158.4 | ) | ||||||
Acquisitions of businesses, net of cash acquired |
(78.8 | ) | (590.4 | ) | (33.3 | ) | ||||||
Net proceeds from disposals of assets |
3.2 | 8.8 | 16.7 | |||||||||
Proceeds from sale of Arizona storage facility |
49.0 | — | — | |||||||||
PG Energy Acquisition working capital adjustment |
23.7 | — | — | |||||||||
Net proceeds from sale of Energy Ventures |
— | 13.3 | — | |||||||||
Investment in ZLH |
— | (10.1 | ) | — | ||||||||
Decrease (increase) in short-term investments |
0.6 | 69.4 | (20.0 | ) | ||||||||
Decrease (increase) in restricted cash |
1.4 | (9.3 | ) | (4.8 | ) | |||||||
Other, net |
0.2 | 2.5 | 3.5 | |||||||||
Net cash used by investing activities |
(223.8 | ) | (707.5 | ) | (196.3 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||||||
Dividends on UGI Common Stock |
(76.8 | ) | (72.5 | ) | (67.4 | ) | ||||||
Distributions on AmeriGas Partners publicly held Common Units |
(85.0 | ) | (73.6 | ) | (66.6 | ) | ||||||
Issuances of debt including bank loans with maturities greater than three months |
20.0 | 1,145.4 | 576.0 | |||||||||
Repayments of debt including bank loans with maturities greater than three months |
(30.6 | ) | (918.3 | ) | (544.4 | ) | ||||||
(Decrease) increase in UGI Utilities bank loans with maturities of three months or less |
(26.0 | ) | 204.8 | (49.7 | ) | |||||||
Other bank loans (decrease) increase |
(1.6 | ) | 2.2 | (0.3 | ) | |||||||
Redemption of UGI Utilities preferred shares subject to mandatory redemption |
— | — | (20.0 | ) | ||||||||
Minority interest activity |
1.4 | — | — | |||||||||
Issuances of AmeriGas Partners Common Units |
— | — | 72.7 | |||||||||
Excess tax benefits from equity-based payment arrangements |
3.7 | 0.9 | — | |||||||||
Issuances of UGI Common Stock |
16.4 | 10.8 | 27.1 | |||||||||
Net cash (used) provided by financing activities |
(178.5 | ) | 299.7 | (72.6 | ) | |||||||
EFFECT OF EXCHANGE RATE CHANGES ON CASH |
11.7 | 4.5 | (8.3 | ) | ||||||||
Cash and cash equivalents increase (decrease) |
$ | 65.6 | $ | (123.9 | ) | $ | 160.5 | |||||
Cash and cash equivalents: |
||||||||||||
End of year |
$ | 251.8 | $ | 186.2 | $ | 310.1 | ||||||
Beginning of year |
186.2 | 310.1 | 149.6 | |||||||||
Increase (decrease) |
$ | 65.6 | $ | (123.9 | ) | $ | 160.5 | |||||
See accompanying notes to consolidated financial statements.
F-9
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Millions of dollars, except per share amounts)
(Millions of dollars, except per share amounts)
| Accumulated | Notes | |||||||||||||||||||||||
| Other | Receivable | |||||||||||||||||||||||
| Common | Retained | Comprehensive | From | Treasury | ||||||||||||||||||||
| Stock | Earnings | Income (Loss) | Employees | Stock | Total | |||||||||||||||||||
Balance September 30, 2004 |
$ | 762.8 | $ | 146.2 | $ | 22.6 | $ | (0.2 | ) | $ | (97.3 | ) | $ | 834.1 | ||||||||||
Net income |
187.5 | 187.5 | ||||||||||||||||||||||
Net gain on derivative instruments (net of tax
of $7.9) |
12.9 | 12.9 | ||||||||||||||||||||||
Reclassification of net gains on derivative
instruments (net of tax of $2.1) |
(2.7 | ) | (2.7 | ) | ||||||||||||||||||||
Foreign currency translation adjustments
(net of tax of $6.5) |
(16.3 | ) | (16.3 | ) | ||||||||||||||||||||
Comprehensive income (loss) |
187.5 | (6.1 | ) | 181.4 | ||||||||||||||||||||
Cash dividends on Common Stock
($0.65 per share) |
(67.4 | ) | (67.4 | ) | ||||||||||||||||||||
Common Stock issued: |
||||||||||||||||||||||||
Employee and director plans |
17.2 | 17.7 | 34.9 | |||||||||||||||||||||
Dividend reinvestment plan |
1.6 | 0.8 | 2.4 | |||||||||||||||||||||
Net gain in connection with issuances of
units by AmeriGas Partners (net of tax of $16.0) |
12.0 | 12.0 | ||||||||||||||||||||||
Payments on notes receivable from employees |
0.2 | 0.2 | ||||||||||||||||||||||
Balance September 30, 2005 |
793.6 | 266.3 | 16.5 | — | (78.8 | ) | 997.6 | |||||||||||||||||
Net income |
176.2 | 176.2 | ||||||||||||||||||||||
Net loss on derivative instruments (net of tax
of $43.7) |
(63.7 | ) | (63.7 | ) | ||||||||||||||||||||
Reclassification of net losses on derivative
instruments (net of tax of $13.2) |
17.5 | 17.5 | ||||||||||||||||||||||
Foreign currency translation adjustments
(net of tax of $8.1) |
25.9 | 25.9 | ||||||||||||||||||||||
Comprehensive income (loss) |
176.2 | (20.3 | ) | 155.9 | ||||||||||||||||||||
Cash dividends on Common Stock
($0.69 per share) |
(72.5 | ) | (72.5 | ) | ||||||||||||||||||||
Common Stock issued: |
||||||||||||||||||||||||
Employee and director plans |
4.7 | 3.8 | 8.5 | |||||||||||||||||||||
Dividend reinvestment plan |
1.4 | 0.9 | 2.3 | |||||||||||||||||||||
Excess tax benefits realized on equity-based
compensation |
0.9 | 0.9 | ||||||||||||||||||||||
Stock-based compensation expense |
6.9 | 6.9 | ||||||||||||||||||||||
Balance September 30, 2006 |
807.5 | 370.0 | (3.8 | ) | — | (74.1 | ) | 1,099.6 | ||||||||||||||||
Net income |
204.3 | 204.3 | ||||||||||||||||||||||
Net loss on derivative instruments (net of tax
of $7.6) |
(11.1 | ) | (11.1 | ) | ||||||||||||||||||||
Reclassification of net losses on derivative
instruments (net of tax of $20.8) |
30.1 | 30.1 | ||||||||||||||||||||||
Foreign currency translation adjustments
(net of tax of $9.4) |
53.7 | 53.7 | ||||||||||||||||||||||
Comprehensive income |
204.3 | 72.7 | 277.0 | |||||||||||||||||||||
Adjustment to initially apply SFAS 158
(net of tax of $7.7) |
(11.2 | ) | (11.2 | ) | ||||||||||||||||||||
Cash dividends on Common Stock
($0.723 per share) |
(76.8 | ) | (76.8 | ) | ||||||||||||||||||||
Common Stock issued: |
||||||||||||||||||||||||
Employee and director plans |
10.2 | 8.5 | 18.7 | |||||||||||||||||||||
Dividend reinvestment plan |
1.6 | 0.7 | 2.3 | |||||||||||||||||||||
Excess tax benefits realized on equity-based |
||||||||||||||||||||||||
compensation |
3.7 | 3.7 | ||||||||||||||||||||||
Stock-based compensation expense |
8.6 | 8.6 | ||||||||||||||||||||||
Balance September 30, 2007 |
$ | 831.6 | $ | 497.5 | $ | 57.7 | $ | — | $ | (64.9 | ) | $ | 1,321.9 | |||||||||||
See accompanying notes to consolidated financial statements.
F-10
Table of Contents
UGI
Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 1 — Organization and Significant Accounting Policies
Organization. UGI Corporation (“UGI”) is a holding company that, through subsidiaries and
joint-venture affiliates, distributes and markets energy products and related services. In
the United States, we own and operate (1) retail propane distribution businesses; (2)
natural gas and electric distribution utilities; (3) electricity generation facilities; and
(4) energy marketing and related businesses. Internationally, we distribute liquefied
petroleum gases (“LPG”) in France, Central and Eastern Europe and China. We refer to UGI and
its consolidated subsidiaries collectively as “the Company” or “we.”
We conduct a national propane distribution business through AmeriGas Partners, L.P.
(“AmeriGas Partners”) and its principal operating subsidiaries AmeriGas Propane, L.P.
(“AmeriGas OLP”) and AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (“Eagle OLP”).
AmeriGas Partners, AmeriGas OLP and Eagle OLP are Delaware limited partnerships. UGI’s
wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as
the general partner of AmeriGas Partners and AmeriGas OLP. AmeriGas OLP and Eagle OLP
(collectively referred to as “the Operating Partnerships”) comprise the largest retail
propane distribution business in the United States serving residential, commercial,
industrial, motor fuel and agricultural customers from locations in 46 states. We refer to
AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner
and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30,
2007, the General Partner and its wholly owned subsidiary Petrolane Incorporated
(“Petrolane”) collectively held a 1% general partner interest and 42.9% limited partner
interest in AmeriGas Partners, and an effective 44.5% ownership interest in AmeriGas OLP and
Eagle OLP. Our limited partnership interest in AmeriGas Partners comprises 24,691,209
AmeriGas Partners Common Units (“Common Units”). The remaining 56.1% interest in AmeriGas
Partners comprises 32,297,493 publicly held Common Units representing limited partner
interests.
The Partnership has no employees. Employees of the General Partner conduct, direct and
manage the activities of AmeriGas Partners and AmeriGas OLP. The General Partner also
provides management and administrative services to AmeriGas Eagle Holdings, Inc., the
general partner of Eagle OLP, under a management services agreement. The General Partner is
reimbursed monthly for all direct and indirect expenses it incurs on behalf of the
Partnership including all General Partner employee compensation costs and a portion of UGI
employee compensation and administrative costs. Although the Partnership’s operating income
comprises a significant portion of our consolidated operating income, the Partnership’s
impact on our consolidated net income is considerably less due to the Partnership’s
significant minority interest.
Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries
(1) conducts an LPG distribution business in France; (2) conducts LPG distribution
businesses and participates in an LPG joint-venture business in central and eastern Europe
(collectively, “Flaga”); and (3) participates in an LPG joint-venture business in the
Nantong region of China. Our LPG distribution business in France is conducted through
Antargaz, a subsidiary of AGZ Holding (“AGZ”), and its operating subsidiaries (collectively,
“Antargaz”). We refer to our foreign operations collectively as “International Propane.”
During fiscal 2006, we formed a Dutch private limited liability company, UGI International
Holdings, B.V., to hold our interests in Antargaz and Flaga.
Our natural gas and electric distribution utility businesses are conducted through our
wholly owned subsidiary, UGI Utilities, Inc. and its subsidiary, UGI Penn Natural Gas, Inc.
(“UGIPNG”). UGI Utilities, Inc. owns and operates (1) natural gas distribution utilities in
eastern and northeastern Pennsylvania (“UGI Gas” and “PNG Gas,” respectively) and (2) an
electric distribution utility in northeastern Pennsylvania (“Electric Utility”). On August
24, 2006, UGI Utilities, Inc., through UGIPNG, acquired the natural gas business of PG
Energy, an operating division of Southern Union Company (the “PG Energy Acquisition”) (see
Note 2). UGI Gas and PNG Gas (collectively, “Gas Utility”) and Electric Utility are subject
to regulation by the Pennsylvania Public Utility Commission (“PUC”). The term “UGI
Utilities” is used as an abbreviated reference to UGI Utilities, Inc. or UGI Utilities,
Inc. and its subsidiaries, including UGIPNG.
Through other subsidiaries, Enterprises also conducts an energy marketing business
primarily in the Eastern United States (collectively, “Energy Services”). Energy Services’
wholly owned subsidiary, UGI Development Company (“UGID”), owns and operates a 48-megawatt
coal-fired electric generation station located in northeastern Pennsylvania and owns an
approximate 6% interest in a 1,711-megawatt coal-fired electric generation station located
in western Pennsylvania. In addition, Energy Services’ wholly owned subsidiary UGI Asset
Management, Inc., through its subsidiary Atlantic Energy, Inc. (collectively, “Asset
Management”) owns a propane storage terminal located in Chesapeake, Virginia. Through other
Enterprises’ and UGI Utilities’ subsidiaries, we own and operate heating, ventilation,
air-conditioning, refrigeration and electrical contracting services businesses in the Middle
Atlantic states (“HVAC/R”).
F-11
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
UGI was incorporated in Pennsylvania in 1991. UGI is a “holding company” under the
Public Utility Holding Company Act of 2005 (“PUHCA 2005”). PUHCA 2005 and the implementing
regulations of the Federal Energy Regulatory Commission (“FERC”) give FERC access to certain
holding company books and records and impose certain accounting, record-keeping, and
reporting requirements on holding companies. PUHCA 2005 also provides state utility
regulatory commissions with access to holding company books and records in certain
circumstances. Pursuant to a waiver granted in accordance with FERC’s regulations on the
basis of UGI’s status as a single-state holding company system, UGI is not subject to
certain of the accounting, record-keeping, and reporting requirements prescribed by FERC’s
regulations.
Consolidation Principles. The consolidated financial statements include the accounts of
UGI and its controlled subsidiary companies which, except for the Partnership, are majority
owned. We eliminate all significant intercompany accounts and transactions when we
consolidate. We report the public’s limited partner interests in the Partnership and other
parties’ interests in consolidated but less than 100% owned subsidiaries as minority
interests. Other entities in which we own 50% or less and in which we exercise significant
influence over operating and financial policies (“equity investees”) are accounted for by
the equity method and presented on a one-line basis. Entities in which we own less than 20%
are accounted for on the cost basis of accounting. Such cost basis investments totaled
$52.2 and $46.5 at September 30, 2007 and 2006 and are included in “Other Assets” in the
Consolidated Balance Sheets.
Loss from our equity investees was $3.8 in fiscal 2007, $2.2 in fiscal 2006 and
$2.6 in fiscal 2005. Undistributed net earnings of our equity investees included in
consolidated retained earnings were not material at September 30, 2007, 2006 or 2005.
Summarized financial information for our equity investments are not presented because they
are not material to our Consolidated Balance Sheets or Consolidated Statements of Income.
Gains resulting from issuances and sales of AmeriGas Partners’ Common Units to third parties
are recorded as increases to common stockholders’ equity with corresponding decreases to
minority interests in accordance with U.S. Securities and Exchange Commission (“SEC”) Staff
Accounting Bulletin No. 51, “Accounting for Sales of Common Stock by a Subsidiary” (“SAB
51”). These gains result when the public offering price of the AmeriGas Partners Common Units
exceeds the associated carrying amount of our investment in the Partnership on the date of
sale. We record deferred income tax liabilities associated with these gains (see
Note 14).
Reclassifications. We have reclassified certain prior-year balances to conform to the
current-year presentation.
Use of Estimates. We make estimates and assumptions when preparing financial statements in
conformity with accounting principles generally accepted in the United States of America.
These estimates and assumptions affect the reported amounts of assets and liabilities,
revenues and expenses, as well as the disclosure of contingent assets and liabilities.
Actual results could differ from these estimates.
Regulated Utility Operations. We account for the operations of Gas Utility and Electric
Utility in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71,
“Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). SFAS 71 requires us
to record the effects of rate regulation in the financial statements. SFAS 71 allows us to
defer expenses and revenues on the balance sheet as regulatory assets and liabilities when
it is probable that those expenses and revenue will be allowed in the ratemaking process in
a period different from the period in which they would have been reflected in the income
statement of an unregulated company. These deferred assets and liabilities are then flowed
through the income statement in the period in which the same amounts are included in rates
and recovered from or refunded to customers. As required by SFAS 71, we monitor our
regulatory and competitive environments to determine whether the recovery of our regulatory
assets continues to be probable. If we were to determine that recovery of these regulatory
assets is no longer probable, such assets would be written off against earnings. We believe
that SFAS 71 continues to apply to our regulated utility operations and that the recovery of
our regulatory assets is probable.
F-12
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Regulatory assets and liabilities associated with Gas Utility and Electric Utility
included in our Consolidated Balance Sheets at September 30 comprise the following:
| 2007 | 2006 | |||||||
Regulatory assets: |
||||||||
Income taxes recoverable |
$ | 72.0 | $ | 64.3 | ||||
Postretirement benefits |
4.9 | 5.4 | ||||||
Environmental costs |
8.3 | — | ||||||
Deferred fuel costs |
14.8 | — | ||||||
Other |
3.8 | 3.2 | ||||||
Total regulatory assets |
$ | 103.8 | $ | 72.9 | ||||
Regulatory liabilities: |
||||||||
Postretirement benefits |
$ | 7.5 | $ | 3.8 | ||||
Deferred fuel costs |
— | 12.2 | ||||||
Total regulatory liabilities |
$ | 7.5 | $ | 16.0 | ||||
UGI Utilities’ regulatory liabilities relating to postretirement benefits and
deferred fuel costs are included in “other noncurrent liabilities” and “other current
liabilities,” respectively, on the Consolidated Balance Sheets. UGI Utilities does not
recover a rate of return on its regulatory assets.
In an order entered on November 30, 2006, the PUC approved a settlement of a PNG Gas base
rate proceeding. The settlement authorized PNG Gas to increase base rates $12.5 annually,
or approximately 4%, effective December 2, 2006.
As a result of Pennsylvania’s Electricity Generation Customer Choice and Competition Act
that became effective January 1, 1997, all of Electric Utility’s customers are permitted to
acquire their electricity from entities other than Electric Utility. As of September 30,
2007, none of Electric Utility’s customers have chosen an alternative electricity generation
supplier. Electric Utility remains the provider of last resort (“POLR”) for its customers
that are not served by an alternate electric generation provider. The terms and conditions
under which Electric Utility provides POLR service, and rules governing the rates that may
be charged for such service, have been established in a series of PUC approved settlements,
the latest of which became effective June 23, 2006 (collectively, the “POLR Settlement”).
In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up to
certain limits through December 31, 2009. Consistent with the terms of the POLR Settlement,
Electric Utility’s POLR rates increased 4.5% on January 1, 2005 and 3% on January 1, 2006.
During fiscal 2007, Electric Utility increased its POLR rates effective January 1, 2007
which increased the average cost to a residential heating customer by approximately 35% over
such costs in effect during calendar 2006. New PUC default service regulations became
effective on September 15, 2007, but do not disturb Electric Utility’s POLR Settlement
through 2009. Under the default service regulations, Electric Utility will be required to
file a default service plan with the PUC in 2008 that will establish the terms and
conditions under which it will offer POLR service commencing 2010.
Derivative Instruments. SFAS No. 133, “Accounting for Derivative Instruments and
Hedging Activities” (“SFAS 133”), as amended, establishes accounting and reporting standards
for derivative instruments and for hedging activities. It requires that all derivative
instruments be recognized as either assets or liabilities and measured at fair value. The
accounting for changes in fair value depends upon the purpose of the derivative instrument
and whether it is designated and qualifies for hedge accounting. For a detailed description
of the derivative instruments we use, our objectives for using them, and related
supplemental information required by SFAS 133, see Note 11.
Consolidated Statements of Cash Flows. We define cash equivalents as highly liquid
investments with maturities of three months or less when purchased. We record cash
equivalents at cost plus accrued interest, which approximates market value. Restricted cash
represents those cash balances in our natural gas futures brokerage accounts which are
restricted from withdrawal.
We paid interest totaling $127.4 in fiscal 2007, $129.3 in fiscal 2006 and $130.6 in fiscal
2005. We paid income taxes totaling $93.5 in fiscal 2007, $142.6 in fiscal 2006 and $54.7
in fiscal 2005.
Revenue Recognition. We recognize revenues from the sale of propane and other LPG
principally as product is delivered to customers. We record UGI Utilities’ regulated
revenues for distribution service and related commodity charges provided to the end of each
month which includes an accrual for certain unbilled amounts based upon estimated usage. We
reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the
time they become effective. Energy Services records revenues when energy products are
delivered to customers. Revenue from the sale of appliances and equipment is recognized at
the time of sale or installation.
F-13
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
We present revenue-related taxes collected from customers and remitted to taxing
authorities, principally sales and use taxes, on a net basis. Electric Utility gross
receipts taxes are included in total revenues in accordance with regulatory practice.
Inventories. Our inventories are stated at the lower of cost or market. We determine cost
using an average cost method for natural gas, propane and other LPG, specific identification
for appliances and the first-in, first-out (“FIFO”) method for all other inventories.
Earnings Per Common Share. Basic earnings per share reflect the weighted-average number of
common shares outstanding. Diluted earnings per share include the effects of dilutive stock
options and common stock awards. In the
following table, we present shares used in computing basic and diluted earnings per share
for fiscal 2007, 2006 and 2005:
| 2007 | 2006 | 2005 | ||||||||||
(Millions of shares) |
||||||||||||
Average common shares outstanding
for basic computation |
106.451 | 105.455 | 103.877 | |||||||||
Incremental shares issuable for stock
options and common stock awards |
1.490 | 1.272 | 1.846 | |||||||||
Average common shares outstanding
for diluted computation |
107.941 | 106.727 | 105.723 | |||||||||
Income Taxes. AmeriGas Partners and the Operating Partnerships are not directly subject
to federal income taxes. Instead, their taxable income or loss is allocated to the
individual partners. We record income taxes on our share of (1) the Partnership’s current
taxable income or loss and (2) the differences between the book and tax basis of our
investment in the Partnership. The Operating Partnerships have subsidiaries which operate in
corporate form and are directly subject to federal income taxes.
Gas Utility and Electric Utility record deferred income taxes in the Consolidated
Statements of Income resulting from the use of accelerated tax depreciation methods based
upon amounts recognized for ratemaking purposes. They also record a deferred income tax
liability for tax benefits that are flowed through to ratepayers when temporary differences
originate and record a regulatory income tax asset for the probable increase in future
revenues that will result when the temporary differences reverse.
We are amortizing deferred investment tax credits related to UGI Utilities’ plant
additions over the service lives of the related property. UGI Utilities reduces its deferred
income tax liability for the future tax benefits that will occur when investment tax
credits, which are not taxable, are amortized. We also reduce the regulatory income tax
asset for the probable reduction in future revenues that will result when such deferred
investment tax credits amortize.
Property, Plant and Equipment and Related Depreciation. The amounts we assign to property,
plant and equipment of acquired businesses are based upon estimated fair value at date of
acquisition. When Gas Utility and Electric Utility retire depreciable utility plant and
equipment, we charge the original cost, net of removal costs and salvage value, to
accumulated depreciation for financial accounting purposes. When our other businesses retire
or dispose of plant and equipment, we eliminate the associated cost and accumulated
depreciation and recognize any resulting gain or loss in “Other income, net.”
We record depreciation expense over estimated economic useful lives. We record depreciation
expense for UGI Utilities’ plant and equipment on a straight-line method over the estimated
average remaining lives of the various classes of its depreciable property. Depreciation
expense as a percentage of the related average depreciable base for Gas Utility was 2.7% in
fiscal 2007, 2.5% in fiscal 2006, and 2.4% in fiscal 2005. Depreciation expense as a
percentage of the related average depreciable base for Electric Utility was 2.7% in fiscal
2007, 2.8% in fiscal 2006 and 2.9% in fiscal 2005. We compute depreciation expense on plant
and equipment associated with our LPG operations using the straight-line method over
estimated service lives generally ranging from 15 to 40 years for buildings and
improvements; 7 to 40 years for storage and customer tanks and cylinders; and 2 to 12 years
for vehicles, equipment, and office furniture and fixtures. Depreciation expense was $150.6
in fiscal 2007, $130.9 in fiscal 2006, and $127.8 in fiscal 2005. No depreciation expense is included in cost of sales in the Consolidated Statements of Income.
F-14
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Costs to install Partnership and Antargaz-owned tanks, net of amounts billed to
customers, are capitalized and amortized over the estimated period of benefit not exceeding
ten years.
We evaluate the impairment of long-lived assets whenever events or changes in circumstances
indicate that the carrying amount of such assets may not be recoverable. We evaluate
recoverability based upon undiscounted future cash flows expected to be generated by such
assets. During fiscal 2007, 2006 and 2005, no provisions for impairments were recorded.
Intangible Assets. Intangible assets comprise the following at September 30:
| 2007 | 2006 | |||||||
Goodwill (not subject to amortization) |
$ | 1,498.8 | $ | 1,418.2 | ||||
Other intangible assets: |
||||||||
Customer relationships, noncompete agreements and other |
$ | 208.9 | $ | 183.0 | ||||
Trademark (not subject to amortization) |
48.4 | 43.1 | ||||||
Gross carrying amount |
257.3 | 226.1 | ||||||
Accumulated amortization |
(84.2 | ) | (62.8 | ) | ||||
Net carrying amount |
$ | 173.1 | $ | 163.3 | ||||
The increase in goodwill during fiscal 2007 is principally the result of
AmeriGas Propane business acquisitions and the effects of foreign currency translation
reduced by a $20.5 adjustment resulting principally from the working capital payment from SU
associated with the PG Energy Acquisition. The changes in the carrying amount of other
intangible assets during fiscal 2007 principally reflects AmeriGas Propane business
acquisitions and the effects of foreign currency translation.
We amortize customer relationship and noncompete agreement intangibles over their
estimated periods of benefit which do not exceed 15 years. Amortization expense of
intangible assets was $16.9 in fiscal 2007, $16.5 in fiscal 2006 and $16.9 in fiscal 2005.
No amortization expense is included in cost of sales in the
Consolidated Statements of Income.
Estimated amortization expense of intangible assets during the next five
fiscal years is as follows: fiscal 2008 — $17.6; fiscal 2009 — $16.9; fiscal 2010 —
$15.4; fiscal 2011 — $14.8; fiscal 2012 — $14.7.
In accordance with the provisions of SFAS No. 142, “Goodwill and Other Intangible
Assets” (“SFAS 142”), we amortize intangible assets over their useful lives unless we
determined their lives to be indefinite. Goodwill and other intangible assets with
indefinite lives are not amortized but are subject to tests for impairment at least
annually. SFAS 142 requires that we perform impairment tests more frequently than annually
if events or circumstances indicate that the value of goodwill or intangible assets with
indefinite lives might be impaired. When performing our impairment tests, we use quoted
market prices or, in the absence of quoted market prices, discounted estimates of future
cash flows. No provisions for goodwill or other intangibles impairments were recorded during
fiscal 2007, 2006 or 2005.
Stock-Based Compensation. We adopted SFAS No. 123 (Revised 2004), “Share-Based Payment”
(“SFAS 123R”), effective October 1, 2005. Among other things, SFAS 123R requires expensing
the fair value of stock options, a previously optional accounting method. We chose the
modified prospective approach which requires that the new guidance be applied to the
unvested portion of all outstanding option grants as of October 1, 2005 and to new grants
after that date. The adoption of SFAS 123R resulted in pre-tax stock option expense of $6.3
and $3.8 during fiscal 2007 and 2006, respectively. SFAS 123R also requires the calculation
of an accumulated pool of tax windfalls using historical data from the effective date of
SFAS No. 123 (prior to its revision). We have calculated a tax windfall pool using the
shortcut method and any future tax shortfalls related to equity-based compensation will be
charged against common stock up to the amount of the tax windfall pool.
In accordance with SFAS 123R, all of our equity-based compensation, principally
comprising UGI stock options, grants of UGI stock-based and AmeriGas Partners Common
Unit-based equity instruments (“Units”) is measured at fair value on the grant date, date of
modification, or end of the period, as applicable, and recognized in earnings over the
requisite service period. Depending upon the settlement terms of the awards, all or a
portion of the fair value of the awards may be presented as a liability or as equity in our
Consolidated Balance Sheets. We use a Black-Scholes option-pricing model to estimate the
fair value of UGI stock options. We use a Monte Carlo valuation approach to estimate the
fair value of our UGI and AmeriGas Unit awards. Equity-based compensation costs associated
with the portion of Unit awards classified as equity are measured based upon their estimated
fair value on the date of grant or modification. Equity-based compensation costs associated
with the portion of Unit awards classified as liabilities are measured based upon their
estimated fair value as of the end of each period.
F-15
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
During fiscal 2006, the Company modified the settlement terms of certain UGI Unit awards
previously granted to 28 key employees on January 1, 2006, and the General Partner modified
the settlement terms of certain of its AmeriGas Partner Unit awards. The modifications did
not affect the number of Units awarded to employees. As a result of the modifications, a
portion of the fair value of these Unit awards is reflected as equity rather than as a
liability in accordance with SFAS 123R. We did not record any incremental equity-based
compensation expense as a result of these modifications. Also during 2006, we modified the
settlement terms of UGI Unit awards granted to non-employee directors. Such awards are now settled 65% in shares of UGI Common Stock and 35% in
cash. Prior to this modification, these awards were settled 100% in shares of UGI Common
Stock. As a result of this modification, during fiscal 2006 we recorded additional pre-tax
equity-based compensation expense of $1.0.
Prior to October 1, 2005, we applied the provisions of Accounting Principles Board (“APB”)
Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), in recording
equity-based compensation. Under APB 25, the Company did not record any compensation
expense for stock options, but provided the required pro forma disclosures as if we had
determined compensation expense under the fair value method prescribed by the provisions of
SFAS No. 123.
We recognized total pre-tax equity-based compensation expense of $12.4 ($8.5 after-tax),
$9.0 ($6.0 after-tax), and $15.5 ($10.1 after-tax) in fiscal 2007, 2006 and 2005,
respectively. The chart below reflects the effects on net income and basic and diluted
earnings per share for fiscal 2005 as if we had applied the provisions of SFAS 123R:
| 2005 | ||||
Net income, as reported |
$ | 187.5 | ||
Add: Stock and Unit-based compensation expense included in
reported net income, net of related tax effects |
10.1 | |||
Deduct: Total Stock and Unit-based employee compensation
expense determined under the fair value method for all awards,
net of related tax effects |
(11.9 | ) | ||
Pro forma net income |
$ | 185.7 | ||
Basic earnings per share: |
||||
As reported |
$ | 1.81 | ||
Pro forma |
$ | 1.79 | ||
Diluted earnings per share: |
||||
As reported |
$ | 1.77 | ||
Pro forma |
$ | 1.76 | ||
For a description of our equity-based compensation plans and related
disclosures, see Note 8.
Deferred Debt Issuance Costs. Included in “Other assets” on our Consolidated Balance Sheets
are net deferred debt issuance costs of $19.1 at September 30, 2007 and $19.9 at September
30, 2006. We are amortizing these costs over the terms of the related debt.
Refundable Tank and Cylinder Deposits. Included in “Other noncurrent liabilities” are
customer paid deposits on Antargaz owned tanks and cylinders of $228.5 and $207.4 at
September 30, 2007 and 2006, respectively. Deposits are refundable to customers when the
tanks or cylinders are returned in accordance with contract terms.
Computer Software Costs. We include in property, plant and equipment costs associated with
computer software we develop or obtain for use in our businesses. We amortize computer
software costs on a straight-line basis over expected periods of benefit not exceeding
fifteen years once the installed software is ready for its intended use.
Deferred Fuel Costs. Gas Utility’s tariffs contain clauses which permit recovery of certain
purchased gas costs through the application of purchased gas cost (“PGC”) rates. The clauses
provide for periodic adjustments to PGC rates for the difference between the total amount of
purchased gas costs collected from customers and the recoverable costs incurred. In
accordance with SFAS 71, we defer the difference between amounts recognized in revenues and
the applicable gas costs incurred until they are subsequently billed or refunded to
customers.
Environmental and Other Legal Matters. We accrue environmental investigation and cleanup
costs when it is probable that a liability exists and the amount or range of amounts can be
reasonably estimated. Amounts accrued generally reflect our best estimate of costs expected
to be incurred or the minimum liability associated with a range of expected environmental
response costs. Our estimated liability for environmental contamination is reduced to
reflect anticipated participation of other responsible parties but is not reduced for
possible recovery from insurance carriers. In those instances for which the amount and
timing of cash payments associated with environmental investigation and cleanup are reliably
determinable, we discount such liabilities to reflect the time value of money. We intend to
pursue recovery of incurred costs through all appropriate means, including regulatory
relief. UGI Gas is permitted to amortize as removal costs site-specific environmental
investigation and remediation costs, net of related third-party payments, associated with
Pennsylvania sites. UGI Gas is currently permitted to include in rates, through future base
rate proceedings, a five-year average of such prudently incurred remediation costs. In
accordance with the terms of the PNG Gas base rate case order which became effective on
December 2, 2006, site-specific environmental investigation and remediation costs associated
with PNG Gas incurred prior to December 2, 2006 are amortized as
removal costs over five-year periods. Such costs incurred after December 1, 2006 are
expensed as incurred. At September 30, 2007 and 2006, neither the Company’s undiscounted
amount nor its accrued liability for environmental investigation and cleanup costs was
material.
F-16
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Similar to environmental issues, we accrue for other pending claims and legal actions
investigation and other legal costs for other matters when it is probable that a liability
exists and the amount or range of amounts can be reasonably estimated (see Note 10).
Foreign Currency Translation. Balance sheets of international subsidiaries and our
investments in international LPG joint ventures are translated into U.S. dollars using the
exchange rate at the balance sheet date. Income statements and equity investee results are
translated into U.S. dollars using an average exchange rate for each reporting period. Where
the local currency is the functional currency, translation adjustments are recorded in other
comprehensive income. Where the local currency is not the functional currency, translation
adjustments are recorded in net income.
Employee Retirement Plans. We use a market-related value of plan assets and an expected
long-term rate of return to determine the expected return on our pension plans and other
postretirement plan assets. The market-related value of plan assets, other than equity
investments, is based upon market prices. The market-related value of equity investments is
calculated by rolling forward the prior-year’s market-related value with contributions,
disbursements and the expected return on plan assets. One third of the difference between
the expected and the actual value is then added to or subtracted from the expected value to
determine the new market-related value. See Note 5.
SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans
— an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (“SFAS 158”), became
effective for us as of September 30, 2007. SFAS 158 requires recognition of an asset or
liability in the statement of financial position reflecting the funded status of pension and
postretirement benefit plans such as retiree health and life, with current year changes
recognized in shareholders’ equity. SFAS 158 did not change the existing criteria for
measurement of periodic benefit costs, plan assets or benefit obligations.
The following table summarizes the incremental effects of the initial adoption of SFAS 158
on our Consolidated Balance Sheet as of September 30, 2007:
| Before | After | |||||||||||
| Application | SFAS 158 | Application | ||||||||||
| of SFAS 158 | Adjustments | of SFAS 158 | ||||||||||
Other assets |
$ | 122.3 | $ | (15.4 | ) | $ | 106.9 | |||||
Total assets |
5,518.1 | (15.4 | ) | 5,502.7 | ||||||||
Other noncurrent liabilities |
375.9 | 3.6 | 379.5 | |||||||||
Deferred income taxes |
514.2 | (7.8 | ) | 506.4 | ||||||||
Total liabilities |
3,992.8 | (4.2 | ) | 3,988.6 | ||||||||
Accumulated other comprehensive income (loss)
|
68.9 | (11.2 | ) | 57.7 | ||||||||
Total stockholders’ equity |
1,333.1 | (11.2 | ) | 1,321.9 | ||||||||
Total liabilities and stockholders’
equity |
5,518.1 | (15.4 | ) | 5,502.7 | ||||||||
The
amount recorded in accumulated other comprehensive income at
September 30, 2007 includes $(11.6) associated with our
pension plans, principally comprising net actuarial losses, and $0.4 associated with our other postretirement benefit plans,
principally comprising net actuarial gains.
Comprehensive Income. Comprehensive income comprises net income and other comprehensive
income (loss). Other comprehensive income (loss) principally results from gains and losses
on derivative instruments qualifying as cash flow hedges and foreign currency translation
adjustments. Accumulated other comprehensive income at September 30, 2007 also includes the
effects of the initial adoption of SFAS 158.
The components of accumulated other comprehensive income (loss) at September 30, 2007
and 2006 follow:
| Foreign | ||||||||||||
| Derivative | Currency | |||||||||||
| Postretirement | Instruments Net | Translation | ||||||||||
| Benefit Plans | Losses | Adjustments | ||||||||||
Balance, September 30, 2007 |
$ | (11.2 | ) | $ | (4.4 | ) | $ | 73.3 | ||||
Balance, September 30, 2006 |
$ | — | $ | (23.4 | ) | $ | 19.6 | |||||
F-17
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Recently Issued Accounting Pronouncements. In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No.
159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an
amendment of FASB Statement No. 115” (“SFAS 159”), which permits entities to choose to
measure certain financial instruments at fair value that are not currently required to be
measured at fair value. Upon adoption of SFAS 159, a cumulative adjustment will be made to
beginning retained earnings for the initial fair value option remeasurement. Subsequent
unrealized gains and losses for remeasured assets and liabilities will be reported in
earnings. SFAS 159 is effective for our fiscal year beginning October 1, 2008 (fiscal 2009)
and shall not be applied retrospectively, except as permitted by certain conditions for
early adoption. We are currently evaluating the potential impact of SFAS 159.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”).
SFAS 157 defines fair value, establishes a framework for measuring fair value in generally
accepted accounting principles, and expands disclosures about fair value measurements. The
provisions of this standard apply to other accounting pronouncements that require or permit
fair value measurements. The provisions of SFAS 157 are effective for our fiscal year
beginning October 1, 2008 (fiscal 2009). We are currently evaluating the potential impact
of SFAS 157.
In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in
Income Taxes — an interpretation of FASB No. 109” (“FIN 48”), which clarifies the
accounting for uncertainty in income taxes. FIN 48 requires the impact of a tax position be
recognized if that tax position is more likely than not of being sustained on audit, based
on the technical merits of the position. The tax position is measured at the largest amount
of benefit that is greater than 50% likely of being realized upon the effective settlement.
The provisions of FIN 48 are effective for our fiscal year beginning October 1, 2007 (fiscal
2008), with any cumulative effect of the change in accounting principle recorded as an
adjustment to opening retained earnings. The Company has determined that its expected
charge to beginning retained earnings as of October 1, 2007 will not be material.
Note 2 — Acquisitions and Divestitures
On August 24, 2006, UGI Utilities acquired certain assets and assumed certain liabilities of
Southern Union Company’s (“SU’s”) PG Energy Division, a natural gas distribution utility
located in northeastern Pennsylvania, and all of the issued and outstanding stock of SU’s
wholly-owned subsidiary, PG Energy Services, Inc., pursuant to a Purchase and Sale
Agreement, as amended, between SU and UGI dated January 26, 2006 (the “Agreement”). UGI
subsequently assigned its rights under the Agreement to UGI Utilities. On August 24, 2006
and in accordance with the terms of the Agreement, UGI Utilities paid SU $580 in cash. The
cash payment of $580 was funded with net proceeds from the issuance of $275 of UGI
Utilities’ bank loans under a Credit Agreement dated as of August 18, 2006 (the “Bridge
Loan”), cash capital contributions from UGI of $265 and borrowings under UGI Utilities’
revolving credit agreement for working capital. In September 2006, UGI Utilities repaid the
Bridge Loan with proceeds from the issuance of $175 of 5.753% Senior Notes due 2016 and $100
of 6.206% Senior Notes due 2036. Pursuant to the terms of the Agreement, the initial
purchase price was subject to a working capital adjustment equal to the difference between
$68.1 and the actual working capital as of the closing date agreed to by both UGI Utilities
and SU. In March 2007, UGI Utilities and SU reached an agreement on the working capital
adjustment pursuant to which SU paid UGI Utilities approximately $23.7 in cash.
During
fiscal 2007, UGI Utilities completed its review and determination of the fair value
of the assets acquired and liabilities assumed. The purchase price of the PG Energy
Acquisition, including transaction fees and expenses of approximately $11.0, has been
allocated to the assets acquired and liabilities assumed as follows:
Working capital |
$ | 47.3 | ||
Property, plant, and equipment |
362.3 | |||
Goodwill |
162.3 | |||
Regulatory assets |
15.0 | |||
Other assets |
4.0 | |||
Noncurrent liabilities |
(23.6 | ) | ||
Total |
$ | 567.3 | ||
Substantially all of the goodwill is deductible for income tax purposes over a
fifteen-year period.
F-18
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The operating results of PNG Gas are included in our consolidated results beginning
August 24, 2006. The following table presents unaudited pro forma income statement and basic
and diluted per share data for fiscal 2006 and 2005 as if the acquisition of PNG Gas had occurred
as of the beginning of those periods:
| 2006 | 2005 | |||||||
| (pro forma) | (pro forma) | |||||||
Revenues |
$ | 5,545.7 | $ | 5,176.1 | ||||
Net income |
$ | 88.5 | $ | 199.5 | ||||
Earnings per share: |
||||||||
Basic |
$ | 0.84 | $ | 1.92 | ||||
Diluted |
$ | 0.83 | $ | 1.89 | ||||
The pro forma results of operations reflect PNG Gas’ historical operating results
after giving effect to adjustments directly attributable to the transaction that are
expected to have a continuing effect. The pro forma amounts are not necessarily indicative
of the operating results that would have occurred had the PG Energy Acquisition been
completed as of the date indicated, nor are they necessarily indicative of future operating
results. The unaudited pro forma net income and earnings per share for fiscal 2006 include
the effects of a writedown of goodwill of $98 recorded by SU during the three months ended
December 31, 2005.
During fiscal 2007, the Partnership acquired several retail propane distribution
businesses, including the retail distribution businesses of All Star Gas Corporation and Shell Gas (LPG)
USA, and several cylinder refurbishing businesses. Total cash consideration for these
businesses totaled $79.6.
In July 2007, AmeriGas OLP sold its 3.5 million barrel liquefied petroleum gas storage
terminal located near Phoenix, Arizona to Plains LPG Services, L.P. The Partnership recorded a
pre-tax gain of $46.1 which is included in “Other income, net” in the fiscal 2007
Consolidated Statement of Income. The gain increased fiscal 2007 net income by $12.5 or
$0.12 per diluted share.
In March 2006, UGID sold its 50% ownership interest in Hunlock Creek Energy Ventures
(“Energy Ventures”) to Allegheny Energy Supply Hunlock Creek, LLC. Energy Ventures’ assets
primarily comprised a 44-megawatt gas-fired combustion turbine electric generator and a
48-megawatt coal-fired electric generation facility. As part of the transaction, Energy
Ventures transferred its ownership in the 48-megawatt coal-fired electric generation station
to UGID. UGID recorded a net pre-tax gain of $9.1 ($5.3 after-tax) associated with this
transaction, which is reflected in “Other income, net” in the fiscal 2006 Consolidated
Statement of Income. The gain increased fiscal 2006 net income by $0.05 per diluted share.
On February 15, 2006, Flaga entered into an agreement with a subsidiary of Progas GmbH
& Co KG (“Progas”) to form a joint venture company, Zentraleuropa LPG Holding, an Austrian
limited liability company (“ZLH”), which, through subsidiaries, distributes LPG in the Czech
Republic, Hungary, Poland, Slovakia and Romania. ZLH is owned and controlled equally by
Flaga and Progas. Progas, headquartered in Dortmund, Germany, is controlled by Thyssen’sche
Handelsgesellschaft m.b.H. As part of the joint venture formation, Flaga contributed the
shares of its LPG subsidiaries which operate in the Czech Republic and Slovakia to ZLH and
paid €9.2 cash to Progas. Progas contributed the shares of its LPG subsidiaries operating in
the Czech Republic, Hungary, Poland, Romania and Slovakia to ZLH. The operating subsidiaries
distributed a combined approximately 77 million gallons of LPG in these five countries in
2005. In a related transaction, Flaga purchased Progas’ retail LPG business in Austria. The
cash consideration for this business was not material.
In November 2004, UGI Asset Management, Inc. acquired from ConocoPhillips Company and
AmerE Holdings, Inc. (a wholly owned, indirect subsidiary of AmeriGas OLP) in separate
transactions 100% of the issued and outstanding common stock of Atlantic Energy for an
aggregate purchase price of approximately $24 in cash, including post-closing adjustments
(the “AEI Acquisition”). The AEI Acquisition has been accounted for as a step acquisition in
the Consolidated Financial Statements.
During fiscal 2006, AmeriGas OLP acquired two retail propane distribution businesses and a
cylinder refurbishing business. During fiscal 2005, AmeriGas OLP acquired several retail
propane distribution businesses and HVAC/R acquired a commercial and residential electrical
contracting business. Total cash consideration for these businesses were $3.3 and $24.6 in
fiscal 2006 and 2005, respectively. The operating results of these businesses have been
included in our operating results from their respective dates of acquisition. The pro forma
effects of these transactions, the previously mentioned fiscal 2007 Partnership
acquisitions, and Flaga’s 2006 transactions with Progas, are not material.
F-19
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 3 — Debt
Long-term debt comprises the following at September 30:
| 2007 | 2006 | |||||||
AmeriGas Propane: |
||||||||
AmeriGas Partners Senior Notes: |
||||||||
8.875%, due May 2011 (including unamortized
premium of $0.2, effective rate - 8.46%) |
$ | 14.8 | $ | 14.8 | ||||
7.25%, due May 2015 |
415.0 | 415.0 | ||||||
7.125%, due May 2016 |
350.0 | 350.0 | ||||||
AmeriGas OLP First Mortgage Notes: |
||||||||
Series D, 7.11%, due March 2009 (including
unamortized premium of $0.6 and $0.9,
respectively, effective rate - 6.52%) |
70.6 | 70.9 | ||||||
Series E, 8.50%, due July 2010 (including
unamortized premium of $0.1, effective
rate - 8.47%) |
80.1 | 80.1 | ||||||
Other |
2.6 | 2.9 | ||||||
Total AmeriGas Propane |
933.1 | 933.7 | ||||||
International Propane: |
||||||||
Antargaz Senior Facilities term loan,
due March 2011 |
541.8 | 483.5 | ||||||
Flaga term loan, due through September 2011 |
59.9 | 60.9 | ||||||
Other |
3.5 | 2.6 | ||||||
Total International Propane |
605.2 | 547.0 | ||||||
UGI Utilities: |
||||||||
Senior Notes: |
||||||||
5.75% Notes, due October 2016 |
175.0 | 175.0 | ||||||
6.21% Notes, due October 2036 |
100.0 | 100.0 | ||||||
Medium Term Notes: |
||||||||
7.17% Notes, due June 2007 |
— | 20.0 | ||||||
5.53% Notes, due September 2012 |
40.0 | 40.0 | ||||||
5.37% Notes, due August 2013 |
25.0 | 25.0 | ||||||
5.16% Notes, due May 2015 |
20.0 | 20.0 | ||||||
7.37% Notes, due October 2015 |
22.0 | 22.0 | ||||||
5.64% Notes, due December 2015 |
50.0 | 50.0 | ||||||
6.17% Notes, due June 2017 |
20.0 | — | ||||||
7.25% Notes, due November 2017 |
20.0 | 20.0 | ||||||
6.50% Notes, due August 2033 |
20.0 | 20.0 | ||||||
6.13% Notes, due October 2034 |
20.0 | 20.0 | ||||||
Total UGI Utilities |
512.0 | 512.0 | ||||||
Other |
3.2 | 4.2 | ||||||
Total long-term debt |
2,053.5 | 1,996.9 | ||||||
Less current maturities (including net unamortized
premium of $0.5) |
(14.7 | ) | (31.9 | ) | ||||
Total long-term debt due after one year |
$ | 2,038.8 | $ | 1,965.0 | ||||
F-20
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Scheduled principal repayments of long-term debt due in fiscal years 2008 to 2012
follows:
| 2008 | 2009 | 2010 | 2011 | 2012 | ||||||||||||||||
AmeriGas Propane |
$ | 1.5 | $ | 70.5 | $ | 80.3 | $ | 14.8 | $ | 0.1 | ||||||||||
UGI Utilities |
— | — | — | — | 40.0 | |||||||||||||||
International Propane
and Other |
12.7 | 9.7 | 9.3 | 576.2 | 3.5 | |||||||||||||||
Total |
$ | 14.2 | $ | 80.2 | $ | 89.6 | $ | 591.0 | $ | 43.6 | ||||||||||
AmeriGas Propane
AmeriGas Partners Senior Notes. The 8.875% Senior Notes may be redeemed at our option; a
redemption premium applies through May 19, 2009. The 7.25% and 7.125% Senior Notes generally
cannot be redeemed at our option prior to May 20, 2010 and 2011, respectively. In January
2006, the Partnership refinanced its Series A and Series C First Mortgage Notes totaling
$228.8; $59.6 of the Partnership’s 10% Senior Notes; and an
AmeriGas OLP $35 term loan, with proceeds from
the issuance of $350 of AmeriGas Partners 7.125% Senior Notes due 2016. In May 2005,
AmeriGas Partners refinanced $373.4 of its 8.875% Senior Notes pursuant to a tender offer
with proceeds from the issuance of $415 of 7.25% Senior Notes due 2015. The Partnership
recognized losses of $17.1 and $33.6 associated with these refinancings which amounts are
reflected in “Loss on extinguishments of debt” in the fiscal 2006 and 2005 Consolidated
Statements of Income, respectively. AmeriGas Partners may, under certain circumstances
following the disposition of assets or a change of control, be required to offer to prepay
its 7.25% and 7.125% Senior Notes.
AmeriGas OLP First Mortgage Notes. As of November 6, 2006, AmeriGas OLP’s First Mortgage
Notes are no longer collateralized. The General Partner is co-obligor of the Series D and E
First Mortgage Notes. AmeriGas OLP may prepay the First Mortgage Notes, in whole or in part.
These prepayments include a make whole premium. Following the disposition of assets or a
change of control, AmeriGas OLP may be required to offer to prepay the First Mortgage Notes,
in whole or in part.
AmeriGas OLP Credit Agreement. Effective November 6, 2006, AmeriGas OLP entered into a new
unsecured Credit Agreement (“AmeriGas Credit Agreement”) consisting of (1) a Revolving
Credit Facility and (2) an Acquisition Facility. The General Partner and Petrolane are
guarantors of amounts outstanding under the AmeriGas Credit Agreement. References made
herein to the AmeriGas Credit Agreement relate to the former or new Credit Agreement, as
appropriate.
Under the Revolving Credit Facility, AmeriGas OLP may borrow up to $125, including a
$100 sublimit for letters of credit, which is subject to restrictions in the AmeriGas
Partners Senior Notes indentures (see “Restrictive Covenants” below). The Revolving Credit
Facility may be used for working capital and general purposes of AmeriGas OLP. The Revolving
Credit Facility expires on October 15, 2011, but may be extended for additional one-year
periods with the consent of the participating banks representing at least 80% of the
commitments thereunder. There were no borrowings outstanding under AmeriGas OLP’s Revolving
Credit Facility at September 30, 2007 and 2006. Issued and outstanding letters of credit,
which reduce available borrowings under the Revolving Credit Facility, totaled $58.0 and
$58.9 at September 30, 2007 and 2006, respectively.
The Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 to
finance the purchase of propane businesses or propane business assets or, to the extent it
is not so used, for working capital and general purposes, subject to restrictions in the
Senior Notes indentures. The Acquisition Facility operates as a revolving facility through
October 15, 2011, at which time amounts then outstanding will be immediately due and
payable. There were no amounts outstanding under the Acquisition Facility at September 30,
2007 and 2006.
The Revolving Credit Facility and the Acquisition Facility permit AmeriGas OLP to
borrow at prevailing interest rates, including the base rate, defined as the higher of the
Federal Funds rate plus 0.50% or the agent bank’s prime rate (7.75% at September 30, 2007),
or at a two-week, one-, two-, three-, or six-month Eurodollar Rate,
as defined in the AmeriGas Credit
Agreement, plus a margin. The margin on Eurodollar Rate borrowings (which ranges from 1.00%
to 1.75%), and the AmeriGas Credit Agreement facility fee rate (which ranges from 0.25% to
0.375%), are dependent upon AmeriGas OLP’s ratio of funded debt to earnings before interest
expense, income taxes, depreciation and amortization (“EBITDA”), each as defined in the
AmeriGas Credit Agreement.
AmeriGas OLP Term Loan. In April 2005, AmeriGas OLP entered into a $35 variable-rate term
loan due October
1, 2006 (“AmeriGas OLP Term Loan”), which bore interest plus margin at the same rates as the
AmeriGas Credit
Agreement. Proceeds from the AmeriGas OLP Term Loan were used to repay a portion of the
$53.8 maturing AmeriGas OLP First Mortgage Notes. The Partnership used a portion of the
proceeds from the issuance of the 7.125% Senior Notes due 2016 to repay the AmeriGas OLP
Term Loan in January 2006.
F-21
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Restrictive Covenants. The 7.125% and 7.25% Senior Notes of AmeriGas Partners restrict the
ability of the Partnership and AmeriGas OLP to, among other things, incur additional
indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated
indebtedness, and effect mergers, consolidations and sales of assets.
The AmeriGas Credit Agreement and First Mortgage Notes restrict the incurrence of
additional indebtedness and also restrict certain liens, guarantees, investments, loans and
advances, payments, mergers, consolidations, asset transfers, transactions with affiliates,
sales of assets, acquisitions and other transactions. The AmeriGas Credit Agreement and
First Mortgage Notes require a maximum ratio of total indebtedness to EBITDA, as defined. In
addition, the AmeriGas Credit Agreement requires that AmeriGas OLP maintain a minimum ratio
of EBITDA to interest expense, as defined, and a minimum interest coverage ratio. Generally,
as long as no default exists or would result, the Partnership and AmeriGas OLP are permitted
to make cash distributions not more frequently than quarterly in an amount not to exceed
available cash, as defined, for the immediately preceding calendar quarter.
International Propane
On December 7, 2005, Antargaz executed a new five-year, floating rate Senior Facilities
Agreement with a major French bank providing for a €380 term loan and a €50 revolving credit
facility. AGZ Finance notified the holders of its High Yield Bonds of its decision to redeem
them, including a premium, pursuant to the Trust Deed. The proceeds of the term loan were
used in December 2005 to repay immediately the existing €175 Senior Facilities term loan, to
fund the redemption of the €165 High Yield Bonds in January 2006 (including a premium) and
for general corporate purposes. As a result of this refinancing, we incurred a pre-tax loss
on extinguishment of debt of $1.4 ($0.9 after-tax).
Antargaz’ term loan bears interest at euribor or libor plus margin, as defined by the
Senior Facilities Agreement. The margin (which ranges from 0.70% to 1.15%) is dependent upon
Antargaz’ ratio of total net debt to EBITDA, each as defined by the Senior Facilities
Agreement. AGZ has executed interest rate swap agreements with the same bank to fix the
underlying euribor or libor rate of interest on the term loan at approximately 3.25% for the
duration of the loan (see Note 11). The effective interest rate on Antargaz’ term loan at
September 30, 2007 was 4.05%. The Senior Facilities Agreement debt has been collateralized
by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its
accounts receivable.
Effective in July 2006, Flaga entered into a euro-based, variable-rate term loan
facility in the amount of €48 and a working capital facility of up to €8 which expire in
September 2011. The term loan bears interest at one- to twelve-month euribor rates (as
chosen by Flaga from time to time) plus a margin. The margin on such borrowings range from
0.52% to 1.45%. Generally, principal payments of €3 on the term loan are due semi-annually
on March 31 and September 30 each year with final payments totaling €24 due in 2011. The
effective interest rate on Flaga’s term loan at September 30, 2006 was 3.72%. In November
2006, Flaga effectively fixed the euribor component of its interest rate on a substantial
portion of the term loan through September 2011 at 3.91% by entering into an interest rate
swap agreement. The effective interest rate on Flaga’s term loan at September 30, 2007 was
4.43%. Flaga may prepay the term loan, in whole or in part, without incurring any premium.
Flaga repaid its multi-currency acquisition note (“Acquisition Note”) with the proceeds from
its term loan. The Acquisition Note bore interest at a rate of 1.25% over one- to
twelve-month euribor rates (as chosen by Flaga from time to time).
Flaga’s borrowings under its working capital facility at September 30, 2007 and 2006
totaled €6.3 ($8.9) and €7.4 ($9.4), respectively. Amounts outstanding under the working
capital facility are classified as bank loans. Borrowings under its working capital
facility bear interest at market rates (a daily euro-based rate) plus a margin. The
weighted-average interest rates on Flaga’s bank loan borrowings outstanding were 5.42% at
September 30, 2007 and 4.23% at September 30, 2006.
Restrictive Covenants and Guarantees. The Senior Facilities Agreement restricts the ability
of AGZ and its subsidiaries, including Antargaz, to, among other things, incur additional
indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of
assets. Under this agreement, AGZ is generally permitted to make restricted payments, such
as dividends, if the ratio of net debt to EBITDA on a French generally accepted accounting
basis, as defined in the agreement, is less than 3.75 to 1.00 and if no event of default
exists or would exist upon payment of such restricted payment.
The Flaga term loan and working capital facility are guaranteed by UGI. In addition,
under certain conditions regarding changes in certain financial ratios of UGI, the lending
bank may accelerate repayment of the debt.
Flaga’s joint venture, ZLH, has multi-currency working capital facilities that provide
for borrowings of up to €14, half of which is guaranteed by UGI.
F-22
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
UGI Utilities
Revolving Credit Agreements. UGI Utilities has a revolving credit agreement (“Utilities
Revolving Credit Agreement”) with banks providing for borrowings of up to $350 expiring
August 2011. Under this agreement, UGI Utilities may borrow at various prevailing interest
rates, including LIBOR and the banks’ prime rate. UGI Utilities had borrowings outstanding
under the Utilities Revolving Credit Agreement totaling $190.0 at September 30, 2007 and
$216.0 at September 30, 2006, which we classify as bank loans. From time to time, UGI
Utilities has entered into short-term borrowings under uncommitted arrangements with major
banks in order to meet liquidity needs. Such borrowings are also classified as bank loans.
There were no amounts outstanding under these uncommitted arrangements at September 30, 2007
or 2006. During fiscal 2006, we repaid two separate $35 borrowings outstanding under
uncommitted arrangements with major banks in February and March 2006. The weighted-average
interest rates on UGI Utilities’ bank loans were 5.24% at September 30, 2007 and 5.58% at
September 30, 2006.
Restrictive Covenants. Utilities Revolving Credit Agreement requires UGI Utilities to
maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of
0.65 to 1.00.
Note 4 — Income Taxes
Income before income taxes comprises the following:
| 2007 | 2006 | 2005 | ||||||||||
Domestic |
$ | 278.4 | $ | 193.6 | $ | 161.4 | ||||||
Foreign |
52.6 | 81.1 | 145.3 | |||||||||
Total income before income taxes |
$ | 331.0 | $ | 274.7 | $ | 306.7 | ||||||
The provisions for income taxes consist of the following:
| 2007 | 2006 | 2005 | ||||||||||
Current expense: |
||||||||||||
Federal |
$ | 65.6 | $ | 54.2 | $ | 49.8 | ||||||
State |
17.4 | 12.0 | 14.6 | |||||||||
Foreign |
16.6 | 24.9 | 42.7 | |||||||||
Total current expense |
99.6 | 91.1 | 107.1 | |||||||||
Deferred expense (benefit): |
||||||||||||
Federal |
24.8 | 2.3 | 0.3 | |||||||||
State |
1.9 | 1.3 | 1.6 | |||||||||
Foreign |
0.8 | 4.2 | 10.6 | |||||||||
Investment tax credit amortization |
(0.4 | ) | (0.4 | ) | (0.4 | ) | ||||||
Total deferred expense |
27.1 | 7.4 | 12.1 | |||||||||
Total income tax expense |
$ | 126.7 | $ | 98.5 | $ | 119.2 | ||||||
Federal income taxes for fiscal 2007, 2006 and 2005 are net of foreign tax
credits of $14.1, $21.2 and $25.4, respectively. Tax benefits associated with nonqualified
stock options reduced taxes currently payable by $3.5, $0.8 and $10.2 for fiscal 2007, 2006
and 2005, respectively.
A reconciliation from the statutory federal tax rate to our effective tax rate is as
follows:
| 2007 | 2006 | 2005 | ||||||||||
Statutory federal tax rate |
35.0 | % | 35.0 | % | 35.0 | % | ||||||
Difference in tax rate due to: |
||||||||||||
State income taxes, net of federal |
3.8 | 3.4 | 2.6 | |||||||||
Effects of international operations |
(1.4 | ) | (3.3 | ) | 2.2 | |||||||
Other, net |
0.9 | 0.8 | (0.9 | ) | ||||||||
Effective tax rate |
38.3 | % | 35.9 | % | 38.9 | % | ||||||
F-23
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Deferred tax liabilities (assets) comprise the following at September 30:
| 2007 | 2006 | |||||||
Excess book basis over tax basis of property, plant and equipment |
$ | 298.0 | $ | 265.1 | ||||
Investment in AmeriGas Partners |
181.2 | 146.6 | ||||||
Intangible assets and goodwill |
51.8 | 46.2 | ||||||
Utility regulatory assets |
41.0 | 29.9 | ||||||
Pension plan assets and liabilities |
7.4 | 4.3 | ||||||
Unrepatriated foreign earnings |
3.9 | 4.4 | ||||||
Accumulated other comprehensive income |
13.7 | — | ||||||
Deferred expenses |
4.7 | 18.3 | ||||||
Other |
2.9 | 4.8 | ||||||
Gross deferred tax liabilities |
604.6 | 519.6 | ||||||
Employee-related benefits |
(30.2 | ) | (23.7 | ) | ||||
Deferred investment tax credits |
(2.7 | ) | (2.8 | ) | ||||
Utility regulatory liabilities |
(3.1 | ) | (9.1 | ) | ||||
Operating loss carryforwards |
(22.8 | ) | (20.2 | ) | ||||
Allowance for doubtful accounts |
(6.8 | ) | (7.9 | ) | ||||
Foreign tax credit carryforward |
(50.1 | ) | (28.3 | ) | ||||
Accumulated other comprehensive loss |
(13.7 | ) | (12.2 | ) | ||||
Other |
(21.8 | ) | (19.1 | ) | ||||
Gross deferred tax assets |
(151.2 | ) | (123.3 | ) | ||||
Deferred tax assets valuation allowance |
62.4 | 39.3 | ||||||
Net deferred tax liabilities |
$ | 515.8 | $ | 435.6 | ||||
UGI
Utilities had recorded deferred tax liabilities of approximately $42.1 as of
September 30, 2007 and $40.4 as of September 30, 2006, pertaining to utility temporary
differences, principally a result of accelerated tax depreciation for state income tax
purposes, the tax benefits of which previously were or will be flowed through to
ratepayers. These deferred tax liabilities have been reduced by deferred tax assets of $2.7
at September 30, 2007 and $2.8 at September 30, 2006, pertaining to utility deferred
investment tax credits. UGI Utilities had recorded regulatory income tax assets related to
these net deferred taxes of $72.0 as of September 30, 2007 and $64.3 as of September 30,
2006. These regulatory income tax assets represent future revenues expected to be recovered
through the
ratemaking process. We will recognize this regulatory income tax asset in deferred tax
expense as the corresponding temporary differences reverse and additional income taxes are
incurred.
Foreign net operating loss carryforwards of Flaga totaled approximately $41.1 and have
no expiration date. At September 30, 2007, deferred tax assets relating to operating loss
carryforwards include $9.6 for Flaga, $2.2 for certain operations of AGZ, $0.6 for certain
operations of UGI International, $2.2 for certain operations of
AmeriGas Propane, and $8.2
of deferred tax assets associated with state net operating loss carryforwards expiring
through 2026. Operating activities and tax deductions related to the exercise of
non-qualified stock options contributed to the state net operating losses. We first
recognize the utilization of state net operating losses from operations (which exclude the
impact of tax deductions for exercises of non-qualified stock options) to reduce income tax
expense. Then, to the extent state net operating loss carryforwards, when realized, relate
to non-qualified stock option deductions, the resulting benefits will be credited to
stockholders’ equity. A valuation allowance of $10.7 has been provided for all deferred tax
assets related to state net operating loss carryforwards and other state deferred tax assets
of certain subsidiaries because, on a state reportable basis, it is more likely than not
that these assets will expire unusable. A valuation allowance of $1.6 was also provided for
deferred tax assets related to certain operations of AGZ and UGI International (BV).
We have foreign tax credit carryforwards of approximately $50.1 expiring through 2018,
resulting from the planned repatriation of AGZ’s accumulated earnings and profits included
in U.S. taxable income since its acquisition. Because we expect that these credits will
expire unused, a valuation allowance has been provided for the entire foreign tax credit
carryforward amount. The valuation allowance for deferred tax assets increased by $23.1 in
fiscal 2007, due primarily to an increase in the foreign tax credit carryforward of $22.8.
F-24
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 5 — Employee Retirement Plans
Defined Benefit Pension and Other Postretirement Plans. We sponsor two defined benefit
pension plans for employees of UGI, UGI Utilities, UGIPNG, and certain of UGI’s other
domestic wholly owned subsidiaries (“Pension Plans”). We also provide postretirement health
care benefits to certain retirees and a limited number of active employees, and
postretirement life insurance benefits to nearly all domestic active and retired employees.
As a result of the PG Energy Acquisition, we acquired the pension assets and assumed the
pension obligations related to the Employees’ Retirement Plan of Southern Union Company
Pennsylvania Division. In addition, Antargaz employees are covered by certain defined
benefit pension and postretirement plans. Although the disclosures in the tables below
include amounts related to the Antargaz plans, such amounts are not material.
Effective September 30, 2007, we adopted SFAS 158, “Employers’ Accounting for Defined
Benefit Pension and Other Postretirement Plans.” See Note 1 for the incremental effects of
the initial adoption of SFAS 158 on our September 30, 2007
Consolidated Balance Sheet.
The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of
the Pension Plans and the Antargaz pension plans, the accumulated benefit obligations (“ABOs”)
of our other postretirement benefit plans, plan assets, and the funded status of the pension and
other postretirement plans as of September 30, 2007 and 2006. ABO is the present value of
benefits earned to date with benefits based upon current compensation levels. PBO is ABO
increased to reflect estimated future compensation.
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||
| 2007 | 2006 | 2007 | 2006 | |||||||||||||
Change in benefit obligations — |
||||||||||||||||
Benefit obligations —
beginning of year |
$ | 316.7 | $ | 247.9 | $ | 23.9 | $ | 23.4 | ||||||||
Service cost |
6.5 | 6.1 | 0.5 | 0.4 | ||||||||||||
Interest cost |
18.8 | 14.3 | 1.2 | 1.3 | ||||||||||||
Actuarial gain |
(18.4 | ) | (12.1 | ) | (1.9 | ) | (0.4 | ) | ||||||||
Plan amendments |
0.3 | — | (2.3 | ) | — | |||||||||||
PG Energy Acquisition |
— | 71.3 | — | 2.4 | ||||||||||||
Plan settlement or curtailment |
(0.1 | ) | — | (0.2 | ) | (1.6 | ) | |||||||||
Foreign currency loss |
1.2 | 0.6 | 0.3 | 0.2 | ||||||||||||
Benefits paid |
(14.6 | ) | (11.4 | ) | (1.4 | ) | (1.8 | ) | ||||||||
Benefit obligations — end of year |
$ | 310.4 | $ | 316.7 | $ | 20.1 | $ | 23.9 | ||||||||
Change in plan assets — |
||||||||||||||||
Fair value of plan assets —
beginning of year |
$ | 278.4 | $ | 215.3 | $ | 11.3 | $ | 11.3 | ||||||||
Actual return on plan assets |
29.4 | 11.6 | 1.2 | 0.9 | ||||||||||||
Foreign currency gain |
0.4 | 0.2 | — | — | ||||||||||||
Employer contributions |
0.4 | 0.4 | 1.1 | 1.7 | ||||||||||||
PG Energy Acquisition |
— | 62.3 | — | — | ||||||||||||
Plan settlement |
— | — | — | (0.8 | ) | |||||||||||
Benefits paid |
(14.6 | ) | (11.4 | ) | (1.4 | ) | (1.8 | ) | ||||||||
Fair value of plan assets — end of year |
$ | 294.0 | $ | 278.4 | $ | 12.2 | $ | 11.3 | ||||||||
Funded status of the plans |
$ | (16.4 | ) | $ | (38.3 | ) | $ | (7.9 | ) | $ | (12.6 | ) | ||||
Unrecognized net actuarial loss |
— | 43.2 | — | 2.4 | ||||||||||||
Unrecognized prior service income |
— | (0.4 | ) | — | (2.3 | ) | ||||||||||
Unrecognized net transition obligation |
— | — | — | 0.7 | ||||||||||||
(Accrued) prepaid benefit cost — end of year |
$ | (16.4 | ) | $ | 4.5 | $ | (7.9 | ) | $ | (11.8 | ) | |||||
Assets
(liabilities) recorded in the balance sheet — |
||||||||||||||||
Prepaid
assets (included in Other assets) |
$ | 1.1 | $ | 19.3 | $ | 0.8 | $ | — | ||||||||
Unfunded
liabilities (included in Other noncurrent liabilities) |
(17.5 | ) | (14.8 | ) | (8.7 | ) | (11.8 | ) | ||||||||
Net amount
recognized |
$ | (16.4 | ) | $ | 4.5 | $ | (7.9 | ) | $ | (11.8 | ) | |||||
Actuarial assumptions for our domestic plans are described in the table below.
Assumptions for the Antargaz plans are based upon market conditions in France. The discount
rates at September 30 are used to measure the year-end benefit obligations and the expense
for the subsequent year. UGIPNG’s expense for fiscal 2006 (for the period subsequent to the
PG Energy Acquisition) was based upon assumptions as of August 31, 2006. The expected rate
of return on assets assumption is based on the rates of return for certain asset classes and
the allocation of plan assets among those asset classes as well as actual historic long-term
rates of return on our plan assets.
F-25
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
| Pension Plans | Other Postretirement Benefits | |||||||||||||||||||||||||||||||
| Weighted-average assumptions: | 2007 | 2006 | 2005 | 2004 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||||||||||
Discount rate |
6.4 | % | 6.0 | % | 5.7 | % | 6.1 | % | 6.4 | % | 6.0 | % | 5.7 | % | 6.1 | % | ||||||||||||||||
Expected return on plan assets |
8.5 | % | 8.5 | % | 9.0 | % | 9.0 | % | 5.5 | % | 5.6 | % | 5.8 | % | 5.8 | % | ||||||||||||||||
Rate of increase in salary levels |
3.8 | % | 3.8 | % | 4.0 | % | 4.0 | % | 3.8 | % | 3.8 | % | 4.0 | % | 4.0 | % | ||||||||||||||||
The ABO for the Pension Plans was $269.3 and $277.7 as of September 30, 2007 and
2006, respectively.
Net periodic pension expense and other postretirement benefit costs include the
following components:
| Other | ||||||||||||||||||||||||
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||
| 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||
Service cost |
$ | 6.5 | $ | 6.1 | $ | 5.6 | $ | 0.5 | $ | 0.4 | $ | 0.4 | ||||||||||||
Interest cost |
18.8 | 14.3 | 14.0 | 1.2 | 1.3 | 1.7 | ||||||||||||||||||
Expected return on assets |
(23.5 | ) | (19.3 | ) | (18.0 | ) | (0.6 | ) | (0.6 | ) | (0.5 | ) | ||||||||||||
Amortization of: |
||||||||||||||||||||||||
Transition obligation |
— | — | — | 0.2 | 0.2 | 0.8 | ||||||||||||||||||
Prior service cost (benefit) |
0.2 | 0.8 | 0.7 | (0.3 | ) | (0.2 | ) | (0.1 | ) | |||||||||||||||
Actuarial loss |
1.1 | 2.0 | 1.5 | — | 0.2 | 0.2 | ||||||||||||||||||
Net benefit cost |
3.1 | 3.9 | 3.8 | 1.0 | 1.3 | 2.5 | ||||||||||||||||||
Change in associated regulatory liabilities |
— | — | — | 3.1 | 2.7 | 1.6 | ||||||||||||||||||
Net benefit cost after changes in regulatory liabilities |
$ | 3.1 | $ | 3.9 | $ | 3.8 | $ | 4.1 | $ | 4.0 | $ | 4.1 | ||||||||||||
Pension Plans assets are held in trust. The Company did not make any
contributions to the Pension Plans in fiscal 2007 nor does it believe it will be required to
make any contributions to the Pension Plans during fiscal 2008 for
ERISA funding purposes. At September 30, 2006, the ABO of the Antargaz pension and
postretirement plans exceeded associated plan assets by $5.3. However, the associated
liability recorded in our Consolidated Balance Sheet at September 30, 2006 exceeded the
minimum pension liability. Antargaz does not expect to make any material contributions to
fund pension or other postretirement benefits during fiscal 2008.
UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”)
trust to pay retiree health care and life insurance benefits by depositing into the VEBA the
annual amount of postretirement benefits costs determined under SFAS No. 106, “Employers
Accounting for Postretirement Benefits Other than Pensions.” The difference between such
amounts and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future
recovery from, or refund to, ratepayers. Effective July 1, 2005, substantially all retirees
and their beneficiaries participating in the UGI Utilities’ postretirement benefit program
were enrolled in insured Medicare Advantage plans. As a result, the net benefit cost
declined for periods subsequent to July 1, 2005. The required contribution to the VEBA
during the year ending September 30, 2008 is not expected to be material.
Expected payments for pension benefits and for other postretirement welfare benefits
are as follows:
| Other | ||||||||
| Pension | Postretirement | |||||||
| Benefits | Benefits | |||||||
Fiscal 2008 |
$ | 15.3 | $ | 1.4 | ||||
Fiscal 2009 |
15.5 | 1.5 | ||||||
Fiscal 2010 |
16.1 | 1.5 | ||||||
Fiscal 2011 |
16.5 | 1.6 | ||||||
Fiscal 2012 |
17.6 | 1.6 | ||||||
Fiscal 2013-2017 |
103.6 | 9.2 | ||||||
F-26
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
In accordance with our investment strategy to obtain long-term growth, our
target asset allocations are to maintain a mix of 60% equities and the remainder in fixed
income funds or cash equivalents. The targets and actual allocations for the Pension Plans’
and VEBA trust assets at September 30 are as follows:
| Target | Pension Plan | VEBA | ||||||||||||||||||||||
| Pension | ||||||||||||||||||||||||
| Plan | VEBA | 2007 | 2006 | 2007 | 2006 | |||||||||||||||||||
Equities |
60 | % | 60 | % | 63 | % | 60 | % | 66 | % | 63 | % | ||||||||||||
Fixed income funds |
40 | % | 30 | % | 37 | % | 40 | % | 29 | % | 30 | % | ||||||||||||
Cash equivalents |
N/A | 10 | % | N/A | N/A | 5 | % | 7 | % | |||||||||||||||
UGI Common Stock comprised approximately 7% of Pension Plan assets at September
30, 2007 and 2006.
The assumed domestic health care cost trend rates are 10.0% for fiscal 2008, decreasing
to 5.5% in fiscal 2012. A one percentage point change in the assumed health care cost trend
rate would increase (decrease) the fiscal 2007 postretirement benefit cost and obligation as
follows:
| 1% | 1% | |||||||
| Increase | Decrease | |||||||
Effect on total service and interest costs |
$ | 0.1 | $ | (0.1 | ) | |||
Effect on postretirement benefit obligation |
$ | 1.6 | $ | (1.3 | ) | |||
We also sponsor unfunded and non-qualified supplemental executive retirement
plans. At September 30, 2007 and 2006, the projected benefit obligations of these plans were
$17.3 and $17.0, respectively. We recorded net benefit costs for these plans of $2.4 in
fiscal 2007, $2.4 in fiscal 2006, and $2.0 in fiscal 2005. These costs are not included in
the tables above.
Defined Contribution Plans. We sponsor 401(k) savings plans for eligible employees of UGI
and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may
contribute a portion of their compensation on either a before-tax basis, or on both a
before-tax and after-tax basis. These plans also provide for employer matching contributions
at various rates. The cost of benefits under the savings plans
totaled $9.2 in fiscal 2007,
$7.8 in fiscal 2006, and $8.3 in fiscal 2005.
Note 6 — Inventories
Inventories comprise the following at September 30:
| 2007 | 2006 | |||||||
LPG and natural gas |
$ | 158.8 | $ | 140.5 | ||||
Utility natural gas and LPG |
156.9 | 157.0 | ||||||
Materials, supplies and other |
43.8 | 42.9 | ||||||
Total inventories |
$ | 359.5 | $ | 340.4 | ||||
Note 7 — Series Preferred Stock
UGI has 10,000,000 shares of UGI Series Preferred Stock, including both series subject to
and series not subject to mandatory redemption, authorized for issuance. We had no shares of
UGI Series Preferred Stock outstanding at September 30, 2007 or 2006.
UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock, including
both series subject to and series not subject to mandatory redemption, authorized for
issuance. At September 30, 2007 and 2006, there were no shares of UGI Utilities Series
Preferred Stock outstanding.
On October 1, 2004, UGI Utilities redeemed all 200,000 shares of its $7.75 UGI
Utilities Series Preferred Stock at a price of $100 per share together with full cumulative
dividends. The redemption was funded with proceeds from the October 2004 issuance of $20 of
6.13% Medium-Term Notes due October 2034.
F-27
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 8 — Common Stock and Incentive Stock Award Plans
UGI Common Stock share activity for fiscal 2005, 2006 and 2007 follows:
| Issued | Treasury | Outstanding | ||||||||||
Balance September 30, 2004 |
115,152,994 | (12,730,598 | ) | 102,422,396 | ||||||||
Issued: |
||||||||||||
Employee and director plans |
— | 2,320,478 | 2,320,478 | |||||||||
Dividend reinvestment plan |
— | 106,584 | 106,584 | |||||||||
Balance September 30, 2005 |
115,152,994 | (10,303,536 | ) | 104,849,458 | ||||||||
Issued: |
||||||||||||
Employee and director plans |
— | 498,642 | 498,642 | |||||||||
Dividend reinvestment plan |
— | 106,262 | 106,262 | |||||||||
Balance September 30, 2006 |
115,152,994 | (9,698,632 | ) | 105,454,362 | ||||||||
Issued: |
||||||||||||
Employee and director plans |
— | 1,104,824 | 1,104,824 | |||||||||
Dividend reinvestment plan |
— | 87,700 | 87,700 | |||||||||
Balance September 30, 2007 |
115,152,994 | (8,506,108 | ) | 106,646,886 | ||||||||
UGI Stock Option and Incentive Plans. Under UGI Corporation’s 2004 Omnibus Equity
Compensation Plan, as Amended and Restated on December 5, 2006 (the “OECP”), we may grant
options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units
(comprising “Stock Units” and “UGI Performance Units”) and other equity-based amounts to key
employees and non-employee directors. The exercise price for options may not be
less than the fair market value on the grant date. Awards granted under the OECP may vest
immediately or ratably over a period of years, and stock options can be exercised
no later than ten years from the grant date. In addition, the OECP provides that awards of
UGI Units may also provide for the crediting of dividend equivalents to participants’
accounts. Generally, each grant, unless paid, will terminate when the participant ceases to
be employed. There are certain change of control and retirement eligibility conditions that,
if met, generally result in accelerated vesting or elimination of further service
requirements.
Under the OECP, awards representing up to 15,000,000 shares of UGI Common Stock may be
granted. The maximum number of shares that may be issued pursuant to grants other than stock
options or SARs is 3,200,000. Dividend equivalents on UGI Unit awards to employees will be
paid in cash. Dividend equivalents on non-employee director awards are paid in additional
Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in
shares of Common Stock and cash. Beginning with fiscal 2006 grants, UGI Unit awards granted
to Antargaz employees are settled in shares of Common Stock. With respect to UGI Performance
Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and
the actual amount of dividend equivalents paid, is generally dependent upon the achievement
of market performance goals and service conditions. It is the Company’s practice to issue
treasury shares to satisfy option exercises and UGI Unit awards. The Company does not expect
to repurchase shares for such purposes during fiscal 2008.
UGI Stock Option Awards. Stock option transactions under the OECP and predecessor plans for
fiscal 2005, 2006 and 2007 follow:
| Weighted | Total | Weighted Avg. | ||||||||||||||
| Average | Intrinsic | Contract Term | ||||||||||||||
| Shares | Option Price | Value | (Years) | |||||||||||||
Shares under option — September 30, 2004 |
5,328,926 | $ | 11.71 | |||||||||||||
Granted |
1,596,100 | $ | 21.13 | |||||||||||||
Exercised |
(1,913,668 | ) | $ | 8.41 | $ | 30.4 | ||||||||||
Forfeited |
(58,340 | ) | $ | 21.91 | ||||||||||||
Shares under option — September 30, 2005 |
4,953,018 | $ | 15.95 | |||||||||||||
Granted |
1,159,100 | $ | 20.67 | |||||||||||||
Exercised |
(232,766 | ) | $ | 11.09 | $ | 2.7 | ||||||||||
Forfeited |
(35,500 | ) | $ | 19.26 | ||||||||||||
Shares under option — September 30, 2006 |
5,843,852 | $ | 17.06 | |||||||||||||
Granted |
1,326,800 | $ | 27.12 | |||||||||||||
Exercised |
(812,573 | ) | $ | 13.20 | $ | 11.8 | ||||||||||
Shares under option — September 30, 2007 |
6,358,079 | $ | 19.65 | $ | 40.2 | 6.9 | ||||||||||
Options exercisable — September 30, 2005 |
2,093,821 | $ | 12.38 | |||||||||||||
Options exercisable — September 30, 2006 |
3,146,952 | $ | 14.56 | |||||||||||||
Options exercisable — September 30, 2007 |
3,568,746 | $ | 16.75 | $ | 32.9 | 6.0 | ||||||||||
Non-vested options — September 30, 2007 |
2,789,333 | $ | 23.36 | $ | 7.3 | 8.2 | ||||||||||
F-28
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Cash received from stock option exercises and associated tax benefits were
$10.7 and $4.0, $2.6 and $0.9, and $16.1 and $10.2 in fiscal 2007, 2006 and 2005,
respectively. As of September 30, 2007, there was $4.4 of unrecognized compensation cost
associated with unvested stock options that is expected to be recognized over a
weighted-average period of 1.9 years.
The following table presents additional information relating to stock options
outstanding and exercisable at September 30, 2007:
| Range of exercise prices | ||||||||||||
| $6.88 - | $12.57 - | $18.23 - | ||||||||||
| $10.63 | $17.01 | $27.90 | ||||||||||
Options outstanding at September 30, 2007: |
||||||||||||
Number of options |
421,700 | 1,917,476 | 4,018,903 | |||||||||
Weighted average remaining contractual life (in years) |
3.7 | 5.5 | 7.8 | |||||||||
Weighted average exercise price |
$ | 9.28 | $ | 15.00 | $ | 22.96 | ||||||
Options exercisable at September 30, 2007: |
||||||||||||
Number of options |
421,700 | 1,749,476 | 1,397,570 | |||||||||
Weighted average exercise price |
$ | 9.28 | $ | 14.94 | $ | 21.27 | ||||||
UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock
options granted under our option plans was $5.71 in fiscal 2007, $3.88 in fiscal 2006 and
$2.81 in fiscal 2005. These amounts were determined using a Black-Scholes option pricing
model which values options based on the stock price at the grant date, the expected life of
the option, the estimated volatility of the stock, expected dividend payments and the
risk-free interest rate over the expected life of the option. The expected life of option
awards represents the period of time during which option grants are expected to be
outstanding and is derived from historical exercise patterns. Expected volatility is based
on historical volatility of the price of UGI’s Common Stock. Expected dividend yield is
based on historical UGI dividend rates. The risk free interest rate is based on U.S.
Treasury bonds with terms comparable to the options in effect on the date of grant.
The assumptions we used for valuing option grants during fiscal 2007, 2006 and 2005 are
as follows:
| 2007 | 2006 | 2005 | ||||||||||
Expected life of option |
6 - 6.75 years | 6 years | 6 years | |||||||||
Weighted average volatility |
21.5 | % | 21.3 | % | 17.7 | % | ||||||
Weighted average dividend yield |
2.9 | % | 3.4 | % | 4.1 | % | ||||||
Expected volatility |
20.8%-21.5 | % | 21.2%-22.6 | % | 17.1%-17.8 | % | ||||||
Expected dividend yield |
2.8% - 2.9 | % | 2.8%-3.4 | % | 3.7%-4.2 | % | ||||||
Risk free rate |
4.3% - 4.7 | % | 4.3%-4.9 | % | 3.9%-4.3 | % | ||||||
UGI Unit Awards. UGI Stock and UGI Performance Unit awards entitle the grantee to
shares of UGI Common Stock or cash once the service condition is met and, with respect to
UGI Performance Unit awards, subject to market performance conditions. UGI Performance
Unit grant recipients are awarded a target number of Performance Units. The number of UGI
Performance Units ultimately paid at the end of the performance period (generally
three-year periods) may be higher or lower than the target amount, or even zero, based on
UGI’s Total Shareholder Return (“TSR”) percentile rank relative to companies in the
Standard & Poor’s Utilities Index (“UGI comparator group”). Based on the TSR percentile
rank, grantees may receive 0% to 200% of the target award granted. If UGI’s TSR ranks
below the 40th percentile compared to the UGI comparator group, the employee
will not receive an award. At the 40th percentile, the employee will be paid an
award equal to 50% of the target award; at the 50th percentile, 100%; and at the
100th percentile, 200%. The actual amount of the award is interpolated between
these percentile rankings. Dividend equivalents are paid in cash only on UGI Performance
Units that eventually vest.
The fair value of UGI Stock Units on the grant date is equal to the market price of UGI
Stock on the grant date. Under SFAS 123R, UGI Performance Units are equity awards with a
market-based condition which, if settled in shares, results in the recognition of
compensation cost over the requisite employee service period regardless of whether the
market-based condition is satisfied. The fair values of UGI Performance Units awarded
prior to fiscal 2006 are estimated using the intrinsic value method and accounted for as
liabilities. The fair value of UGI Performance Units awarded during fiscal 2006 and 2007
are estimated using a Monte Carlo valuation model. The fair value associated with the target award
is accounted for as equity and the fair value of the award over the target, as well as all
dividend equivalents, are accounted for as liabilities. The expected term of the UGI
Performance Unit awards is three years based on the performance period. Expected
volatility is based upon the historical volatility of UGI Common Stock over a three-year
period. The risk-free interest rate is based on the U.S Treasury yield at the time of
grant. Volatility for all comparator companies is based on historical volatility.
F-29
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The following table summarizes the weighted average assumptions used to determine the fair
value of UGI Performance Unit awards and related compensation costs:
| Grants Awarded in Fiscal | ||||||||
| 2007 | 2006 | |||||||
Risk-free rate |
4.7 | % | 5.2 | % | ||||
Expected life |
3 years | 3 years | ||||||
Expected volatility |
19.6 | % | 19.8 | % | ||||
Dividend yield |
2.6 | % | 2.8 | % | ||||
The weighted-average grant date fair value of UGI Performance Unit awards was
estimated to be $26.84 for Units granted in fiscal 2007 and $21.08 for Units granted in
fiscal 2006.
Based on the Company’s TSR during the associated three-year performance periods ended
December 31, during fiscal 2007 the Company paid 206,493 UGI Performance Unit awards,
including $2.8 paid in cash, associated with 193,600 awards granted in fiscal 2004; in
fiscal 2006 the Company paid 209,211 UGI Performance Unit awards, including $2.1 paid in
cash, associated with 168,500 awards granted in fiscal 2003; and in fiscal 2005, the
Company paid 927,000 UGI Performance awards, including $14.4 paid in cash, associated with
508,500 UGI Performance Unit awards granted in fiscal 2002. During fiscal 2007, 2006 and
2005, the Company paid Stock Unit awards and cash as follows: 2007 — 86,000 Stock Unit
awards including $1.1 in cash; 2006 — 20,000 Stock Unit awards including $0.2 in cash;
2005 — 8,400 Stock Unit awards including $0.1 in cash.
The following table summarizes UGI Unit award activity for fiscal 2007:
| Weighted-Average | ||||||||
| Number of | Grant Date Fair | |||||||
| UGI Units | Value (per Unit) | |||||||
Non-vested Units — September 30, 2006 |
435,078 | $ | 20.00 | |||||
Granted |
242,371 | $ | 26.78 | |||||
Forfeited |
(14,500 | ) | $ | 25.65 | ||||
Vested |
(271,180 | ) | $ | 21.20 | ||||
Non-vested Units — September 30, 2007 |
391,769 | $ | 23.04 | |||||
During fiscal 2007, 2006 and 2005, we granted UGI Unit awards representing
242,371, 187,326, and 286,230 shares, respectively, having weighted-average grant date fair
values per Unit of $26.78, $21.13 and $20.91, respectively. At September 30, 2007, UGI Unit
awards representing 879,000 shares of Common Stock were outstanding under the OECP and
predecessor equity-based compensation plans.
As of September 30, 2007, there was a total of approximately $5.0 of unrecognized
compensation cost associated with 879,000 UGI Unit awards outstanding that is expected to be
recognized over a weighted average period of 1.9 years. The total fair values of UGI Units
that vested during fiscal 2007, 2006, and 2005 were $6.9, $7.2 and $11.2, respectively. As
of September 30, 2007 and 2006, total liabilities of $7.9 and $13.9, respectively,
associated with UGI Unit awards are reflected in other current liabilities and other
noncurrent liabilities in the Consolidated Balance Sheets.
At September 30, 2007, 8,399,397 shares of Common Stock were available for future
grants under the OECP, of which up to 2,078,057 may be issued pursuant to grants other than
stock options or SARs.
AmeriGas Partners Equity-Based Compensation Plans and Awards. Under the AmeriGas Propane,
Inc. 2000 Long-Term Incentive Plan (“2000 Propane Plan”), the General Partner may award to
key employees the right to receive a total of 500,000 AmeriGas Partners Common Units
(comprising “AmeriGas Performance
Units”), or cash equivalent to the fair
market value of such Common Units. In addition, the 2000 Propane Plan authorizes the
crediting of Common Unit distribution equivalents to participants’ accounts. AmeriGas
Performance Unit grant recipients are awarded a target number of AmeriGas Performance Units.
The number of AmeriGas Performance Units ultimately paid at the end
of the performance period (generally three years) may be higher or lower than the
target amount based upon the performance of AmeriGas Partners Common Units as compared with
a peer group. Percentile rankings and payout percentages are generally the same as the UGI
Performance Unit awards. Any distribution equivalents earned are paid in cash. Generally,
each grant, unless paid, will terminate when the participant ceases to be employed by the
General Partner. There are certain change of control and retirement eligibility conditions
that, if met, generally result in accelerated vesting or elimination of further service
requirements.
F-30
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Under SFAS 123R, AmeriGas Performance Units are equity awards with a market-based
condition which, if settled in Common Units, results in the recognition of compensation
cost over the requisite employee service period
regardless of whether the market-based condition is satisfied. The fair value of AmeriGas
Performance Units awarded prior to fiscal 2006 are estimated using the intrinsic value
method and are accounted for as liabilities. The fair value of AmeriGas Performance
Units awarded during fiscal 2007 and 2006 are estimated using a Monte Carlo valuation model. The
fair value associated with the target award and the award above the
target, if any, is accounted for as equity and the fair value of
all distribution equivalents is accounted for as
a liability. The expected term of the AmeriGas Performance Unit awards is three years based
on the performance period. Expected volatility is based upon the historical volatility of
AmeriGas Partners Common Units over a three-year period. The risk-free interest rate is
based on the U.S Treasury yield at the time of grant. Volatility for all comparator
limited partnerships in the peer group is based on historical volatility.
The following table summarizes the weighted-average assumptions used to determine the fair
value of AmeriGas Performance Unit awards and related compensation costs:
| Grants Awarded in Fiscal | ||||||||
| 2007 | 2006 | |||||||
Risk-free rate |
4.7 | % | 5.2 | % | ||||
Expected life |
3 years | 3 years | ||||||
Expected volatility |
17.6 | % | 18.1 | % | ||||
Dividend yield |
7.1 | % | 7.7 | % | ||||
We also have a nonexecutive AmeriGas Partners Common Unit plan under which the General
Partner may grant awards of up to a total of 200,000 Common Units
(comprising “AmeriGas Units”) to key employees who do
not participate in the 2000 Propane Plan. Generally, awards under the nonexecutive plan vest
at the end of a three-year period and will be paid in Common Units and cash. The General
Partner made awards under the 2000 Propane Plan and the nonexecutive plan representing
49,650, 38,350 and 41,100 Common Units in fiscal 2007, 2006 and 2005, respectively, having
weighted-average grant date fair values per Common Unit of $33.63, $29.62 and $29.51,
respectively. At September 30, 2007 and 2006, awards representing 119,317 and 113,517 Common
Units, respectively, were outstanding. At September 30, 2007, 316,686 and 137,750 Common
Units were available for future grants under the 2000 Propane Plan and the nonexecutive
plan, respectively.
During fiscal 2007, the Partnership
paid 38,736 AmeriGas Partners Common Units, including $0.6 paid in cash, associated with 51,200
awards granted in fiscal 2004. During fiscal 2006, the Partnership paid 6,750 AmeriGas Partners
Common Units, including $0.1 paid in cash, associated with 43,500 awards granted in fiscal 2003.
During fiscal 2005, the Partnership paid 29,586 AmeriGas Partners Common Units, including $0.5
paid in cash, associated with 112,250 awards granted in fiscal 2003 and fiscal 2002.
The following table summarizes AmeriGas Unit and AmeriGas Performance Unit award
activity for fiscal 2007:
| Number of | Weighted-Average | |||||||
| AmeriGas Partners | Grant Date Fair | |||||||
| Common Units | Value (per Unit) | |||||||
Non-vested Units — September 30, 2006 |
93,900 | $ | 29.10 | |||||
Granted |
49,650 | $ | 33.63 | |||||
Forfeited |
(1,200 | ) | $ | 31.52 | ||||
Vested |
(31,698 | ) | $ | 28.64 | ||||
Performance criteria not met |
(3,918 | ) | $ | 28.02 | ||||
Non-vested Units — September 30, 2007 |
106,734 | $ | 30.61 | |||||
As of September 30, 2007, there was a total of approximately $1.8 of unrecognized
compensation cost associated with 119,317 AmeriGas Common Unit awards that is expected to be
recognized over a weighted average period of 1.8 years. The total fair values of Common
Units that vested during fiscal 2007, 2006, and 2005 were $1.2, $0.6 and $1.2, respectively.
As of September 30, 2007 and 2006, total liabilities of $1.8 and $2.2 associated with Common
Unit awards are reflected in other current liabilities and other noncurrent liabilities in
the Consolidated Balance Sheet.
F-31
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 9 — Partnership Distributions
The Partnership makes distributions to its partners approximately 45 days after the end of
each fiscal quarter in a total amount equal to its Available Cash for such quarter.
Available Cash generally means:
| 1. | all cash on hand at the end of such quarter, |
|
| 2. | plus all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter, |
|
| 3. | less the amount of cash reserves established by the General Partner in its reasonable discretion. |
The General Partner may establish reserves for the proper conduct of the
Partnership’s business and for distributions during the next four quarters. In addition,
certain of the Partnership’s debt agreements require reserves be established for the payment
of debt principal and interest.
Distributions of Available Cash are made 98% to limited partners and 2% to the General
Partner (representing a 1% General Partner interest in AmeriGas Partners and 1.01% interest
in AmeriGas OLP) until Available Cash exceeds the Minimum Quarterly Distribution of $0.55
and the First Target Distribution of $0.055 per Common Unit (or a total of $0.605 per Common
Unit). If Available Cash exceeds $0.605 per Common Unit in any quarter, the General Partner
will receive a greater percentage of the total Partnership distribution (the “incentive
distribution”) but only with respect to the amount by which the distribution per Common Unit
to limited partners exceeds $0.605. Accordingly, because the Partnership made distributions
to Common Unitholders of $0.61 per limited partner unit on May 18, 2007 and $0.86 per
limited partner unit on August 18, 2007 (which amount included a one-time $0.25 per limited
partner unit increase in the quarterly distribution associated with a portion of the
proceeds from the sale of the Partnership’s Arizona storage facility), the General Partner
received a greater percentage of the total Partnership distribution than its aggregate 2%
general partner interest in AmeriGas OLP and AmeriGas Partners. The General Partner
distribution based on its general partner ownership interest alone totaled $6.8 in fiscal
2007. The amount of the incentive distribution received by the General Partner during fiscal
2007 totaled $3.7.
As previously mentioned, on July 30, 2007, the General Partner’s Board of Directors approved
a distribution of $0.86 per Common Unit payable on August 18, 2007 to unitholders of record
on August 10, 2007. This distribution included the regular quarterly distribution of $0.61
per Common Unit and $0.25 per Common Unit reflecting a distribution of a portion of the
proceeds from the Partnership’s sale of its Arizona storage facility in July
2007.
Note 10 — Commitments and Contingencies
We lease various buildings and other facilities and transportation, computer and office
equipment under operating leases. Certain of our leases contain renewal and purchase options
and also contain step-rent provisions. Our aggregate rental expense for such leases was
$68.1 in fiscal 2007, $60.3 in fiscal 2006 and $55.1 in fiscal 2005.
Minimum future payments under operating leases that have initial or remaining
noncancelable terms in excess of one year are as follows:
| After | ||||||||||||||||||||||||
| 2008 | 2009 | 2010 | 2011 | 2012 | 2012 | |||||||||||||||||||
AmeriGas Propane |
$ | 46.5 | $ | 39.7 | $ | 34.4 | $ | 28.6 | $ | 22.5 | $ | 51.7 | ||||||||||||
UGI Utilities |
4.9 | 3.9 | 2.7 | 2.2 | 1.9 | 3.4 | ||||||||||||||||||
International Propane and other |
6.5 | 3.1 | 2.3 | 1.4 | 0.5 | 0.7 | ||||||||||||||||||
Total |
$ | 57.9 | $ | 46.7 | $ | 39.4 | $ | 32.2 | $ | 24.9 | $ | 55.8 | ||||||||||||
The Company’s businesses enter into contracts of varying lengths and terms to
meet their supply, pipeline transportation, storage, capacity and energy needs. Gas Utility
has gas supply agreements with producers and marketers with terms not exceeding one year.
Gas Utility also has agreements for firm pipeline transportation and natural gas storage
services, which Gas Utility may terminate at various dates through 2016. Gas Utility’s costs
associated with transportation and storage capacity agreements are included in its annual
PGC filing with the PUC and are recoverable through PGC rates. In addition, Gas Utility has
short-term gas supply agreements which permit it to purchase certain of its gas supply needs
on a firm or interruptible basis at spot-market prices. Electric Utility purchases its
energy needs under contracts with various suppliers and on the spot market. Contracts with
producers for energy needs expire at various dates through fiscal 2011. Energy Services
enters into fixed-price contracts with suppliers to purchase natural gas to meet its sales
commitments. Generally, these contracts have terms of less than two years. The Partnership
enters into fixed-price and, from time to time, variable-priced contracts to purchase a
portion of its supply requirements. These contracts generally have terms of less than one
year. International Propane,
particularly Antargaz, enters into variable-priced contracts to purchase a portion of its
supply requirements. Generally, these contracts have terms that do not exceed three years.
F-32
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The following table presents contractual obligations under Gas Utility, Electric
Utility, Energy Services, AmeriGas Propane and International Propane supply, storage and
service contracts existing at September 30, 2007:
| After | ||||||||||||||||||||||||
| 2008 | 2009 | 2010 | 2011 | 2012 | 2012 | |||||||||||||||||||
Gas Utility and Electric Utility
supply, storage and transportation
contracts |
$ | 478.9 | $ | 189.9 | $ | 103.6 | $ | 73.4 | $ | 52.1 | $ | 121.6 | ||||||||||||
Energy Services supply contracts |
462.6 | 47.3 | — | — | — | — | ||||||||||||||||||
AmeriGas Propane supply contracts |
25.8 | — | — | — | — | — | ||||||||||||||||||
International Propane supply contracts |
61.7 | 47.0 | — | — | — | — | ||||||||||||||||||
Total |
$ | 1,029.0 | $ | 284.2 | $ | 103.6 | $ | 73.4 | $ | 52.1 | $ | 121.6 | ||||||||||||
The Partnership and International Propane also enter into other contracts to
purchase LPG to meet supply requirements. Generally, these contracts are one- to three-year
agreements subject to annual review and call for payment based on either market prices at
date of delivery or fixed prices.
On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired the propane
distribution businesses of Columbia Energy Group (the “2001 Acquisition”) pursuant to the
terms of a purchase agreement (the “2001 Acquisition Agreement”) by and among Columbia
Energy Group (“CEG”), Columbia Propane Corporation (“Columbia Propane”), Columbia Propane,
L.P. (“CPLP”), CP Holdings, Inc. (“CPH,” and together with Columbia Propane and CPLP, the
“Company Parties”), AmeriGas Partners, AmeriGas OLP and the General Partner (together with
AmeriGas Partners and AmeriGas OLP, the “Buyer Parties”). As a result of the 2001
Acquisition, AmeriGas OLP acquired all of the stock of Columbia Propane and CPH and
substantially all of the partnership interests of CPLP. Under the terms of an earlier
acquisition agreement (the “1999 Acquisition Agreement”), the Company Parties agreed to
indemnify the former general partners of National Propane Partners, L.P. (a predecessor
company of the Columbia Propane businesses) and an affiliate (collectively, “National
General Partners”) against certain income tax and other losses that they may sustain as a
result of the 1999 acquisition by CPLP of National Propane Partners, L.P. (the “1999
Acquisition”) or the operation of the business after the 1999 Acquisition (“National
Claims”). At September 30, 2007, the potential amount payable under this indemnity by the
Company Parties was approximately $58.0. These indemnity obligations will expire on the date
that CPH acquires the remaining outstanding partnership interest of CPLP, which is expected
to occur on or after July 19, 2009. Under the terms of the 2001 Acquisition Agreement, CEG
agreed to indemnify the Buyer Parties and the Company Parties against any losses that they
sustain under the 1999 Acquisition Agreement and related agreements (“Losses”), including
National Claims, to the extent such claims are based on acts or omissions of CEG or the
Company Parties prior to the 2001 Acquisition. The Buyer Parties agreed to indemnify CEG
against Losses, including National Claims, to the extent such claims are based on acts or
omissions of the Buyer Parties or the Company Parties after the 2001 Acquisition. CEG and
the Buyer Parties have agreed to apportion certain losses resulting from National Claims to
the extent such losses result from the 2001 Acquisition itself.
Samuel and Brenda Swiger and their son (the “Swigers”) sustained personal injuries and
property damage as a result of a fire that occurred when propane that leaked from an
underground line ignited. In July 1998, the Swigers filed a class action lawsuit against
AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of
Monongalia County, West Virginia, in which they sought to recover an unspecified amount of
compensatory and punitive damages and attorney’s fees, for themselves and on behalf of
persons in West Virginia for whom the defendants had installed propane gas lines, resulting
from the defendants’ alleged failure to install underground propane lines at depths required
by applicable safety standards. In 2003, AmeriGas OLP settled the individual personal injury
and property damage claims of the Swigers. In 2004, the court granted the plaintiffs’ motion
to include customers acquired from Columbia Propane in August 2001 as additional potential
class members and the plaintiffs amended their complaint to name additional parties pursuant
to such ruling. Subsequently, in March 2005, AmeriGas OLP filed a crossclaim against CEG,
former owner of Columbia Propane, seeking indemnification for conduct undertaken by Columbia
Propane prior to AmeriGas OLP’s acquisition. Class counsel has indicated that the class is
seeking compensatory damages in excess of $12 plus punitive damages, civil penalties and
attorneys’ fees. We believe we have good defenses to the claims of the class members and
intend to defend against the remaining claims in this lawsuit.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries
owned and operated a number of manufactured gas plants (“MGPs”) prior to the general
availability of natural gas. Some constituents of coal tars and other residues of the
manufactured gas process are today considered hazardous substances under the Superfund Law
and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned
the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the
businesses of some gas companies under agreement. Pursuant to the requirements of the Public
Utility Holding Company Act of 1935, UGI Utilities divested all of its utility operations
other than those which now constitute UGI Gas and Electric Utility by
the early 1950s.
UGI Utilities does not expect its costs for investigation and remediation of hazardous
substances at Pennsylvania MGP sites to be material to its results of operations because UGI
Gas is currently permitted to include in rates, through future base rate proceedings, a
five-year average of such prudently incurred remediation costs. In
accordance with the terms of the PNG base rate case order which
became effective December 2, 2006, site-specific environmental investigation and remediation
costs associated with PNG Gas incurred prior to December 2, 2006 are amortized as removal
costs over five-year periods. Such costs incurred after December 1, 2006 are expensed as
incurred.
As a result of the acquisition of PG Energy by UGI Utilities’ wholly-owned subsidiary,
UGIPNG, UGIPNG became party to a Multi-Site Remediation Consent Order and Agreement between
PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004
(“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform annually a
specified level of activities associated with environmental investigation and remediation
work at 11 currently owned properties on which MGP-related facilities were operated
(“Properties”). Under the Multi-Site Agreement,
environmental expenditures, including costs to perform work on the
Properties, are capped at $1.1 million in any calendar year. Costs related to investigation and remediation of one property
formerly owned by UGIPNG are also included in this cap. The Multi-Site Agreement terminates
in 2019 but may be terminated by either party effective at the end of any two-year period
beginning with the original effective date.
UGI Utilities has been notified of several sites outside Pennsylvania on which private
parties allege MGPs were formerly owned or operated by it or owned or operated by its former
subsidiaries. Such parties are investigating the extent of environmental contamination or
performing environmental remediation. UGI Utilities is currently litigating four claims
against it relating to out-of-state sites. We accrue environmental investigation and cleanup
costs when it is probable that a liability exists and the amount or range of amounts can be
reasonably estimated.
Management believes that under applicable law UGI Utilities should not be liable in
those instances in which a former subsidiary owned or operated an MGP. There could be,
however, significant future costs of an uncertain amount associated with environmental
damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that
were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude
that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities
should be considered to have been an operator because of its conduct with respect to its
subsidiary’s MGP.
South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006,
South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a
lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution
from UGI Utilities for past and future remediation costs related to the operations of a
former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from
1855 to 1954 and alleges that UGI Utilities controlled operations of the plant from 1910 to
1926 and is liable for 47% of the costs associated with the site. SCE&G asserts that it has
spent approximately $22 in remediation costs and $26 in third-party claims relating to the
site and estimates that future remediation costs could be as high as $2.5. SCE&G further
asserts that it has received a demand from the United States Justice Department for natural
resource damages. UGI Utilities is defending the suit.
City of Bangor, Maine v. Citizens Communications Company. In April 2003, Citizens
Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party
defendant in a civil action pending in the United States District Court for the District of Maine.
In that action, the plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover
environmental response costs associated with MGP wastes generated at a plant allegedly
operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently
joined UGI Utilities and ten other third-party defendants alleging that the third-party
defendants are responsible for an equitable share of costs Citizens may be required to pay
to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that UGI
Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies
conducted by the City and Citizens suggest that it could cost up to $18 to clean up the
river. Citizens’ third-party claims have been stayed pending a resolution of the City’s suit
against Citizens, which was tried in September 2005. Maine’s Department of Environmental
Protection (“DEP”) informed UGI Utilities in March 2005 that it considers UGI Utilities to
be a potentially responsible party for costs incurred by the State of Maine related to gas
plant contaminants at this site. On June 27,
2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs.
On February 14, 2007, Citizens and the City entered into a Settlement agreement pursuant to
which Citizens agreed to pay $7.6 in exchange for a release of its liabilities. UGI
Utilities believes that it has good defenses to any claim that the DEP may bring to recover
its costs, and is defending the Citizens’ suit.
F-34
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Consolidated Edison Company of New York v. UGI Utilities, Inc. On September 20, 2001,
Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the
United States District Court for the Southern District of New York, seeking contribution
from UGI Utilities for an allocated share of response costs associated with investigating
and assessing gas plant related contamination at former MGP sites in Westchester County, New
York. The complaint alleges that UGI Utilities “owned and operated” the MGPs prior to 1904.
The complaint also seeks a declaration that UGI Utilities is responsible for an allocated
percentage of future investigative and remedial costs at the sites.
The trial court granted UGI Utilities’ motion for summary judgment and dismissed
ConEd’s complaint. The grant of summary judgment was entered April 1, 2004. ConEd appealed
and on September 9, 2005 a panel of the Second Circuit Court of Appeals affirmed in part and
reversed in part the decision of the trial court. The appellate panel affirmed the trial
court’s decision dismissing claims that UGI Utilities was liable under CERCLA as an operator
of MGPs owned and operated by its former subsidiaries. The appellate panel reversed the
trial court’s decision that UGI Utilities was released from liability at three sites where
UGI Utilities operated MGPs under lease. ConEd claims that the cost of remediation for the
three sites would be approximately $14. On October 7, 2005, UGI Utilities filed for
reconsideration of the panel’s order, which was denied by the Second Circuit Court of
Appeals on January 17, 2006. On April 14, 2006, Utilities filed a petition requesting that
the United States Supreme Court review the decision of the Second Circuit Court of Appeals.
On June 18, 2007, the United States Supreme Court denied UGI
Utilities petition. The case has now been remanded back to the trial
court. UGI
Utilities is defending the suit.
Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”)
informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean
up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is
responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged
direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006,
KeySpan reported that the New York Department of Environmental Conservation has approved a
remedy for the site that is estimated to cost approximately $10. KeySpan believes that the
cost could be as high as $20. UGI Utilities is in the process of reviewing the information
provided by KeySpan and is investigating this claim.
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities,
Inc.On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services
Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities,
(together the “Northeast Companies”) in the United States District Court for the District of
Connecticut seeking contribution from UGI Utilities for past and future remediation costs
related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities
in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled
operations of the plants from 1883 to 1941. The Northeast Companies estimated that
remediation costs for all of the sites would total approximately $215 and asserted that UGI
Utilities is responsible for approximately $103 of this amount. Based on information
supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities
believes that it may have operated one of the sites, Waterbury North, under lease for a
portion of its operating history. UGI Utilities is reviewing the Northeast Companies’
estimate that remediation costs at Waterbury North could total $23. UGI Utilities is
defending the suit.
French tax authorities levy various taxes on legal entities and individuals regularly
operating a business in France which are commonly referred to collectively as “business
tax.” The amount of business tax charged annually is generally dependent upon the value of
the entity’s tangible fixed assets. Prior to the Antargaz Acquisition, Antargaz filed suit
against French tax authorities in connection with the assessment of business tax related to
certain of its owned tanks at customer locations. Elf Antar France and Elf Aquitaine, now
Total France, former owners of Antargaz, agreed to indemnify Antargaz for all payments which
would have been due from Antargaz in respect of the tax related to its tanks for the period
from January 1, 1997 through December 31, 2000. During the year ended September 30, 2005,
Antargaz was required to remit payment to the French tax authorities with respect to this
matter and Antargaz was fully reimbursed pursuant to the indemnity agreement. At September
30, 2007, the remaining amount subject to the indemnification is immaterial.
On February 4, 2005, Antargaz received a letter that was issued by the French
government to the French Committee of Butane and Propane (“CFBP”), a butane/propane industry
group, concerning the business tax, that eliminated the requirement for Antargaz to pay
business tax associated with tanks at certain customer locations. In addition, during 2005,
resolution was reached relating to business taxes relating to a prior year. Further changes
in the French government or tax authorities’ interpretation of the tax laws or in the tax
laws themselves, could have either an adverse or a favorable effect on our results of
operations. Our 2005 Statement of Income includes a pre-tax gain of $18.8 and net after-tax
gain of $14.2 associated with the resolution of business tax matters related principally to
prior years.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
In addition to these matters, there are other pending claims and legal actions arising
in the normal course of our businesses. We cannot predict with certainty the final results
of environmental and other matters. However, it is reasonably possible that some of them
could be resolved unfavorably to us and result in losses in excess of recorded amounts. We
are unable to estimate any possible losses in excess of recorded amounts. Although we
currently believe, after consultation with counsel, that damages or settlements, if any,
recovered by the plaintiffs in such claims or actions will not have a material adverse
effect on our financial position, damages or settlements could be material to our operating
results or cash flows in future periods depending on the nature and timing of future
developments with respect to these matters and the amounts of future operating results and
cash flows.
Note 11 — Financial Instruments
In accordance with its commodity hedging policy, the Partnership uses derivative
instruments, including price swap and option contracts and contracts for the forward sale of
propane, to manage the cost of a portion of its forecasted purchases of propane and to
manage market risk associated with propane storage inventories. These derivative instruments
have been designated by the Partnership as cash flow or fair value hedges under SFAS 133.
The fair values of these derivative instruments are affected by changes in propane product
prices. In addition to these derivative instruments, the Partnership may also enter into
contracts for the forward purchase of propane as well as fixed-price supply agreements to
manage propane market price risk. These contracts generally qualify for the normal purchases
and normal sales exception of SFAS 133 and therefore are not adjusted to fair value.
Flaga also uses derivative instruments, principally price swap contracts, to reduce
market risk associated with purchases of LPG. These contracts may or may not qualify for
hedge accounting under SFAS 133. Antargaz uses forward foreign exchange contracts and may
use other derivative instruments, similar to those used by the Partnership, to manage the
cost of a portion of its forecasted purchases of LPG.
Energy Services uses exchange-traded and over-the-counter natural gas futures contracts
to manage market risk associated with forecasted purchases of natural gas it sells under
firm commitments and forecasted sales at market prices. In addition, Energy Services uses
price swap and option contracts to manage market risk associated with forecasted purchases
of propane it sells under firm commitments. These derivative instruments are designated as
cash flow hedges. The fair values of these futures and swap and option contracts are
affected by changes in natural gas and propane prices.
In accordance with its commodity hedging policy, Gas Utility may enter into natural gas
call option and futures contracts to reduce volatility in the cost of gas it purchases for
its firm-residential, commercial and industrial (“retail core-market”) customers and
Electric Utility may enter into electric swap agreements in order to reduce the volatility
in the cost of anticipated electricity requirements. Because the cost of the natural gas
option and futures contracts and any associated losses or gains are included in Gas
Utility’s PGC recovery mechanism, as these contracts are marked to fair value in accordance
with SFAS 133, any losses or gains are deferred for future recovery from or refund to Gas
Utility’s ratepayers.
We enter into interest rate protection agreements (“IRPAs”) designed to manage interest
rate risk associated with planned issuances of fixed-rate long-term debt. We designate these
IRPAs as cash flow hedges. Gains or losses on IRPAs are included in accumulated other
comprehensive income and are reclassified to interest expense as the interest expense on the
associated debt affects earnings. Antargaz has entered into interest rate swap agreements
to fix the variable interest component of its Senior Facilities term loan through March
2011. Flaga has entered into an interest rate swap agreement to fix the variable interest
component of substantially all of its term loan through September 2011.
We are also a party to a number of contracts that have elements of a derivative instrument.
These contracts include, among others, binding purchase orders, contracts which provide for
the purchase and delivery of natural gas and electricity, and service contracts that require
the counterparty to provide commodity storage, transportation or capacity service to meet
our normal sales commitments. Although many of these contracts have the requisite elements
of a derivative instrument, these contracts are not subject to the accounting requirements
of SFAS 133 because they provide for the delivery of products or services in quantities that
are expected to be used in the normal course of operating our business or the value of the
contract is directly associated with the price or value of a service.
During fiscal 2007, 2006 and 2005, amounts recognized in earnings representing cash
flow hedge ineffectiveness were not material. Gains and losses included in accumulated
other comprehensive income at September 30, 2007 relating to cash flow hedges will be
reclassified into (1) cost of sales when the forecasted purchase or sale of LPG, natural gas
or electricity subject to the hedges impacts net income and (2) interest expense when
interest on anticipated issuances of fixed-rate long-term debt or interest expense on
variable rate debt subject to interest rate swaps is reflected in net income. Included in
accumulated other comprehensive income at September 30, 2007 are net after-tax losses of
approximately $7.0 from settled IRPAs and IRPAs associated with forecasted issuances of debt anticipated to
occur during fiscal 2009 and 2010. The amount of this net loss that
is expected to be reclassified into net income during the next twelve months is not
material. Also included in accumulated other
F-36
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
comprehensive income at September 30, 2007 are (1) net after-tax losses of approximately
$1.3 principally associated with future purchases of natural gas and propane generally
anticipated to occur during the next twelve months, (2) net after-tax gains of approximately
$0.5 associated with future electric supply purchases expected to occur through December
2007, (3) net after-tax gains of $13.6 associated with International Propane interest rate
swaps, and (4) net after-tax losses of $5.3 associated with forecasted U.S.
dollar-denominated purchases of LPG by our International Propane businesses generally
anticipated to occur during the next three years. The amount of the losses that is expected
to be reclassified into net income during the next twelve months associated with the U.S.
dollar-denominated purchases is not material. The actual amount of gains or losses on
unsettled derivative instruments that ultimately is reclassified into net income will depend
upon the value of such derivative contracts when settled. The fair value of the long-term
portion of unsettled derivative instruments is included in Other assets and Other
noncurrent liabilities in the Consolidated Balance Sheets.
The primary currency for which the Company has exchange rate risk is the euro. The U.S.
dollar value of our foreign-denominated assets and liabilities will fluctuate with changes
in the associated foreign currency exchange rates. We use derivative instruments to hedge
portions of our net investments in foreign subsidiaries. If a derivative is designated as a
hedge of an investment in a foreign subsidiary and qualifies for hedge accounting, any
realized gains or losses remain in other comprehensive income until such foreign operations
have been liquidated. At September 30, 2007, a net after-tax loss of $4.9 is included in
accumulated other comprehensive income associated with settled and unsettled net investment
hedges.
The carrying amounts of financial instruments included in current assets and current
liabilities (excluding unsettled derivative instruments and current maturities of long-term
debt) approximate their fair values because of their short-term nature. The carrying amounts
and estimated fair values of our remaining financial instruments (including unsettled
derivative instruments) at September 30, 2007 and 2006 are as follows:
| Carrying | Estimated | |||||||
| Amount | Fair Value | |||||||
2007: |
||||||||
Natural gas futures and options contracts |
$ | (1.4 | ) | $ | (1.4 | ) | ||
Electric supply swap |
0.8 | 0.8 | ||||||
Propane swap and option contracts |
18.3 | 18.3 | ||||||
Interest rate protection and swap agreements |
21.3 | 21.3 | ||||||
Foreign currency forward contracts |
(14.7 | ) | (14.7 | ) | ||||
Long-term debt |
2,053.5 | 2,037.6 | ||||||
2006: |
||||||||
Natural gas futures and options contracts |
$ | (6.0 | ) | $ | (6.0 | ) | ||
Electric supply swap |
5.2 | 5.2 | ||||||
Propane swap and option contracts |
(26.4 | ) | (26.4 | ) | ||||
Interest rate protection and swap agreements |
14.4 | 14.4 | ||||||
Foreign currency forward contracts |
2.4 | 2.4 | ||||||
Long-term debt |
1,996.9 | 2,006.8 | ||||||
We estimate the fair value of long-term debt by using current market prices
and by discounting future cash flows using rates available for similar type debt. Fair
values of derivative instruments reflect the estimated amounts that we would receive or pay
to terminate the contracts at the reporting date based upon quoted market prices of
comparable contracts at September 30, 2007 and 2006.
We have financial instruments, such as short-term investments and trade accounts
receivable, which could expose us to concentrations of credit risk. We limit our credit risk
from short-term investments by investing only in investment-grade commercial paper, money
market mutual funds and securities guaranteed by the U.S. Government or its agencies. The
credit risk from trade accounts receivable is limited because we have a large customer base,
which extends across many different U.S. markets and several foreign countries. We attempt
to minimize the credit risk associated with our derivative financial instruments through the
application of credit policies.
Note 12 — Energy Services Accounts Receivable Securitization Facility
UGI Energy Services, Inc. (“ESI”) has a $200 receivables purchase facility (“Receivables
Facility”) with an issuer of receivables-backed commercial paper expiring in April 2009,
although the Receivables Facility may terminate prior to
such date due to the termination of commitments of the Receivables Facility’s back-up
purchasers. Prior to September 2006, ESI’s Receivables Facility was $150.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Under the Receivables Facility, ESI transfers, on an ongoing basis and without
recourse, its trade accounts receivable to its wholly owned, special-purpose subsidiary,
Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement
purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time
sell, an undivided interest in the receivables to a commercial paper conduit of a major
bank. ESFC was created and has been structured to isolate its assets from creditors of ESI
and its affiliates, including UGI. This two-step transaction is accounted for as a sale of
receivables following the provisions of SFAS No. 140, “Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities.” ESI continues to service,
administer and collect trade receivables on behalf of the commercial paper issuer and ESFC.
During fiscal 2007, 2006 and 2005, ESI sold trade receivables totaling $1,241.0, $1,306.0
and $1,253.6, respectively, to ESFC. During fiscal 2007, 2006 and 2005, ESFC sold an
aggregate $495.5, $859.5 and $475.5, respectively, of undivided interests in its trade
receivables to the commercial paper conduit. At September 30, 2007, the outstanding balance
of ESFC trade receivables was $65.7 which is net of $16 that was sold to the commercial
paper conduit and removed from the balance sheet. At September 30, 2006, the outstanding
balance of ESFC trade receivables was $24.1 which is net of $60.5 that was sold to the
commercial paper conduit and removed from the balance sheet. Losses on sales of receivables
to the commercial paper conduit that occurred during fiscal 2007, 2006 and 2005 , which are
included in Other income, net, were $1.5, $3.3, and $0.9, respectively.
In addition, a major bank has committed to issue up to $50 of standby letters of credit,
secured by cash or marketable securities (“LC Facility”). Energy Services expects to fund
the collateral requirements with borrowings under its Receivables Facility. The LC Facility
expires April 2008.
Note 13 — Other Income, Net
Other income (loss), net, comprises the following:
| 2007 | 2006 | 2005 | ||||||||||
Interest and interest-related income |
$ | 11.5 | $ | 15.8 | $ | 6.3 | ||||||
Utility non-tariff service income |
5.1 | 1.0 | 1.3 | |||||||||
Gain (loss) on sales of fixed assets |
0.5 | (0.1 | ) | 3.4 | ||||||||
Gain on sale of Energy Ventures |
— | 9.1 | — | |||||||||
Gain on Partnership sale of storage facility |
46.1 | — | — | |||||||||
Finance charges |
10.2 | 8.4 | 7.6 | |||||||||
French business tax reversal |
— | — | 19.9 | |||||||||
Other |
4.5 | 2.6 | 8.2 | |||||||||
Total other income, net |
$ | 77.9 | $ | 36.8 | $ | 46.7 | ||||||
Note 14 — AmeriGas Partners Common Unit Issuances
In September 2007, in conjunction with a propane business acquisition, the Partnership
issued 166,205 Common Units to the General Partner having a fair value of $5.7.
In September 2005, AmeriGas Partners sold 2,300,000 Common Units in an underwritten
public offering at a public offering price of $33.00 per Common Unit. The net proceeds of the
public offering totaling $72.7 and the associated capital contributions from the General
Partner totaling $1.5 were contributed to AmeriGas OLP, and used to reduce indebtedness
under its bank credit agreement and for general partnership purposes. Concurrent with this
sale of Common Units, the Company recorded a gain in the amount of $28.0 which is reflected
in the Company’s balance sheet as an increase in common stockholders’ equity and a
corresponding decrease in minority interests in AmeriGas Partners in accordance with the
guidance in SAB 51. The gain had no effect on the Company’s net income or cash flow. Total
deferred income tax liabilities of $16.0 associated with this gain with a corresponding
decrease to common stockholders’ equity were also recorded and reflected in the Consolidated
Balance Sheet.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 15 — Quarterly Data (unaudited)
The following unaudited quarterly data includes adjustments (consisting only of normal
recurring adjustments) which we consider necessary for a fair presentation unless otherwise
indicated. Our quarterly results fluctuate because of the seasonal nature of our businesses.
| December 31, | March 31 | June 30, | September 30, | |||||||||||||||||||||||||||||
| 2006 | 2005 | 2007 | 2006(a) | 2007 | 2006(b) | 2007(c) | 2006 | |||||||||||||||||||||||||
Revenues |
$ | 1,463.2 | $ | 1,577.9 | $ | 2,002.1 | $ | 1,845.5 | $ | 1,076.8 | $ | 919.1 | $ | 934.8 | $ | 878.5 | ||||||||||||||||
Operating income |
$ | 167.3 | $ | 160.2 | $ | 300.5 | $ | 262.6 | $ | 51.6 | $ | 38.5 | $ | 61.9 | $ | 6.4 | ||||||||||||||||
Income (loss) from
equity investees |
$ | — | $ | (0.6 | ) | $ | (1.3 | ) | $ | (0.6 | ) | $ | (0.9 | ) | $ | — | $ | 1.6 | $ | (1.0 | ) | |||||||||||
Net income (loss) |
$ | 61.9 | $ | 57.5 | $ | 120.2 | $ | 104.0 | $ | 11.5 | $ | 18.7 | $ | 10.7 | $ | (4.0 | ) | |||||||||||||||
Earnings (loss) per share: |
||||||||||||||||||||||||||||||||
Basic |
$ | 0.58 | $ | 0.55 | $ | 1.13 | $ | 0.99 | $ | 0.11 | $ | 0.18 | $ | 0.10 | $ | (0.04 | ) | |||||||||||||||
Diluted |
$ | 0.58 | $ | 0.54 | $ | 1.12 | $ | 0.98 | $ | 0.11 | $ | 0.18 | $ | 0.10 | $ | (0.04 | ) | |||||||||||||||
| (a) | Includes a gain on the sale of our 50% ownership interest in
Energy Ventures which increased operating income by $9.1 and net
income by $5.3 or $0.05 per diluted share, and a loss on early
extinguishments of AmeriGas Propane’s debt which decreased net
income by $4.6 or $0.04 per diluted share. |
|
| (b) | Includes the effects of changes in management’s estimate of taxes
to be paid associated with planned repatriation of foreign
earnings which increased net income by approximately $5.0 or $0.05
per diluted share. |
|
| (c) | Includes a gain from sale of the Partnership’s 3.5 million barrel underground
storage terminal which increased
operating income by $46.1 and net income by $12.5 or $0.12 per diluted share. |
Note 16 — Segment Information
We have organized our business units into six reportable segments generally based upon
products sold, geographic location (domestic or international) and regulatory environment.
Our reportable segments are: (1) AmeriGas Propane; (2) an international LPG segment
comprising Antargaz; (3) an international LPG segment comprising Flaga and our international
propane equity investments (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Energy
Services. We refer to both international segments collectively as “International Propane.”
AmeriGas Propane derives its revenues principally from the sale of propane and related
equipment and supplies to retail customers from locations in 46 states. Our International
Propane segments’ revenues are derived principally from the distribution of LPG to retail
customers in France and Austria. Gas Utility’s revenues are derived principally from the
sale and distribution of natural gas to customers in eastern and northeastern Pennsylvania.
Electric Utility derives its revenues principally from the distribution of electricity in
two northeastern Pennsylvania counties. Energy Services revenues are derived from the sale
of natural gas and, to a lesser extent, LPG, electricity and fuel oil to customers located
primarily in the Eastern United States.
The accounting policies of our reportable segments are the same as those described in
Note 1. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s
earnings before interest expense, income taxes, depreciation and amortization (“Partnership
EBITDA”). Although we use Partnership EBITDA to evaluate AmeriGas Propane’s profitability,
it should not be considered as an alternative to net income (as an indicator of operating
performance) or as an alternative to cash flow (as a measure of liquidity or ability to
service debt obligations) and is not a measure of performance or financial condition under
accounting principles generally accepted in the United States of America. The Company’s
definition of Partnership EBITDA may be different from that used by other companies. We
evaluate the performance of our International Propane, Gas Utility, Electric Utility and
Energy Services segments principally based upon their income (loss) before income taxes.
No single customer represents more than ten percent of our consolidated revenues. In
addition, all of our reportable segments’ revenues, other than those of our International
Propane segments, are derived from sources within the United States, and all of our
reportable segments’ long-lived assets, other than those of our International Propane
segments, are located in the United States.
F-39
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Financial information by reportable business segment follows:
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| Elim- | AmeriGas | Gas | Electric | Energy | International Propane | Corporate | ||||||||||||||||||||||||||||||
| Total | inations | Propane | Utility | Utility | Services | Antargaz | Other (b) | & Other (c) | ||||||||||||||||||||||||||||
2007 |
||||||||||||||||||||||||||||||||||||
Revenues |
$ | 5,476.9 | $ | (197.3 | ) (d) | $ | 2,277.4 | $ | 1,044.9 | $ | 121.9 | $ | 1,336.1 | $ | 759.2 | $ | 41.2 | $ | 93.5 | |||||||||||||||||
Cost of sales |
$ | 3,730.8 | $ | (193.8 | ) (d) | $ | 1,437.2 | $ | 741.5 | $ | 67.8 | $ | 1,235.2 | $ | 366.7 | $ | 21.9 | $ | 54.3 | |||||||||||||||||
Operating income |
$ | 581.3 | $ | — | $ | 265.8 | $ | 136.6 | $ | 26.0 | $ | 57.4 | $ | 94.5 | $ | — | $ | 1.0 | ||||||||||||||||||
Loss from equity investees |
(3.8 | ) | — | — | — | — | — | (1.8 | ) | (2.0 | ) | — | ||||||||||||||||||||||||
Interest expense |
(139.6 | ) | — | (71.5 | ) | (39.9 | ) | (2.4 | ) | — | (23.1 | ) | (2.1 | ) | (0.6 | ) | ||||||||||||||||||||
Minority interests |
(106.9 | ) | (0.2 | ) | (105.3 | ) | — | — | — | (1.4 | ) | — | — | |||||||||||||||||||||||
Income (loss) before income taxes |
$ | 331.0 | $ | (0.2 | ) | $ | 89.0 | $ | 96.7 | $ | 23.6 | $ | 57.4 | $ | 68.2 | $ | (4.1 | ) | $ | 0.4 | ||||||||||||||||
Depreciation and amortization |
$ | 169.2 | $ | — | $ | 75.7 | $ | 37.4 | $ | 3.5 | $ | 6.9 | $ | 41.5 | $ | 3.4 | $ | 0.8 | ||||||||||||||||||
Partnership EBITDA (a) |
$ | 338.7 | ||||||||||||||||||||||||||||||||||
Total assets |
$ | 5,502.7 | $ | (358.1 | ) | $ | 1,708.4 | $ | 1,531.2 | $ | 102.9 | $ | 254.9 | $ | 1,648.9 | $ | 196.8 | $ | 417.7 | |||||||||||||||||
Capital expenditures |
$ | 223.1 | $ | — | $ | 73.8 | $ | 66.2 | $ | 7.2 | $ | 10.7 | $ | 61.8 | $ | 2.5 | $ | 0.9 | ||||||||||||||||||
Investments in equity investees |
$ | 63.9 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 63.9 | $ | — | ||||||||||||||||||
Goodwill |
$ | 1,498.8 | $ | (4.0 | ) | $ | 645.1 | $ | 162.3 | $ | — | $ | 11.8 | $ | 630.3 | $ | 46.3 | $ | 7.0 | |||||||||||||||||
2006 |
||||||||||||||||||||||||||||||||||||
Revenues |
$ | 5,221.0 | $ | (156.1 | ) (d) | $ | 2,119.3 | $ | 724.0 | $ | 98.0 | $ | 1,414.3 | $ | 881.9 | $ | 63.6 | $ | 76.0 | |||||||||||||||||
Cost of sales |
$ | 3,657.9 | $ | (152.3 | ) (d) | $ | 1,343.8 | $ | 522.9 | $ | 51.0 | $ | 1,328.2 | $ | 478.4 | $ | 38.8 | $ | 47.1 | |||||||||||||||||
Operating income |
$ | 467.7 | $ | — | $ | 184.1 | $ | 84.2 | $ | 20.7 | $ | 53.1 | $ | 115.4 | $ | 3.9 | $ | 6.3 | ||||||||||||||||||
Loss from equity investees |
(2.2 | ) | — | — | — | — | — | (1.6 | ) | (0.6 | ) | — | ||||||||||||||||||||||||
Loss on extinguishments of debt |
(18.5 | ) | — | (17.1 | ) | — | — | — | (1.4 | ) | — | — | ||||||||||||||||||||||||
Interest expense |
(123.6 | ) | — | (74.1 | ) | (21.8 | ) | (2.5 | ) | — | (23.1 | ) | (1.7 | ) | (0.4 | ) | ||||||||||||||||||||
Minority interests |
(48.7 | ) | (0.4 | ) | (51.3 | ) | — | — | — | 3.0 | — | — | ||||||||||||||||||||||||
Income before income taxes |
$ | 274.7 | $ | (0.4 | ) | $ | 41.6 | $ | 62.4 | $ | 18.2 | $ | 53.1 | $ | 92.3 | $ | 1.6 | $ | 5.9 | |||||||||||||||||
Depreciation and amortization |
$ | 148.7 | $ | — | $ | 72.5 | $ | 23.3 | $ | 3.3 | $ | 6.7 | $ | 38.2 | $ | 3.9 | $ | 0.8 | ||||||||||||||||||
Partnership EBITDA (a) |
$ | 237.9 | ||||||||||||||||||||||||||||||||||
Total assets |
$ | 5,080.5 | $ | (340.7 | ) | $ | 1,627.2 | $ | 1,504.3 | $ | 105.3 | $ | 238.5 | $ | 1,406.8 | $ | 183.4 | $ | 355.7 | |||||||||||||||||
Capital expenditures |
$ | 191.7 | $ | — | $ | 70.7 | $ | 49.2 | $ | 9.0 | $ | 7.0 | $ | 47.9 | $ | 7.6 | $ | 0.3 | ||||||||||||||||||
Investments in equity investees |
$ | 58.2 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 58.2 | $ | — | ||||||||||||||||||
Goodwill |
$ | 1,418.2 | $ | (4.0 | ) | $ | 619.1 | $ | 182.9 | $ | — | $ | 11.8 | $ | 560.7 | $ | 40.9 | $ | 6.8 | |||||||||||||||||
2005 |
||||||||||||||||||||||||||||||||||||
Revenues |
$ | 4,888.7 | $ | (124.1 | ) (d) | $ | 1,963.3 | $ | 585.1 | $ | 96.1 | $ | 1,355.0 | $ | 869.9 | $ | 74.0 | $ | 69.4 | |||||||||||||||||
Cost of sales |
$ | 3,306.0 | $ | (120.0 | ) (d) | $ | 1,220.0 | $ | 390.1 | $ | 47.8 | $ | 1,281.4 | $ | 401.5 | $ | 42.6 | $ | 42.6 | |||||||||||||||||
Operating income |
$ | 503.0 | $ | — | $ | 168.1 | $ | 81.6 | $ | 21.6 | $ | 37.5 | $ | 188.3 | (e) | $ | 5.5 | $ | 0.4 | |||||||||||||||||
Loss from equity investees |
(2.6 | ) | — | — | — | — | — | (2.5 | ) | (0.1 | ) | — | ||||||||||||||||||||||||
Loss on extinguishments of debt |
(33.6 | ) | — | (33.6 | ) | — | — | — | — | — | — | |||||||||||||||||||||||||
Interest expense |
(130.2 | ) | — | (79.8 | ) | (16.6 | ) | (1.7 | ) | — | (28.6 | ) | (2.9 | ) | (0.6 | ) | ||||||||||||||||||||
Minority interests |
(29.9 | ) | 3.9 | (33.1 | ) | — | — | — | (0.7 | ) | — | — | ||||||||||||||||||||||||
Income (loss) before income taxes |
$ | 306.7 | $ | 3.9 | $ | 21.6 | $ | 65.0 | $ | 19.9 | $ | 37.5 | $ | 156.5 | (e) | $ | 2.5 | $ | (0.2 | ) | ||||||||||||||||
Depreciation and amortization |
$ | 146.4 | $ | — | $ | 73.7 | $ | 20.7 | $ | 3.1 | $ | 5.7 | 37.6 | $ | 4.9 | $ | 0.7 | |||||||||||||||||||
Partnership EBITDA (a) |
$ | 215.9 | ||||||||||||||||||||||||||||||||||
Total assets |
$ | 4,571.5 | $ | (348.1 | ) | $ | 1,672.9 | $ | 803.6 | $ | 99.8 | $ | 296.1 | $ | 1,404.8 | $ | 152.4 | $ | 490.0 | |||||||||||||||||
Capital expenditures |
$ | 158.4 | $ | — | $ | 62.6 | $ | 38.8 | $ | 7.5 | $ | 6.2 | $ | 38.5 | $ | 3.5 | $ | 1.3 | ||||||||||||||||||
Investments in equity investees |
$ | 12.8 | $ | — | $ | — | $ | — | $ | — | $ | 8.5 | $ | 1.6 | $ | 2.7 | $ | — | ||||||||||||||||||
Goodwill |
$ | 1,231.2 | $ | (4.0 | ) | $ | 618.2 | $ | — | $ | — | $ | 11.8 | $ | 531.4 | $ | 67.5 | $ | 6.3 | |||||||||||||||||
| (a) | The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income: |
| Year ended September 30, | 2007 | 2006 | 2005 | |||||||||
Partnership EBITDA (i) |
$ | 338.7 | $ | 237.9 | $ | 215.9 | ||||||
Depreciation and amortization (ii) |
(75.7 | ) | (72.5 | ) | (73.6 | ) | ||||||
Minority interests (iii) |
2.8 | 1.6 | 1.3 | |||||||||
Intercompany gain on sale of Atlantic Energy |
— | — | (9.1 | ) | ||||||||
Loss on extinguishments of debt |
— | 17.1 | 33.6 | |||||||||
Operating income |
$ | 265.8 | $ | 184.1 | $ | 168.1 | ||||||
| (i) | Includes $46.1 gain on the sale of Arizona storage facility in fiscal 2007 and $9.1 gain on the sale of Atlantic Energy to Energy Services in fiscal 2005. See Note 2. |
||
| (ii) | Excludes General Partner depreciation and amortization of $0.1 in fiscal 2005 |
||
| (iii) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. |
| (b) | International Propane — Other principally comprises FLAGA, including its Central and Eastern European joint-venture ZLH, and our joint-venture business in China. |
|
| (c) | Corporate & Other results principally comprise UGI Enterprises’ HVAC/R, net expenses of UGI’s captive general liability insurance company and
UGI Corporation’s unallocated corporate and general expenses, interest income, and, beginning January 1, 2007, UGI Utilities’ HVAC operations.
Corporate and Other’s assets principally comprise cash, short-term investments and an intercompany loan. The intercompany interest associated with the
intercompany loan is removed in the segment presentation. |
|
| (d) | Represents the elimination of intersegment transactions primarily associated with Energy Services’ revenues from sales to Gas Utility and AmeriGas Propane
totaling $127.1 and $33.6 in fiscal 2007, respectively, $101.0 and $37.3 in fiscal 2006, respectively, and $89.2 and $25.9 in fiscal 2005, respectively. |
|
| (e) | International Propane — Antargaz’ operating income and income before income taxes for fiscal 2005 include $18.8 associated with the resolution of certain
business tax contingencies (see Note 10). |
F-40
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
BALANCE SHEETS
(Millions of dollars)
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
BALANCE SHEETS
(Millions of dollars)
| September 30, | ||||||||
| ASSETS | 2007 | 2006 | ||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 0.7 | $ | — | ||||
Accounts and notes receivable |
9.1 | 5.8 | ||||||
Deferred income taxes |
0.3 | 0.2 | ||||||
Prepaid expenses and other current assets |
1.6 | 1.7 | ||||||
Total current assets |
11.7 | 7.7 | ||||||
Investments in subsidiaries |
1,337.5 | 1,117.8 | ||||||
Other assets |
14.6 | 8.8 | ||||||
Total assets |
$ | 1,363.8 | $ | 1,134.3 | ||||
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts and notes payable |
$ | 11.0 | $ | 11.3 | ||||
Derivative financial instruments |
6.5 | — | ||||||
Accrued liabilities |
4.1 | 4.9 | ||||||
Total current liabilities |
21.6 | 16.2 | ||||||
Noncurrent liabilities |
20.3 | 18.5 | ||||||
Commitments and contingencies |
||||||||
Common stockholders’ equity: |
||||||||
Common Stock, without par value (authorized - 300,000,000 shares;
issued - 115,152,994 shares) |
831.6 | 807.5 | ||||||
Retained earnings |
497.5 | 370.0 | ||||||
Accumulated other comprehensive income (loss) |
57.7 | (3.8 | ) | |||||
| 1,386.8 | 1,173.7 | |||||||
Less treasury stock, at cost |
(64.9 | ) | (74.1 | ) | ||||
Total common stockholders’ equity |
1,321.9 | 1,099.6 | ||||||
Total liabilities and common stockholders’ equity |
$ | 1,363.8 | $ | 1,134.3 | ||||
Commitments and Contingencies:
In addition to the guarantees of Flaga’s debt and 50%
of ZLH’s working capital facility as described in Note 3
to Consolidated Financial Statements, at September 30, 2007, UGI Corporation had agreed to indemnify the issuers of
$29.5 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to
$385.0 of obligations to suppliers and customers of UGI Energy Services, Inc. (UESI) and subsidiaries of which
$342.1 of such obligations were outstanding as of September 30, 2007.
S-1
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
| Year Ended | ||||||||||||
| September 30, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
Revenues |
$ | — | $ | — | $ | — | ||||||
Costs and expenses: |
||||||||||||
Operating and administrative expenses |
27.2 | 25.4 | 30.0 | |||||||||
Other income, net |
(27.1 | ) | (25.7 | ) | (29.5 | ) | ||||||
| 0.1 | (0.3 | ) | 0.5 | |||||||||
Operating (loss) income |
(0.1 | ) | 0.3 | (0.5 | ) | |||||||
Intercompany interest income (expense) |
0.2 | (5.6 | ) | (3.7 | ) | |||||||
Income (loss) before income taxes |
0.1 | (5.3 | ) | (4.2 | ) | |||||||
Income tax expense (benefit) |
0.8 | (1.1 | ) | 1.0 | ||||||||
Loss before equity in income
of unconsolidated subsidiaries |
(0.7 | ) | (4.2 | ) | (5.2 | ) | ||||||
Equity in income of unconsolidated
subsidiaries |
205.0 | 180.4 | 192.7 | |||||||||
Net income |
$ | 204.3 | $ | 176.2 | $ | 187.5 | ||||||
Earnings per common share: |
||||||||||||
Basic |
$ | 1.92 | $ | 1.67 | $ | 1.81 | ||||||
Diluted |
$ | 1.89 | $ | 1.65 | $ | 1.77 | ||||||
Average common shares outstanding (millions): |
||||||||||||
Basic |
106.451 | 105.455 | 103.877 | |||||||||
Diluted |
107.941 | 106.727 | 105.723 | |||||||||
S-2
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
(Millions of dollars)
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
(Millions of dollars)
| Year Ended | ||||||||||||
| September 30, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
NET CASH PROVIDED BY OPERATING
ACTIVITIES (a) |
$ | 105.1 | $ | 357.6 | $ | 93.3 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||
Investments in unconsolidated subsidiaries |
(44.0 | ) | (295.4 | ) | (53.4 | ) | ||||||
Net cash used by investing activities |
(44.0 | ) | (295.4 | ) | (53.4 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||
Payment of dividends on Common Stock |
(76.8 | ) | (72.5 | ) | (67.4 | ) | ||||||
Issuance of Common Stock |
16.4 | 10.0 | 27.1 | |||||||||
Net cash used by financing activities |
(60.4 | ) | (62.5 | ) | (40.3 | ) | ||||||
Cash and cash equivalents increase (decrease) |
$ | 0.7 | $ | (0.3 | ) | $ | (0.4 | ) | ||||
Cash and cash equivalents: |
||||||||||||
End of period |
$ | 0.7 | $ | — | $ | 0.3 | ||||||
Beginning of period |
— | 0.3 | 0.7 | |||||||||
Increase (decrease) |
$ | 0.7 | $ | (0.3 | ) | $ | (0.4 | ) | ||||
| (a) | Includes dividends received from unconsolidated subsidiaries of $100.0, $351.6, and $98.5, respectively, for the years
ended September 30, 2007, 2006 and 2005. |
S-3
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Millions of dollars)
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Millions of dollars)
| Charged | ||||||||||||||||
| Balance at | (credited) | Balance at | ||||||||||||||
| beginning | to costs and | end of | ||||||||||||||
| of year | expenses | Other | year | |||||||||||||
Year Ended September 30, 2007 |
||||||||||||||||
Reserves deducted from assets in
the consolidated balance sheet: |
||||||||||||||||
Allowance for doubtful accounts |
$ | 38.0 | $ | 26.7 | $ | (28.3 | ) (1) | $ | 37.7 | |||||||
| 1.3 | (4) | |||||||||||||||
Other reserves: |
||||||||||||||||
Self-insured property and casualty
liability |
$ | 62.9 | $ | 16.1 | $ | (15.3 | ) (3) | $ | 65.0 | |||||||
| 1.3 | (2) | |||||||||||||||
Insured property and casualty liability |
$ | 0.3 | $ | 0.3 | ||||||||||||
Environmental, litigation and other |
$ | 26.5 | $ | 1.0 | $ | (0.9 | ) (3) | $ | 36.1 | |||||||
| 1.2 | (2) | |||||||||||||||
| 8.3 | (4) | |||||||||||||||
Year Ended September 30, 2006 |
||||||||||||||||
Reserves deducted from assets in
the consolidated balance sheet: |
||||||||||||||||
Allowance for doubtful accounts |
$ | 29.2 | $ | 25.0 | $ | (22.4 | ) (1) | $ | 38.0 | |||||||
| 6.2 | (4) | |||||||||||||||
Other reserves: |
||||||||||||||||
Self-insured property and casualty
liability |
$ | 66.0 | $ | 13.8 | $ | (17.9 | ) (3) | $ | 62.9 | |||||||
| 0.1 | (2) | |||||||||||||||
| 0.9 | (4) | |||||||||||||||
Insured property and casualty liability |
$ | 0.6 | $ | (0.3 | ) (3) | $ | 0.3 | |||||||||
Environmental, litigation and other |
$ | 19.7 | $ | 7.5 | $ | (1.2 | ) (3) | $ | 26.5 | |||||||
| 0.1 | (2) | |||||||||||||||
| 0.4 | (4) | |||||||||||||||
S-4
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS (continued)
(Millions of dollars)
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS (continued)
(Millions of dollars)
Year Ended September 30, 2005 |
||||||||||||||||
Reserves deducted from assets in
the consolidated balance sheet: |
||||||||||||||||
Allowance for doubtful accounts |
$ | 22.3 | $ | 25.1 | $ | (19.0 | ) (1) | $ | 29.2 | |||||||
| $ | 0.8 | (2) | ||||||||||||||
Other reserves: |
||||||||||||||||
Self-insured property and casualty
liability |
$ | 57.8 | $ | 25.9 | $ | (17.7 | ) (3) | $ | 66.0 | |||||||
Insured property and casualty liability |
$ | 0.6 | $ | 0.6 | ||||||||||||
Environmental, litigation and other |
$ | 34.7 | $ | (11.1 | ) | $ | (4.7 | ) (3) | $ | 19.7 | ||||||
| 0.8 | (2) | |||||||||||||||
| (1) | Uncollectible accounts written off, net of recoveries. |
|
| (2) | Other adjustments. |
|
| (3) | Payments, net. |
|
| (4) | Acquisition |
S-5
Table of Contents
EXHIBIT INDEX
| Exhibit No. | Description | |||
| 10.8 | UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006 |
|||
| 10.16 | UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan,
As Amended and Restated on July 31, 2007 |
|||
| 10.90 | Extension of Guarantee Agreement dated July 26, 2006, between UGI Corporation, as
Guarantor, and Raiffeisen Zentralbank Osterreich Aktiengesellschaft (“RZB”), as
Beneficiary, relating to the extension of the Working Capital Facility Agreement dated
July 26, 2006, between RZB and Flaga GmbH |
|||
| 21 | Subsidiaries of the Registrant |
|||
| 23 | Consent of PricewaterhouseCoopers LLP |
|||
| 31.1 | Certification by the Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act |
|||
| 31.2 | Certification by the Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act |
|||
| 32 | Certification by the Chief Executive Officer and Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act |
|||