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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, 2010
Commission file number 1-11071
UGI CORPORATION
(Exact name of registrant as specified in its charter)
| Pennsylvania | 23-2668356 | |
| (State or Other Jurisdiction of | (I.R.S. Employer Identification No.) | |
| Incorporation or Organization) |
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. |
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 whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files).
Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K
(§229.405 of this chapter) 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, a
non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated
filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). Yes o No þ
The aggregate market value of UGI Corporation Common Stock held by non-affiliates of the registrant
on March 31, 2010 was $2,848,571,109.
At
November 15, 2010 there were 110,466,049 shares of UGI Corporation Common Stock issued and
outstanding.
Portions of the Proxy Statement for the Annual Meeting of Shareholders to be held on January 20,
2011 are incorporated by reference into Part III of this Form 10-K.
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FORWARD-LOOKING INFORMATION
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 liquefied petroleum gases, oil, electricity, and natural gas and the capacity to
transport product to our customers; (3) changes in domestic and foreign laws and regulations,
including safety, tax and accounting matters; (4) inability to timely recover costs through utility
rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures
from the same and alternative energy sources; (7) failure to acquire new customers thereby reducing
or limiting any increase in revenues; (8) liability for environmental claims; (9) increased
customer conservation measures due to high energy prices and improvements in energy efficiency and
technology resulting in reduced demand; (10) adverse labor relations; (11) large customer,
counter-party or supplier defaults; (12) 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 and liquefied petroleum gases;
(13) political, regulatory and economic conditions in the United States and in foreign countries,
including foreign currency exchange rate fluctuations, particularly the euro; (14) capital market
conditions, including reduced access to capital markets and interest rate fluctuations; (15)
changes in commodity market prices resulting in significantly higher cash collateral requirements;
(16) reduced distributions from subsidiaries; (17) the timing of development of Marcellus Shale gas
production; and (18) the timing and success of our acquisitions, commercial initiatives and
investments to grow our businesses.
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.
PART I:
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
CORPORATE OVERVIEW
UGI Corporation is a holding company that, through subsidiaries, 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; a manager of midstream assets; and a regional provider of
heating, ventilation, air conditioning, refrigeration and electrical contracting services. Our
subsidiaries and affiliates operate principally in the following six business segments:
| • | AmeriGas Propane |
||
| • | International Propane — Antargaz |
||
| • | International Propane — Other |
||
| • | Gas Utility |
| • | Electric Utility |
||
| • | Midstream & Marketing (formerly, Energy Services) |
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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 Consolidated Financial Statements.
The International Propane-Antargaz segment consists of the LPG distribution business of our
wholly owned subsidiary Antargaz, a French société anonyme (“Antargaz”). The International Propane — Other segment consists of the LPG distribution businesses of Flaga GmbH, an Austrian corporation,
and its subsidiaries (“Flaga”), Kosan Gas A/S, a Danish company managed by Flaga, and a
majority-owned Delaware limited partnership, China Gas Partners, L.P. Antargaz is one of the
largest retail distributors of LPG in France. Flaga is the largest retail LPG distributor in
Austria and one of the largest in the Czech Republic, Slovakia and Hungary. Kosan Gas is the
largest LPG distributor in Denmark. China Gas Partners is an LPG distributor in the Nantong
region of China.
The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution
businesses of our subsidiary, UGI Utilities, Inc. (“UGI Utilities”) and UGI Utilities’
subsidiaries, UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). Gas
Utility serves approximately 568,000 customers in eastern and central Pennsylvania and several
hundred customers in portions of one Maryland county. UGI Utilities’ natural gas distribution
utility is referred to as “UGI Gas;” PNG’s natural gas distribution utility is referred to as “PNG
Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” 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 is
regulated by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small
service territory, the Maryland Public Service Commission. Electric Utility is regulated by the
PUC.
The Midstream & Marketing segment (formerly, Energy Services) consists of energy-related
businesses conducted by UGI Energy Services, Inc. and a number of its subsidiaries. These
businesses include (i) energy marketing in the eastern region of the United States under the trade
name GASMARK®, (ii) generating electricity in Pennsylvania, including through solar
facilities, (iii) operating and owning a natural gas liquefaction, storage and vaporization
facility and propane-air mixing assets, (iv) managing natural gas pipeline and storage contracts,
and (v) developing pipelines, gathering infrastructure and gas storage facilities to serve
customers in the Marcellus Shale region of Pennsylvania.
Through subsidiaries, 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 utilizing our core competencies
from our existing businesses and 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 2010,
we completed a number of transactions in pursuit of this strategy and moved forward on a number of
larger internally generated capital projects and renewable energy projects.
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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. The terms “Fiscal 2010” and “Fiscal 2009”
refer to the fiscal years ended September 30, 2010 and September 30, 2009, respectively.
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 Reports 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 Hugh J. Gallagher, Director, Treasury Services and Investor Relations, UGI Corporation,
P.O. Box 858, Valley Forge, PA 19482.
AMERIGAS PROPANE
Products, Services and Marketing
Our domestic propane distribution business is conducted through AmeriGas Partners. AmeriGas
Propane is responsible for managing the Partnership. The Partnership serves approximately 1.3
million customers in all 50 states from nearly 1,200 propane distribution locations. In addition to
distributing propane, the Partnership also sells, installs and services propane appliances,
including heating systems. In certain areas, 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 Ontario
and Quebec.
The Partnership sells propane primarily to residential, commercial/industrial, motor fuel,
agricultural and wholesale customers. The Partnership distributed over one billion gallons of
propane in Fiscal 2010. Approximately 87% of the Partnership’s Fiscal 2010 sales (based on gallons
sold) were to retail accounts and approximately 13% were to wholesale customers. Sales to
residential customers in Fiscal 2010 represented approximately 40% of retail gallons sold;
commercial/industrial customers 37%; motor fuel customers 13%; and agricultural customers 5%.
Transport gallons, which are large-scale deliveries to retail customers other than residential,
accounted for 5% of Fiscal 2010 retail gallons. No single customer represents, or is anticipated to
represent, more than 5% of the Partnership’s consolidated revenues.
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The Partnership continues to expand its AmeriGas Cylinder Exchange (“ACE”) program. At
September 30, 2010, ACE cylinders were available at approximately 30,000 retail locations
throughout the United States. Sales of our ACE grill cylinders to retailers are included in
commercial/industrial sales. The ACE program enables consumers to purchase or exchange their empty
propane grill cylinders at various retail locations such as home centers, gas stations, mass
merchandisers and grocery and convenience stores. We also supply retailers with large propane tanks
to enable retailers to replenish customers’ propane grill cylinders directly at the retailer’s
location.
Residential customers use propane 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.
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 in portable cylinders, including ACE propane grill cylinders. Some of these
deliveries are made to the customer’s location, where empty cylinders are either picked up or
replenished 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, 2010, approximately 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 2011. 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. BP Products North America
Inc. and BP Canada Energy Marketing Corp. (collectively), Enterprise Products Operating LP and
Targa Midstream Services LP, supplied approximately 43% of the Partnership’s Fiscal 2010 propane
supply. No other single supplier provided more than 10% of the Partnership’s total propane supply
in Fiscal 2010. In certain areas, however, a single supplier provides 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 various storage facilities and terminals
located in strategic areas across the United States.
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.”
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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
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 for its
detection. Propane is clean burning, producing negligible amounts of pollutants when properly
consumed.
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. In some areas 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.
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For motor fuel customers, 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 no growth in total demand foreseen in the next
several years. 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 long-term 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. The
Partnership also offers customers various payment and service options, including fixed price and
guaranteed price programs.
In Fiscal 2010, the Partnership’s retail propane sales totaled approximately 893 million
gallons. Based on the most recent annual survey by the American Petroleum Institute, 2008 domestic
retail propane sales (annual sales for other than chemical uses) in the United States totaled
approximately 9.3 billion gallons. Based on LP-GAS magazine rankings, 2008 sales volume of the ten
largest propane companies (including AmeriGas Partners) represented approximately 41% of domestic
retail sales.
Properties
As of September 30, 2010, the Partnership owned approximately 86% of its district locations.
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, 2010, the Partnership operated a transportation fleet with the following
assets:
| Approximate Quantity & Equipment Type | % Owned | % Leased | ||||||||||
| 1,400 | Trailers |
89 | % | 11 | % | |||||||
| 300 | Tractors |
13 | % | 87 | % | |||||||
| 188 | Railroad tank cars |
0 | % | 100 | % | |||||||
| 2,460 | Bobtail trucks |
14 | % | 86 | % | |||||||
| 267 | Rack trucks |
1 | % | 99 | % | |||||||
| 2,125 | Service and delivery trucks |
15 | % | 85 | % | |||||||
Other assets owned at September 30, 2010 included approximately 837,000 stationary storage
tanks with typical capacities ranging from 121 to 2,000 gallons and approximately 3.3 million
portable propane cylinders with typical capacities of 1 to 120 gallons. The Partnership also owned
approximately 5,700 large volume tanks with typical capacities of more than 2,000 gallons which are
used for its own storage requirements.
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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 in the U.S. 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 65% to 70% of the Partnership’s retail sales volume occurs, and
substantially all of the Partnership’s operating income is earned, during the peak heating season
from October 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.
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, the Comprehensive Environmental Response, Compensation and
Liability 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.
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. 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 employees who provide information
to their employers or to the federal government as to pipeline safety from adverse employment
actions.
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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, 2010,
the General Partner had approximately 5,800 employees, including approximately 400 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 PROPANE — ANTARGAZ
Our International Propane — Antargaz LPG distribution business is conducted in France through
our wholly owned subsidiary, Antargaz. Antargaz is one of the largest LPG distributors in France.
During Fiscal 2010, Antargaz sold approximately 280 million gallons of LPG.
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 tanks. Sales of LPG
are also made to service stations to accommodate vehicles that run on LPG. Antargaz sells LPG in
cylinders to approximately 17,500 retail outlets, such as supermarkets, individually owned stores
and gas stations. Supermarket sales represented approximately 58% of cylinder sales volume in
Fiscal 2010. At September 30, 2010, Antargaz had approximately 200,000 bulk customers and
approximately 6 million cylinders in circulation. Approximately 62% of Antargaz’ Fiscal 2010 sales
(based on volumes) were cylinder and small bulk, 14% medium bulk, 18% large bulk, 3% to service
stations for automobiles, and 3% piped networks (metered sales). 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 total 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 cylinders accounted for
approximately 61% of all LPG cylinders sold in Fiscal 2010, with propane cylinders accounting for
the remainder. Propane cylinders are also used to supply fuel for forklift trucks. The market
demand for 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 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 enterprises, and
poultry brooders. Large bulk customers include agricultural companies, and companies that use LPG
in their industrial processes.
LPG Supply and Storage
Antargaz has an agreement with Totalgaz for the supply of butane, with pricing based on
internationally quoted market prices. Under this agreement, 80% of Antargaz’ requirements for
butane are guaranteed until September 2012. Requirements are fixed annually and Antargaz can
develop other sources of supply. For Fiscal 2010, Antargaz purchased almost 100% of its butane
needs and approximately 10% of its propane needs from Totalgaz. Antargaz
also purchases propane on the international market and on the domestic market, under term
agreements with international oil and gas trading companies. In addition, purchases are made on the
spot market from international oil and gas companies and to a lesser extent from domestic
refineries, including those operated by BP France and Esso SAF. During Fiscal 2010, three suppliers
accounted for substantially all of Antargaz’ propane supply.
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Antargaz has 4 primary storage facilities in operation, including 3 that are located at deep
sea harbor facilities, and 26 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.
Competition
The LPG market in France is mature, with modest declines in total demand due to competition
with other fuels and conservation. 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 cost 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 derives a significant portion of its electricity from nuclear power plants. Due to
the nuclear power plants as well as the regulation of electricity prices by the French government,
electricity prices in France are generally less expensive than LPG. As a result, electricity has
increasingly become a more significant competitor to LPG in France than in other countries where we
operate. In addition, government policies and incentives that favor alternative energy sources 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. In recent years, competition
has increased as supermarkets affiliate with LPG distributors to offer their own brands of
cylinders. Antargaz has partnered with one supermarket chain in this market. If Antargaz is
unsuccessful in expanding its services to other supermarket chains, its market share through
supermarket sales may decline. Antargaz’ competitors are generally affiliates of its LPG suppliers.
As a result, its competitors may obtain product at more competitive prices.
On October 21, 2009, Antargaz responded to a Statement of Objections issued by the French
competition authority, the General Division of Competition, Consumption and Fraud Punishment, in
July of 2009. For more information on this matter, see “Legal Proceedings” and Note 15 to
Consolidated Financial Statements, included under Item 8 of this Report.
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
substantially all of Antargaz’ operating income is earned, during the six 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.
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Properties
Antargaz has 4 primary storage facilities in operation. One of these is a refrigerated
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 | 450 | |||||||||
| (1) | Cubic meters. |
|
| (2) | Pursuant to a long-term contractual arrangement with the owner. |
Antargaz closed a fifth storage facility, Geovexin, during Fiscal 2010. Antargaz has 26
secondary storage facilities, 13 of which are wholly owned. The others are partially owned, through
joint ventures.
Employees
At September 30, 2010, Antargaz had approximately 950 employees.
INTERNATIONAL PROPANE — OTHER
Our International Propane — Other LPG distribution business is conducted principally in Europe
through our wholly owned subsidiary, Flaga. Flaga operates in Austria, Switzerland, the Czech
Republic, Slovakia, Poland, Hungary and Romania. During Fiscal 2010, Flaga sold approximately 70
million gallons of LPG. Our majority-owned partnership in China sold approximately 12.3 million
gallons of LPG during Fiscal 2010. Prior to February 2010, this partnership was a joint venture.
On September 23, 2010, we acquired Kosan Gas A/S, which operates in Denmark and is managed by
Flaga. On October 15, 2010, we acquired Shell Gas Polska Sp. z.o.o, which operates in Poland and is
being combined with Flaga’s existing business there.
FLAGA
Products, Services, Marketing and Storage
Flaga is referred to in this section collectively with Kosan Gas as “Flaga” unless the context
otherwise requires. Flaga distributes LPG for residential, commercial, industrial, and auto gas
applications in the following European countries: Austria, Switzerland, the Czech Republic,
Denmark, Slovakia, Poland, Hungary and Romania. During Fiscal 2010, Flaga sold approximately 70
million gallons of LPG. Flaga is the largest distributor of LPG in Austria and Denmark and one of
the largest distributors of LPG in the Czech Republic, Hungary and Slovakia.
Flaga’s customers primarily use LPG for heating, cooking, construction work, industrial
processing, forklifts and autogas. The retail propane industry in Austria, Denmark and Switzerland
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 32 sales offices throughout the countries it serves. Much
of Flaga’s cylinder business in Austria is conducted through approximately 600 local resellers with
whom Flaga has a long business relationship. In its other countries, Flaga sells cylinders to
distributors who resell the cylinders to end users under the distributor’s pricing and terms. Flaga
utilizes approximately 60 storage facilities with 21 of those storage facilities in the Czech
Republic and 16 in Austria.
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Seasonality and Competition
Because many of Flaga’s customers use LPG for heating, sales volumes in Flaga’s sales
territories 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 profitability is sensitive to
changes in wholesale LPG costs, Flaga generally seeks to pass on increases in the cost of LPG to
customers. There is no assurance, however, that Flaga will always be able to pass on product cost
increases fully. In parts of Flaga’s sales territories, it is particularly difficult to pass on
rapid increases in the price of LPG due to the low per capita income of customers in several of its
territories and the intensity of competition. 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 sales territories, government policies and incentives that favor
alternative energy sources may result in customers migrating to energy sources other than LPG.
Flaga competes with other LPG marketers, including competitors located in other European
countries, and also competes with providers of other sources of energy, principally natural gas,
electricity and wood. Rules and regulations applicable to LPG industry operations in many of the
eastern European countries where Flaga operates are still evolving, or are not consistently
enforced. As a result, competitive conditions in those areas are intense.
Government Regulation
Flaga’s business is 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, 2010, Flaga had approximately 850 employees.
GAS UTILITY
The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution
businesses of our subsidiary, UGI Utilities, Inc. (“UGI Utilities”) and UGI Utilities’
subsidiaries, UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). Gas
Utility serves approximately 568,000 customers in eastern and central Pennsylvania and several
hundred customers in portions of one Maryland county. UGI Utilities’ natural gas distribution
utility is referred to as “UGI Gas;” PNG’s natural gas distribution utility is referred to as “PNG
Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” 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 is
regulated by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small
service territory, the Maryland Public Service Commission. Electric Utility is regulated by the
PUC.
Service Area; Revenue Analysis
Gas Utility is authorized to distribute natural gas to approximately 568,000 customers in
portions of 45 eastern and central Pennsylvania counties through its distribution system of
approximately 11,900 miles of gas mains. The service area includes the cities of Allentown,
Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre, Lock
Haven, Pittston, Pottsville 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. Gas Utility
also distributes natural gas to several hundred customers in portions of one Maryland county.
System throughput (the total volume of gas sold to or transported for customers within Gas
Utility’s distribution system) for Fiscal 2010 was approximately 153.9 billion cubic feet (“bcf”).
System sales of gas accounted for
approximately 37% of system throughput, while gas transported for residential, commercial and
industrial customers (who bought their gas from others) accounted for approximately 63% of system
throughput.
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Sources of Supply and Pipeline Capacity
Gas Utility is permitted to recover prudently incurred costs of natural gas it sells to its
customers. See “Management’s Discussion and Analysis of Financial Condition and Results of
Operations — Market Risk Disclosures.” 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 long-term agreements with a number of pipeline companies, including Texas
Eastern Transmission Corporation, Columbia Gas Transmission Corporation, Transcontinental Gas
Pipeline Corporation, Dominion Transmission, ANR Pipeline and Tennessee Gas Pipeline.
Gas Supply Contracts
During Fiscal 2010, Gas Utility purchased approximately 91 bcf of natural gas for sale to
core-market customers (principally comprised of firm-residential, commercial and industrial
customers who purchase their gas from Gas Utility (“retail core-market”) and, to a much lesser
extent, residential and small commercial customers who purchase their gas from alternate suppliers)
and off-system sales customers. Approximately 75% of the volumes purchased were supplied under
agreements with 10 suppliers. The remaining 25% of gas purchased by Gas Utility was supplied by
approximately 21 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.
Seasonality
Because many of its customers use gas for heating purposes, Gas Utility sales are seasonal.
Approximately 65% to 70% of Gas Utility’s sales volume is supplied, and approximately 85% to 90% of
Gas Utility’s operating income is earned, during a typical peak heating season from October 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. 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. Rate caps for electric utilities serving a significant portion
of Gas Utility’s service territory expired at the end of 2009 or are scheduled to expire at the end
of 2010 which will likely result in electricity losing all or some of its competitive price
advantage. Additionally, high efficiency electric heat pumps have led to a decrease in the cost of
heating with electricity. Government subsidies currently favor ground source heat pumps over fossil
fueled systems. 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, effective July 1, 1999 all of Gas Utility’s
customers, including core-market customers, have been afforded this opportunity.
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.”
Approximately 31% of Gas Utility’s commercial and industrial customers’ annual throughput volume,
including
certain customers served under interruptible rates, have locations which afford them the
opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing
Gas Utility. 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 28 customers, most of which
are among the 10 largest customers for each of UGI Gas, PNG and CPG in terms of annual volumes. All
of these customers have contracts, 22 of which extend beyond the 2011 fiscal year. No single
customer represents, or is anticipated to represent, more than 5% of Gas Utility’s total revenues.
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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 2011.
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 2010, Gas Utility supplied transportation service to 2 major co-generation
installations and 5 electric generation facilities. Gas Utility continues to seek new residential,
commercial and industrial customers for both firm and interruptible service. In the residential
market sector, Gas Utility connected approximately 7,700 residential heating customers during
Fiscal 2010. These customers consisted primarily of (i) customers converting from other energy
sources, mainly oil and electricity, (ii) existing non-heating gas customers who added gas heating
systems to replace other energy sources and (iii) new home construction customers.
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.
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 2,120 miles of transmission and distribution lines and 13 transmission substations.
For Fiscal 2010, approximately 54% of sales volume came from residential customers, 34% from
commercial customers, and 12% from industrial and other customers. Sales of electricity for
residential heating purposes accounted for approximately 18% of total sales of electricity during
Fiscal 2010.
Sources of Supply
In accordance with Electric Utility’s default service settlement with the PUC effective
January 1, 2010, Electric Utility is permitted to recover prudently incurred electricity costs,
including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply
plan filed with the PUC. See “Management’s Discussion and Analysis of Financial Condition and
Results of Operations — Market Risk Disclosures” and Note 8 to Consolidated Financial Statements.
Electric Utility distributes electricity that it purchases from wholesale markets and electricity
that customers purchase from other suppliers, if any. As of September 30, 2010, 4 electric
generation suppliers provided energy for customers representing 13% of Electric Utility’s sales
volume. See “Gas Utility and Electric Utility Regulation and Rates — Electric Utility Rates.”
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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 “default service” provider for its customers who do not
choose an alternate electric generation supplier. In Fiscal 2010, Electric Utility served nearly
all of the electric customers within its service territory and is the only regulated electric
utility having the right, granted by the PUC or by law, to distribute electricity in its service
territory. As an energy source, electricity competes with natural gas, oil, propane and other
heating fuels for residential heating purposes.
The terms and conditions under which Electric Utility provides default service, and rules
governing the rates that may be charged for such service, have been established in a Default
Service Rate Plan (“DSR Plan”) approved by the PUC. Consistent with the terms of the DSR Plan,
effective January 1, 2010, default service rates are designed to recover all reasonable and prudent
costs incurred in providing electricity to default service customers. This recovery, through
default service rates, no longer subjects Electric Utility to the risk that actual costs for
purchased power will exceed default service revenues. Conversely, effective January 1, 2010,
Electric Utility does not have the opportunity to recover revenues in excess of actual power costs.
See “Gas Utility and Electric Utility Regulation and Rates — Electric Utility Rates.”
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. There are primarily two
types of rates that UGI Utilities may charge customers for gas and electric service: (1) rates
designed to recover costs other than purchased gas costs (“PGCs”) and electric default service
costs; and (2) rates designed to recover PGCs and electric default service costs. Rates designed
to recover costs other than PGCs and electric default service costs are primarily established in
general base rate proceedings. Rates designed to recover PGCs and electric default service costs
are established in PGC and electric default service rate proceedings.
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. PJM is a regional transmission organization that regulates and
coordinates generation supply and the wholesale delivery of electricity. 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
Rates that UGI Utilities’ utility operations may charge for gas service come in two forms: 1)
rates designed to recover costs other than purchased gas costs; and 2) rates designed to recover
purchase gas costs. Rates designed to recover costs other than purchased gas costs are primarily
established in general base rate proceedings. Rates designed to recover purchased gas costs are
reviewed in a purchased gas costs (“PGC”) rate proceeding. The most recent general base rate
increase for UGI Gas became effective in 1995. In accordance with a statutory mechanism, a rate
increase for Gas Utility’s retail core-market customers became effective October 1, 2000 along with
a PGC variable credit equal to a portion of the margin received from customers served under
interruptible rates to the extent
such interruptible customers use third-party pipeline capacity contracted for by UGI Gas for
retail core-market customers.
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On August 27, 2009, the PUC approved PNG’s and CPG’s base rate case settlement agreements,
which resulted in a $19.75 million base rate operating revenue increase for PNG and a $10 million
base rate operating revenue increase for CPG. The increases became effective on August 28, 2009.
The gas service tariffs for UGI Gas, PNG and CPG 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, PNG, and CPG sell to their customers. PGC rates are reviewed and
approved annually by the PUC. UGI Gas, PNG, and CPG 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.
UGI Gas has two PGC rates: (1) PGC is applicable to small, firm, retail core-market customers
consisting of the residential and small commercial and industrial classes; and (2) PGC is
applicable to firm, contractual, high-load factor customers served on three separate rates. PNG and
CPG each have 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 (POLR or
“default service”) components in 1998. In accordance with the POLR Settlements, Electric Utility
increased POLR rates annually from 2005 through 2009.
PUC default service regulations became applicable to Electric Utility’s provision of default
service effective January 1, 2010 and Electric Utility, consistent with these regulations, has
received approval from the PUC of (1) default service tariff rules applicable for service rendered
on or after January 1, 2010, (2) a reconcilable default service cost rate recovery mechanism to
recover the cost of acquiring default service supplies for service rendered on or after January 1,
2010, (3) a plan for meeting the post-2009 requirements of the Alternative Energy Portfolio
Standards Act (“AEPS Act”), which requires Electric Utility to directly or indirectly acquire
certain percentages of its supplies from designated alternative energy sources and (4) a
reconcilable AEPS Act cost recovery rate mechanism to recover the costs of complying with AEPS Act
requirements applicable to default service supplies for service rendered on or after January 1,
2010. Under these rules, default service rates for most customers will be adjusted quarterly.
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.
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.
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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, PNG and CPG 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, PNG and CPG 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 Note 15 to Consolidated Financial Statements.
Employees
At September 30, 2010, UGI Utilities had approximately 1,400 employees.
MIDSTREAM & MARKETING
UGI Energy Services, Inc. and its subsidiaries (collectively, “Energy Services”) operate the
energy-related businesses described below.
Retail Energy Marketing
Energy Services conducts its energy marketing business under the trade name
GASMARK®. Energy Services sells natural gas, liquid fuels and electricity to
approximately 9,000 commercial and industrial customers at approximately 30,000 locations. Energy
Services serves customers in all or portions of Pennsylvania, New Jersey, Delaware, New York, Ohio,
Maryland, Virginia, North Carolina and the District of Columbia. Energy Services distributes
natural gas through the use of the transportation systems of 33 utility systems. It supplies power
to customers through the use of the transmission systems of 13 utility systems.
Gas and power marketing are high-revenue, low-margin businesses. A majority of Energy
Services’ commodity sales are made under fixed-price agreements. Energy Services manages supply
cost volatility related to these agreements by (i) entering into fixed-price supply arrangements
with a diverse group of suppliers and holders of interstate pipeline capacity, (ii) entering into
exchange-traded futures contracts which are guaranteed by the New York Mercantile Exchange and have
nominal credit risk, (iii) entering into over-the-counter derivative arrangements with major
international banks and major suppliers, and (iv) utilizing supply assets that it owns or manages.
Energy Services also bears the risk for balancing and delivering natural gas and power to its
customers under various gas pipeline and utility company tariffs. See “Management’s Discussion and
Analysis of Financial Condition and Results of Operations — Market Risk Disclosures.”
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Midstream Assets
Energy Services operates a natural gas liquefaction, storage and vaporization facility in
Temple, Pennsylvania (“Temple Facility”), and propane storage and propane-air mixing stations in
Bethlehem, Reading, Hunlock Creek, and White Deer, Pennsylvania. It also operates propane storage,
rail transshipment terminals and propane-air mixing stations in Steelton and Williamsport,
Pennsylvania. These assets are used in Energy Services’ energy peaking business that provides
supplemental energy, primarily liquefied natural gas and propane-air mixtures, to gas utilities at
times of high demand (generally during periods of coldest winter weather). During Fiscal 2010,
Energy Services continued construction work on the fourfold expansion of its Temple Facility. That
project is on schedule and expected to be completed during Fiscal 2012. Energy Services also
manages natural gas pipeline and storage contracts for UGI Utilities, subject to a competitive bid
process.
As we announced in August 2010, Energy Services is planning to make investments in
infrastructure projects to support the development of natural gas in the Marcellus Shale region of
Pennsylvania. These investments are expected to cover a range of new midstream asset opportunities,
including interstate pipelines, local gathering systems and gas storage facilities.
Electric Generation
We have an approximate 5.97% (approximately 102 megawatt) ownership interest in the Conemaugh
generation 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. Energy Services also owns the Hunlock Station located near
Wilkes-Barre, Pennsylvania, which it operated as a 44-megawatt coal-fired facility through May
2010. At that time, it ceased operations to facilitate conversion to a natural gas-fueled plant.
Energy Services is in the process of building a 125-megawatt natural gas-fueled power plant to
replace the Hunlock Station facility. The new plant is expected to be completed in late Fiscal
2011.
Energy Services owns and operates a landfill gas-fueled electricity generation plant in
Hegins, Pennsylvania with gross generating capacity of 11 megawatts. The plant qualifies for
renewable energy credits. During fiscal year 2010, Energy Services built a 1 megawatt solar-powered
generation facility in Easton, Pennsylvania to supply electrical power to a third party and will
receive solar renewable energy credits as a result of the project. Several other solar generation
projects are in development.
Competition
Energy Services competes with other marketers and local utilities to sell natural gas, liquid
fuels, electric power and related services to customers in its service area principally on the
basis of price, customer service and reliability. For electricity generation, we compete with other
generation stations on the PJM interface where sales are based on bid pricing.
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 sales for resale of natural gas and related storage
and transportation services. Energy Services has a tariff on file with FERC pursuant to which it
may make power sales to wholesale customers at market-based rates. Energy Services also has
market-based rate authority for power sales to wholesale customers to the extent that Energy
Services purchases power in excess of its retail customer needs. Energy Services also owns electric
generation facilities that are within the control area of PJM and are dispatched in accordance with
a FERC-approved open access tariff and associated agreements administered by PJM. Energy Services
receives certain revenues collected by PJM, determined under a formulary rate schedule. Energy
Services 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.”
Prior to suspending operations in May 2010 for conversion to natural gas-fueled generation,
Hunlock Station generally complied 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 had a
permit from the DEP to discharge water into the North Branch of the Susquehanna River. A
permit for the gas-fired plant is pending. Energy Services is working with the DEP to develop a
closure plan for the Hunlock Station following the permanent cessation of coal operations there in
2010. The federal Clean Air Act Amendments of 1990 impose emissions limitations for certain
compounds, including sulfur dioxide and nitrous oxides. The Conemaugh Station is in material
compliance with these current emission standards.
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Energy Services 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.
Employees
At September 30, 2010, Energy Services and its subsidiaries had approximately 165 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 120,000 customers in residential,
commercial, industrial and new construction markets. During Fiscal 2010, HVAC/R generated
approximately $77 million in revenues and employed approximately 480 people.
GLOBAL CLIMATE CHANGE
There continues to be concern, both nationally and internationally, about climate change and
the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global
warming.
In addition to carbon dioxide, greenhouse gases include, among others, methane,
a component of natural gas.
While some states have adopted laws regulating the emission of GHGs for some industry
sectors, there is currently no federal regulation mandating the reduction of GHG emissions in the
United States. In June 2009, the United States House of Representatives passed the American Clean
Energy and Security Act (“ACES Act”). The ACES Act would establish an economy-wide GHG
cap-and-trade system to reduce GHG emissions over time. The United States Senate has been
considering a number of related proposals, ranging from “energy only” bills to proposals that place
an economy-wide cap on greenhouse gas emissions. No legislation can be enacted until a final
reconciled bill is approved by both the House of Representatives and
the Senate and signed by the President.
Even if Congress does not pass legislation mandating GHG emissions reductions, there continue to be regulatory
developments under the Clean Air Act applicable to GHGs. In September 2009, the Environmental Protection Agency (“EPA”)
issued a final rule establishing a system for mandatory reporting of GHG emissions. In November 2010, the EPA expanded
the reach of its GHG reporting requirements to include the petroleum and natural gas industries. Petroleum and natural
gas facilities subject to the rule, which include facilities of our natural gas distribution and electricity generation
businesses, are required to begin emissions monitoring in January 2011 and to submit detailed annual reports beginning
in March 2012. The rule does not require affected facilities to implement GHG emission controls or reductions. In
December 2009, the EPA published its findings that emissions of GHGs constitute an endangerment to public health and
the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs
under existing provisions of the Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would
limit GHG emissions from new motor vehicles and that would impose permit requirements for GHG emissions from certain
stationary sources. Legal challenges have been filed against many of EPA’s rulemakings, and we are unable to predict
the results of those challenges.
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Two of the commodities we sell, namely LPG and natural gas, are considered clean alternative
fuels under the federal Clean Air Act Amendments of 1990. We anticipate that this will provide us
with a competitive advantage
over other sources of energy, such as fuel oil and coal, if new climate change regulations
become effective. In addition, we are in the process of refining and implementing our strategy to
identify both our domestic GHG emissions and our energy consumption in order to be in a position to
comply with new regulations and to take advantage of any opportunities that may arise from the
regulation of such emissions.
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 2010, 2009 and 2008 fiscal years appears in Note 21 to Consolidated Financial
Statements included in Item 8 of this Report and is incorporated herein by reference.
EMPLOYEES
At
September 30, 2010, UGI and its subsidiaries had approximately 9,800 employees.
ITEM 1A. RISK FACTORS
There are many factors that may affect our business and results of operations. Additional
discussion regarding factors that may affect our business and operating results is included
elsewhere in this Report.
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 peak heating season of October through March and is directly
affected by the severity of the winter weather. For example, historically, approximately 65% to 70%
of AmeriGas Partners’ annual retail propane volume, Gas Utility’s natural gas throughput (the total
volume of gas sold to or transported for customers within our distribution system) and Antargaz’
annual retail LPG volume has been sold during these months. 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. 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. 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 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 LPG pricing and inventory risk.
The retail LPG business is a “margin-based” business in which gross profits are dependent upon
the excess of the sales price over the LPG supply costs. LPG 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
LPG that our subsidiaries and other marketers purchase can change rapidly over a short period of
time. Most of our domestic LPG 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 LPG supply contracts are based on
internationally quoted market prices. Because our subsidiaries’ profitability is sensitive to
changes in wholesale supply costs, it will be adversely affected if we cannot pass on increases in
cost to our customers. Due to competitive pricing in the
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 LPG 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 LPG 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 and
attrition. A reduction in demand could lower our revenues, and therefore, lower our net income and
adversely affect our cash flows. State and/or federal regulation may require mandatory conservation
measures which would reduce the demand for our energy products. 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.
Volatility in credit and capital markets may restrict our ability to grow, increase the
likelihood of defaults by our customers and counterparties and adversely affect our operating
results.
The recent volatility in credit and capital markets may create additional risks to our
businesses in the future. We are exposed to financial market risk (including refinancing risk)
resulting from, among other things, changes in interest rates, foreign currency exchange rates and
conditions in the credit and capital markets. Recent developments in the credit markets increase
our possible exposure to the liquidity, default and credit risks of our suppliers, counterparties
associated with derivative financial instruments and our customers. Although we believe that recent
financial market conditions, if they were to continue for the foreseeable future, will not have a
significant impact on our ability to fund our existing operations, such market conditions could
restrict our ability to grow through acquisitions, limit the scope of major capital projects if
access to credit and capital markets is limited, or could otherwise adversely affect our operating
results.
The economic recession, volatility in the stock market and the low interest rate environment may
negatively impact our pension liability.
The recent economic recession, the decline in the stock market and the low interest rate
environment have had a significant impact on our pension liability and funded status. Additional
declines in the stock market and valuation of stocks, combined with continued low interest rates,
could further impact our pension liability and increase the amount of required contributions to our
pension plans.
Supplier defaults may have a negative effect on our operating results.
When the Company enters into fixed-price sales contracts with customers, it typically 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, natural gas and
electricity, a default of one or more of our suppliers under such contracts could cause us to
purchase those commodities at higher prices which would have a negative impact on our operating
results.
We are dependent on our principal propane suppliers, which increases the risks from an
interruption in supply and transportation.
During Fiscal 2010, AmeriGas Propane purchased approximately 82% of its propane needs from ten
suppliers. If supplies from these sources were interrupted, the cost of procuring replacement
supplies and transporting those supplies from alternative locations might be materially higher and,
at least on a short-term basis, our earnings could be affected. Additionally, in certain areas, a
single supplier provides more than 50% of AmeriGas Propane’s propane requirements. Disruptions in
supply in these areas could also have an adverse impact on our earnings. Antargaz and Flaga are
similarly dependent upon their suppliers. There is no assurance that Antargaz and Flaga will be
able to
continue to acquire sufficient supplies of LPG to meet demand at prices or within time periods
that would allow them to remain competitive.
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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, as well as
our use of financial instruments to reduce volatility in the cost of LPG, electricity or natural
gas, and for all of our contracts with the NYMEX, changes in the market price of LPG, electricity
and natural gas can create margin payment obligations 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. In the United States, 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.
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.
In addition, due to the prevalence of nuclear electric generation in France, the cost of electricity is generally
less expensive than that of LPG.
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 LPG
industry.
The retail LPG distribution industry in the U.S., France, Austria and Denmark is mature, with
no growth, or modest declines in total demand foreseen. Given this forecast, we expect that
year-to-year industry volumes will be principally affected by weather patterns. Therefore, our
ability to grow within the LPG industry is dependent on our ability to acquire other retail
distributors and to achieve internal growth, which includes expansion of the domestic ACE and
Strategic Accounts programs in the U.S., 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 we will be able to finance acquisitions 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.
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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.
Expanding our midstream asset business by constructing new facilities subjects us to risks.
One of the ways we seek to grow our midstream asset business is by constructing new pipelines
and gathering systems, expanding our LNG facility and improving our gas storage facilities. These
construction projects involve numerous regulatory, environmental, political and legal uncertainties
beyond our control and require the expenditure of significant amounts of capital. These projects
may not be completed on schedule, or at all, or at the anticipated costs. Moreover, our revenues
may not increase immediately upon the expenditure of funds on a particular project. We may
construct facilities to capture anticipated future growth in production and demand in an area in
which anticipated growth and demand does not materialize. As a result, there is the risk that new
and expanded facilities may not be able to attract enough customers to achieve our expected
investment returns, which could have a material adverse effect on our business, results of
operations or financial condition.
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.
Regulators may not allow timely recovery of costs for UGI Utilities in the future, which may
adversely affect our results of operations.
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 its subsidiaries,
PNG and CPG, may charge their utility customers, thus impacting the returns that UGI Utilities may
earn on the assets that are dedicated to those operations. We expect that PNG and CPG will
periodically file requests with the PUC to increase base rates that each company charges customers.
If UGI Utilities is required in a rate proceeding to reduce the rates it charges its utility
customers, or if UGI Utilities is unable to obtain approval for timely rate increases from the PUC,
particularly when necessary to cover increased costs, UGI Utilities’ revenue growth will be limited
and earnings may decrease.
Our operations, capital expenditures and financial results may be affected by regulatory changes
and/or market responses to global climate change.
There continues to be concern, both nationally and internationally, about climate change and
the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global
warming.
In addition to carbon dioxide, greenhouse gases include, among others, methane, a component of natural gas.
While some states have adopted laws regulating the emission of GHGs for some industry
sectors, there is currently no federal regulation mandating the reduction of GHG emissions in the
United States. In June of 2009, the United States House of Representatives passed the American
Clean Energy and Security Act (“ACES Act”). The ACES Act would establish an economy-wide GHG
cap-and-trade system to reduce GHG emissions over time. The United States Senate has been
considering a number of related proposals, ranging from “energy only” bills to proposals that place
an economy-wide cap on greenhouse gas emissions. No legislation can be enacted until a final
reconciled bill is approved by both the House of Representatives and
the Senate and signed by the President.
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Even if Congress does not pass legislation mandating GHG emissions reductions, there continue to be regulatory
developments under the Clean Air Act applicable to GHGs. In September 2009, the Environmental Protection Agency (‘EPA’)
issued a final rule establishing a system for mandatory reporting of GHG emissions. In November 2010, the EPA expanded
the reach of its GHG reporting requirements to include the petroleum and natural gas industries. Petroleum and natural
gas facilities subject to the rule, which include facilities of our natural gas distribution and electricity generation
businesses, are required to begin emissions monitoring in January 2011 and to submit detailed annual reports beginning
in March 2012. The rule does not require affected facilities to implement GHG emission controls or reductions. In
December 2009, the EPA published its findings that emissions of GHGs constitute an endangerment to public health and
the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs
under existing provisions of the Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would
limit GHG emissions from new motor vehicles and that would impose permit requirements for GHG emissions from certain
stationary sources. Legal challenges have been filed against many of EPA’s rulemakings, and we are unable to predict
the results of those challenges.
It is expected that climate change legislation will continue to be part of the legislative and
regulatory discussion for the foreseeable future. Increased regulation of GHG emissions, especially
in the transportation sector, could impose significant additional costs on us and our customers.
The impact of legislation and regulations on us will depend on a number of factors, including (i)
what industry sectors would be impacted, (ii) the timing of required compliance, (iii) the overall
GHG emissions cap level, (iv) the allocation of emission allowances to specific sources, and (v)
the costs and opportunities associated with compliance. At this time, we cannot predict the effect
that climate change regulation may have on our business, financial condition or results of
operations in the future.
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. As a result, we
are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of
business. 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.
Our net income will decrease if we are required to incur additional costs to comply with new
governmental safety, health, transportation, tax and environmental regulations.
We are subject to extensive and changing international, federal, state and local safety,
health, transportation, tax 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 obtain or 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.
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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 currently be recovered in PUC 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.
Our international operations could result in increased risks which may negatively affect our
business results.
We currently operate LPG distribution businesses in Europe through our subsidiaries, Antargaz,
Flaga and Kosan Gas and we continue to explore the expansion of our international businesses. As a
result, 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; |
||
| • | 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; |
||
| • | internal control and risk management practices and policies; |
||
| • | regulatory requirements and changes in regulatory requirements, including French,
Austrian, Danish 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; and |
||
| • | new and inconsistently enforced LPG industry regulatory requirements, which can have an
adverse effect on our competitive position. |
Unforeseen difficulties with the implementation or operation of our information systems could
adversely affect our internal controls and our businesses.
We contracted with third-party consultants to assist us with the design and implementation of
an information system that supports the AmeriGas Order-to-Cash business processes. The efficient
execution of AmeriGas’ business is dependent upon the proper functioning of its internal systems.
Any significant failure or malfunction of AmeriGas’ or our other business units’ information
systems may result in disruptions of their operations. Our results of operations could be adversely
affected if we encounter unforeseen problems with respect to the operation of our information
systems.
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ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
Antargaz Competition Authority Matter. On July 21, 2009, Antargaz received a Statement of
Objections from France’s Autorité de la concurrence (“Competition Authority”) with respect to the
investigation of Antargaz by the General Division of Competition, Consumption and Fraud Punishment
(“DGCCRF”). A Statement of Objections (“Statement”) is part of French competition proceedings and
generally follows an investigation under French competition laws. The Statement sets forth the
Competition Authority’s findings; it is not a judgment or final decision. The Statement alleges
that Antargaz engaged in certain anti-competitive practices in violation of French and European
Union civil competition laws related to the cylinder market during the period from 1999 through
2004. The alleged violations occurred principally during periods prior to March 31, 2004, when UGI
first obtained a controlling interest in Antargaz.
We filed our written response to the Statement of Objections with the Competition Authority on
October 21, 2009. The Competition Authority completed its review of Antargaz’ response and issued
its report on April 26, 2010 (“Report”). The Report is the third pleading typically filed in a
competition proceeding, preceded first by a Statement of Objections filed by the Competition
Authority, and then the Answer to the Statement filed by the defendant in the proceeding. The
Report is, in essence, a revised version of the Statement which takes into consideration both the
evidence and arguments made by a defendant in its Answer to the Statement. Similarly, in response
to the Report, a defendant has the opportunity to file an Answer to the Report. Following
submission of the two rounds of pleadings, a hearing is scheduled to allow the respective parties
to present oral argument on the allegations contained in the Statement and Report.
In its Report, the Competition Authority stated its intent to prosecute two of the alleged violations of French
competition (antitrust) law. The alleged violations were that Antargaz abused its collective dominant position
by: (i) refusing to provide a new competitor with access to liquid petroleum gas filling centers; and (ii)
exerting pressure on a cylinder manufacturer not to do business with that competitor. The Report also
recommended the abandonment of the third and final alleged violation, which involved an alleged illegal sharing
of pricing information by Antargaz. The Report did not contain any new allegations. Although the Report and the
Statement did not specify the nature or amount of relief being sought by the Competition Authority, the
applicable statutes provide for maximum penalties of up to 10% of a company’s or parent company’s consolidated
annual revenues, levied on the highest annual revenue beginning with the fiscal year immediately preceding the
year in which the alleged violations first occurred. Based on our understanding of cases of this nature, we have
recorded a reserve of $10 million, which we based on the revenues of Antargaz, rather than on the consolidated
revenues of UGI, because UGI has not been named as a party to these proceedings.
Antargaz filed its Answer to the Report
on June 28, 2010 and a hearing before the Competition Authority was held on September 21, 2010
(“Hearing”). Based on our review of the Report and participation in oral argument at the Hearing,
we continue to believe that the $10 million reserve previously established by management is
adequate. Notwithstanding our view, the final resolution could result in payment of an amount
significantly different from the amount we have recorded. The
relief to be awarded in this matter, if any, will not be known until a decision on the action has
been issued.
With the exception of the matter described above, and those matters set forth in Note 15 to
Consolidated Financial Statements included in Item 8 of this Report, 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.
ITEM 4. (REMOVED AND RESERVED)
EXECUTIVE OFFICERS
Information regarding our executive officers is included in Part III of this Report and is
incorporated in Part I by reference.
26
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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 Stock Exchange 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:
| 2010 Fiscal Year | High | Low | ||||||
4th Quarter |
$ | 29.00 | $ | 24.90 | ||||
3rd Quarter |
27.88 | 24.30 | ||||||
2nd Quarter |
26.95 | 23.83 | ||||||
1st Quarter |
25.65 | 23.18 | ||||||
| 2009 Fiscal Year | High | Low | ||||||
4th Quarter |
$ | 26.99 | $ | 24.32 | ||||
3rd Quarter |
26.04 | 22.11 | ||||||
2nd Quarter |
27.38 | 21.135 | ||||||
1st Quarter |
26.68 | 18.69 | ||||||
Dividends
Quarterly dividends on our Common Stock were paid in Fiscal 2010 and Fiscal 2009 as follows:
| 2010 Fiscal Year | Amount | |||
4th Quarter |
$ | 0.25000 | ||
3rd Quarter |
0.20000 | |||
2nd Quarter |
0.20000 | |||
1st Quarter |
0.20000 | |||
| 2009 Fiscal Year | Amount | |||
4th Quarter |
$ | 0.20000 | ||
3rd Quarter |
0.19250 | |||
2nd Quarter |
0.19250 | |||
1st Quarter |
0.19250 | |||
Record Holders
On November 15, 2010, UGI had 7,780 holders of record of Common Stock.
27
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ITEM 6. SELECTED FINANCIAL DATA
| Year Ended September 30, | ||||||||||||||||||||
| (Millions of dollars, except per share amounts) | 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||||
FOR THE PERIOD: |
||||||||||||||||||||
Income statement data: |
||||||||||||||||||||
Revenues |
$ | 5,591.4 | $ | 5,737.8 | $ | 6,648.2 | $ | 5,476.9 | $ | 5,221.0 | ||||||||||
Net income |
$ | 355.7 | $ | 382.0 | (a) | $ | 305.3 | (a) | $ | 311.2 | (a) | $ | 224.9 | (a) | ||||||
Less: net income attributable to noncontrolling interests,
principally in AmeriGas Partners |
(94.7 | ) | (123.5 | )(a) | (89.8 | )(a) | (106.9 | )(a) | (48.7 | )(a) | ||||||||||
Net income attributable to UGI Corporation |
$ | 261.0 | $ | 258.5 | (a) | $ | 215.5 | (a) | $ | 204.3 | (a) | $ | 176.2 | (a) | ||||||
Earnings per common share attributable to UGI stockholders: |
||||||||||||||||||||
Basic |
$ | 2.38 | $ | 2.38 | $ | 2.01 | $ | 1.92 | $ | 1.67 | ||||||||||
Diluted |
$ | 2.36 | $ | 2.36 | $ | 1.99 | $ | 1.89 | $ | 1.65 | ||||||||||
Cash dividends declared per common share |
$ | 0.90 | $ | 0.785 | $ | 0.755 | $ | 0.723 | $ | 0.690 | ||||||||||
AT PERIOD END: |
||||||||||||||||||||
Balance sheet data: |
||||||||||||||||||||
Total assets |
$ | 6,374.3 | $ | 6,042.6 | $ | 5,685.0 | $ | 5,502.7 | $ | 5,080.5 | ||||||||||
Capitalization: |
||||||||||||||||||||
Debt: |
||||||||||||||||||||
Bank loans — UGI Utilities |
$ | 17.0 | $ | 154.0 | $ | 57.0 | $ | 190.0 | $ | 216.0 | ||||||||||
Bank loans — AmeriGas Propane |
91.0 | — | — | — | — | |||||||||||||||
Bank loans — Antargaz |
68.2 | — | 70.4 | — | — | |||||||||||||||
Bank loans — other |
24.2 | 9.1 | 9.0 | 8.9 | 9.4 | |||||||||||||||
Long-term
debt (including current maturities): |
||||||||||||||||||||
AmeriGas Propane |
791.4 | 865.6 | 933.4 | 933.1 | 933.7 | |||||||||||||||
Antargaz |
519.1 | 557.7 | 537.4 | 544.9 | 483.5 | |||||||||||||||
UGI Utilities |
640.0 | 640.0 | 532.0 | 512.0 | 512.0 | |||||||||||||||
Other |
55.3 | 69.8 | 66.3 | 63.5 | 67.7 | |||||||||||||||
Total debt |
2,206.2 | 2,296.2 | 2,205.5 | 2,252.4 | 2,222.3 | |||||||||||||||
UGI Corporation stockholders’ equity |
1,824.5 | 1,591.4 | 1,417.7 | 1,321.9 | 1,099.6 | |||||||||||||||
Noncontrolling interests, principally in AmeriGas Partners |
237.1 | 225.4 | 159.2 | 192.2 | 139.5 | |||||||||||||||
Total capitalization |
$ | 4,267.8 | $ | 4,113.0 | $ | 3,782.4 | $ | 3,766.5 | $ | 3,461.4 | ||||||||||
Ratio of capitalization: |
||||||||||||||||||||
Total debt |
51.7 | % | 55.8 | % | 58.3 | % | 59.8 | % | 64.2 | % | ||||||||||
UGI Corporation stockholders’ equity |
42.8 | % | 38.7 | % | 37.5 | % | 35.1 | % | 31.8 | % | ||||||||||
Noncontrolling interests, principally in AmeriGas Partners |
5.5 | % | 5.5 | % | 4.2 | % | 5.1 | % | 4.0 | % | ||||||||||
| 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | |||||||||||
| (a) | As adjusted in accordance
with the transition provisions for accounting for and presentation of noncontrolling interests in
consolidated subsidiaries (see Note 3 to Consolidated Financial
Statements). |
28
Table of Contents
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”)
discusses our results of operations and our financial condition. MD&A should be read in conjunction
with our Items 1 & 2, “Business and Properties,” our Item 1A, “Risk Factors” and our Consolidated
Financial Statements in Item 8 below including “Segment Information” included in Note 21 to
Consolidated Financial Statements. The business segment comprising Energy Services and its
consolidated subsidiaries is referred to as “Midstream & Marketing” below.
Executive Overview
We recorded net income attributable to UGI Corporation of $261.0 million, equal to $2.36 per
diluted share, in Fiscal 2010 compared to net income attributable to UGI Corporation of $258.5
million, equal to $2.36 per diluted share, in Fiscal 2009. Although Fiscal 2010 net income
attributable to UGI Corporation and earnings per diluted share were comparable to those items in
Fiscal 2009, the contribution to net earnings by business segment was significantly different.
Midstream & Marketing net income increased $30.1 million in Fiscal 2010 reflecting a $17.2
million gain from the sale of Energy Services’ Atlantic Energy, LLC (“Atlantic Energy”) subsidiary
and the benefits of higher natural gas and electricity marketing total margin. Gas Utility’s
contribution to net income attributable to UGI Corporation increased $12.8 million in Fiscal 2010
reflecting the full-year effects of the PNG Gas and CPG Gas August 2009 base rate increases and
lower operating and administrative expenses. Substantially offsetting the increases in Midstream &
Marketing and Gas Utility Fiscal 2010 results were lower contributions principally from our
International Propane and AmeriGas Propane business segments. International Propane’s Fiscal 2010
contribution to net income attributable to UGI Corporation was significantly lower than in Fiscal
2009 as the prior-year’s results benefited from unit margins at Antargaz that were significantly
higher than normal following a precipitous decline in LPG commodity costs that occurred as Antargaz
entered the Fiscal 2009 winter heating season. AmeriGas Propane’s contribution to earnings was
$17.7 million lower in Fiscal 2010 principally reflecting the absence of an after-tax gain from the sale of the
Partnership’s California storage facility recorded in Fiscal 2009 ($10.4 million), the impact of
after-tax losses on interest rate protection agreements recorded in Fiscal 2010 ($3.3 million) and
the effects of lower Partnership total margin.
Looking ahead, we expect our results in Fiscal 2011 to be influenced by a number of factors
including, among others, heating-season temperatures in our business units’ service territories;
the strength of the economic recovery in the United States and Europe; declining LPG usage
resulting from competition from other types of energy and ongoing customer conservation; and the
level and volatility of commodity prices for natural gas, LPG and electricity.
We believe that each of our business units has sufficient liquidity in the form of revolving
credit facilities and, in the case of Energy Services, an accounts receivable securitization
facility to fund business operations in Fiscal 2011. We have €380 million of Antargaz term loans
and €25.4 million of Flaga term loans maturing in Fiscal 2011. We intend to refinance this maturing
debt on a long-term basis. Additionally, UGI Utilities expects to renew its revolving credit
agreement prior to its expiration in August 2011 and AmeriGas OLP expects to renew its credit
facilities, which are scheduled to expire in June 2011 and October 2011, during the second half of
Fiscal 2011. Energy Services intends to extend its receivables securitization facility prior to its
expiration in April 2011.
As further described in Note 3 to Consolidated Financial Statements, effective October 1,
2009, we adopted guidance regarding the accounting for and presentation of noncontrolling interests
in consolidated financial statements. The new guidance significantly changed the accounting and
reporting relating to noncontrolling interests in a consolidated subsidiary. Noncontrolling
interests are now classified as a component of equity on the Consolidated Balance Sheets, a change
from their prior classification between liabilities and stockholders’ equity. Earnings attributable
to noncontrolling interests are now included in net income and deducted from net income to
determine net income attributable to UGI Corporation. In accordance with the new guidance,
prior-year periods have been adjusted. The new guidance had no effect on our basic or diluted
earnings per share.
29
Table of Contents
Results of Operations
The following analyses compare the Company’s results of operations for (1) Fiscal 2010 with
Fiscal 2009 and (2) Fiscal 2009 with the year ended September 30, 2008 (“Fiscal 2008”). As
previously mentioned, our consolidated results of operations for Fiscal 2009 and Fiscal 2008
reflect the retroactive effects of the Financial Accounting Standards Board’s (“FASB’s”) accounting
guidance for the presentation of noncontrolling interests in consolidated financial statements.
Fiscal 2010 Compared with Fiscal 2009
Consolidated Results
Consolidated Results
Net Income (Loss) Attributable to UGI Corporation by Business Unit:
| Variance - Favorable | ||||||||||||||||||||||||
| 2010 | 2009 | Unfavorable | ||||||||||||||||||||||
| % of | % of | % of | ||||||||||||||||||||||
| (Millions of dollars) | Amount | Total | Amount | Total | Amount | Total | ||||||||||||||||||
AmeriGas Propane |
$ | 47.3 | 18.1 | % | $ | 65.0 | 25.1 | % | $ | (17.7 | ) | (27.2 | )% | |||||||||||
International Propane |
58.8 | 22.5 | % | 78.3 | 30.3 | % | (19.5 | ) | (24.9 | )% | ||||||||||||||
Gas Utility |
83.1 | 31.8 | % | 70.3 | 27.2 | % | 12.8 | 18.2 | % | |||||||||||||||
Electric Utility |
6.8 | 2.6 | % | 8.0 | 3.1 | % | (1.2 | ) | (15.0 | )% | ||||||||||||||
Midstream & Marketing |
68.2 | 26.1 | % | 38.1 | 14.7 | % | 30.1 | 79.0 | % | |||||||||||||||
Corporate & Other |
(3.2 | ) | (1.1 | )% | (1.2 | ) | (0.4 | )% | (2.0 | ) | N.M. | |||||||||||||
Net income attributable to UGI Corporation |
$ | 261.0 | 100.0 | % | $ | 258.5 | 100.0 | % | $ | 2.5 | 1.0 | % | ||||||||||||
N.M. — Variance is not meaningful. |
||
Highlights — Fiscal 2010 versus Fiscal 2009
| • | Gas Utility results in Fiscal 2010 reflect the full-year impact of the PNG Gas and CPG
Gas August 2009 base rate revenue increases. |
| • | Midstream & Marketing’s Fiscal 2010 net income includes a $17.2 million after-tax gain
on the sale of Midstream & Marketing’s Atlantic Energy subsidiary. |
| • | AmeriGas Propane Fiscal 2010 results include a $3.3 million after-tax loss on interest
rate hedges while Fiscal 2009 results include a $10.4 million after-tax gain from the sale
of its California LPG storage terminal. |
| • | Fiscal 2010 International Propane results reflect lower average unit margins compared
with the higher than normal unit margins in Fiscal 2009. |
| • | Midstream & Marketing’s Fiscal 2010 results benefited from greater natural gas and
retail power margin. |
| • | The lingering effects of the global economic recession continued to impact overall
business activity in all of our business units. |
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| Increase | ||||||||||||||||
| AmeriGas Propane | 2010 | 2009 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 2,320.3 | $ | 2,260.1 | $ | 60.2 | 2.7 | % | ||||||||
Total margin (a) |
$ | 925.2 | $ | 943.6 | $ | (18.4 | ) | (1.9 | )% | |||||||
Partnership EBITDA (b) |
$ | 321.0 | $ | 381.4 | $ | (60.4 | ) | (15.8 | )% | |||||||
Operating income |
$ | 235.8 | $ | 300.5 | $ | (64.7 | ) | (21.5 | )% | |||||||
Retail gallons sold (millions) |
893.4 | 928.2 | (34.8 | ) | (3.7 | )% | ||||||||||
Degree days — % (warmer) than normal (c) |
(2.2 | )% | (3.1 | )% | — | — | ||||||||||
| (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) 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
segment (see Note 21 to Consolidated Financial Statements). Partnership EBITDA (and operating
income) in Fiscal 2010 includes a pre-tax loss of $12.2 million associated with the
discontinuance of interest rate hedges and a loss of $7 million associated with an increase
in a litigation accrual. Partnership EBITDA (and operating income) in Fiscal 2009 includes a
pre-tax gain of $39.9 million associated with the sale of the Partnership’s California LPG
storage facility. |
|
| (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. Fiscal 2009 data has been
adjusted to correct a NOAA error. |
Based upon heating degree-day data, average temperatures in our service territories were 2.2%
warmer than normal during Fiscal 2010 compared with temperatures in the prior year that were 3.1%
warmer than normal. Fiscal 2010 retail gallons sold were lower reflecting, among other things, the
lingering effects of the economic recession, customer conservation and customer attrition partially
offset by volumes acquired through business acquisitions.
Retail propane revenues increased $20.2 million during Fiscal 2010 reflecting an increase as a
result of higher average retail sales prices ($94.3 million) partially offset by lower retail
volumes sold ($74.1 million). Wholesale propane revenues increased $46.7 million principally
reflecting higher year-over-year wholesale selling prices ($37.5 million) and, to a lesser extent,
higher wholesale volumes sold ($9.2 million). Average wholesale propane prices at Mont Belvieu,
Texas, were approximately 47% higher during Fiscal 2010 compared with average wholesale propane
prices during Fiscal 2009. The lower average wholesale propane prices in Fiscal 2009 principally
resulted from a precipitous decline in prices that occurred during the first quarter of Fiscal
2009. Other revenues decreased $6.7 million in Fiscal 2010 compared with Fiscal 2009. Total cost
of sales increased $78.6 million, to $1,395.1 million, principally reflecting the higher 2010
wholesale propane product costs.
Total margin was $18.4 million lower in Fiscal 2010 primarily due to lower total retail margin
($21.9 million). The lower total retail margin reflects the effects of the lower retail volumes
sold ($31.4 million) partially offset by the effects of slightly higher average retail unit margins
($9.5 million) including higher unit margins in our AmeriGas Cylinder Exchange program.
The $60.4 million decrease in Partnership EBITDA during Fiscal 2010 reflects (1) the absence
of a pre-tax gain recorded in Fiscal 2009 associated with the November 2008 sale of the
Partnership’s California LPG storage facility ($39.9 million); (2) the previously mentioned decline
in Fiscal 2010 total margin ($18.4 million); and (3) a loss from the discontinuance of interest
rate hedges ($12.2 million). During the three months ended March 31, 2010, the Partnership’s
management determined that it was likely that it would not issue a previously anticipated $150
million of long-term debt during the summer of 2010. As a result, the Partnership discontinued cash
flow hedge accounting treatment for interest rate protection agreements associated with this
previously anticipated debt issuance and recorded a $12.2 million loss which is reflected in other
(income) expense, net on the Fiscal 2010 Consolidated Statement of Income. These previously
mentioned declines in EBITDA were partially offset by a decrease in operating and administrative
expenses ($5.4 million) largely due to lower self-insured liability and casualty expenses ($9.2
million) and lower compensation and benefits expense ($4.7 million) partially offset by an increase
in a litigation accrual recorded during the fourth quarter of Fiscal 2010 ($7.0 million).
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Operating income in Fiscal 2010 decreased $64.7 million reflecting the previously mentioned
decrease in Partnership EBITDA ($60.4 million) and slightly higher depreciation and amortization
expense associated with fixed assets acquired during the past year ($3.6 million). Partnership
interest expense was $5.2 million lower in Fiscal 2010 principally reflecting lower interest
expense on lower long-term debt outstanding.
| Increase | ||||||||||||||||
| International Propane | 2010 | 2009 | (Decrease) | |||||||||||||
(Millions of euros) (a) |
||||||||||||||||
Revenues |
€ | 763.1 | € | 712.7 | € | 50.4 | 7.1 | % | ||||||||
Total margin (b) |
€ | 345.8 | € | 392.7 | € | (46.9 | ) | (11.9 | )% | |||||||
Operating income |
€ | 82.4 | € | 116.3 | € | (33.9 | ) | (29.1 | )% | |||||||
Income before income taxes |
€ | 62.2 | € | 95.3 | € | (33.1 | ) | (34.7 | )% | |||||||
(Millions of dollars) (a) |
||||||||||||||||
Revenues |
$ | 1,059.5 | $ | 955.3 | $ | 104.2 | 10.9 | % | ||||||||
Total margin (b) |
$ | 477.4 | $ | 525.8 | $ | (48.4 | ) | (9.2 | )% | |||||||
Operating income |
$ | 117.0 | $ | 151.4 | $ | (34.4 | ) | (22.7 | )% | |||||||
Income before income taxes |
$ | 89.5 | $ | 122.0 | $ | (32.5 | ) | (26.6 | )% | |||||||
Antargaz retail gallons sold |
279.9 | 289.3 | (9.4 | ) | (3.2 | )% | ||||||||||
Degree days — % (warmer) than normal (c) |
(0.5 | )% | (2.9 | )% | — | — | ||||||||||
| (a) | Euro amounts represent amounts for Antargaz and Flaga. U.S. dollar amounts include
Antargaz and Flaga as well as our operations in China and certain non-operating entities
associated with our International Propane segment. |
|
| (b) | Total margin represents total revenues less total cost of sales. |
|
| (c) | Deviation from average heating degree days for the 30-year period 1971-2000 at more
than 30 locations in our French service territory. |
International Propane operating results in Fiscal 2010 reflect the full-year consolidation of
Zentraleuropa LPG Holdings GmbH (“ZLH”). In January 2009, Flaga purchased for cash consideration
the 50% equity interest in ZLH it did not already own. International Propane acquisitions completed
during Fiscal 2010 did not have a material effect on results of operations.
Based upon heating degree day data, temperatures in Antargaz’ service territory were 0.5%
warmer than normal during Fiscal 2010 compared with temperatures that were 2.9% warmer than normal
during Fiscal 2009. Temperatures in Flaga’s service territory were slightly colder than the prior
year. The average wholesale commodity price for propane and butane in northwest Europe during
Fiscal 2010 was approximately 48% higher than prices during Fiscal 2009. The lower average LPG
wholesale prices in the prior-year period reflect precipitous declines in propane and butane
wholesale prices principally during the first quarter of Fiscal 2009. Antargaz’ Fiscal 2010 retail
propane volumes were lower than in the prior-year period principally as a result of reduced demand
for crop drying earlier in Fiscal 2010 which was the result of an exceptionally dry 2009 summer,
the effects of customer conservation and the lingering effects of the economic recession in France.
Our International Propane base-currency results are translated into U.S. dollars based upon
exchange rates experienced during each of the reporting periods. During Fiscal 2010, the
un-weighted average currency translation rate was $1.36 per euro compared to a rate of $1.35 per
euro during Fiscal 2009, although the dollar was generally weaker than the euro during the peak
earnings months of October to March in Fiscal 2010. The differences in exchange rates did not have
a material impact on International Propane net income.
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Table of Contents
International Propane euro-based revenues increased €50.4 million or 7.1%. The higher Fiscal
2010 revenues principally resulted from the higher Fiscal 2010 wholesale LPG product costs. U.S.
dollar revenues increased $104.2 million or 10.9% principally reflecting the higher euro-based
revenues. International Propane’s euro-based total cost of sales increased to €417.3 million in
Fiscal 2010 from €320.0 million in the prior year, an increase of 30.4%, reflecting the higher
per-unit LPG commodity costs. U.S. dollar cost of sales increased to $582.1 million in Fiscal 2010
from $429.5 million in Fiscal 2009, an increase of 35.5%, principally reflecting the higher euro
base-currency cost of sales.
International Propane euro-denominated total margin decreased €46.9 million or 11.9% in Fiscal
2010 principally reflecting lower Antargaz total margin (€49.7 million) reflecting the effects of
lower average Antargaz retail unit margins (€37.8 million) and, to a much lesser extent, the lower
Antargaz retail gallons sold (€10.3 million). Antargaz’ euro-denominated retail unit margins were
lower in Fiscal 2010 compared with Fiscal 2009 as the prior-year unit margins were higher than
normal due to the rapid and sharp decline in LPG commodity costs that occurred as Antargaz entered
the Fiscal 2009 winter heating season. U.S. dollar total margin decreased $48.4 million or 9.2%
principally reflecting the lower euro-denominated total margin.
International Propane euro base-currency operating income decreased €33.9 million or 29.1% in
Fiscal 2010 principally reflecting the previously mentioned decrease in euro-based International
Propane total margin (€46.9 million) offset by the absence of a charge associated with the Antargaz
Competition Authority Matter recorded in the prior year (€7.1 million) and lower total Fiscal 2010
operating and administrative expenses (€10.5 million). On a U.S. dollar basis, operating income
decreased $34.4 million or 22.7% reflecting the previously mentioned decrease in U.S.
dollar-denominated total margin ($48.4 million) and higher depreciation expense ($3.9 million)
partially offset by the absence of the charge for the Antargaz Competition Authority Matter
recorded in the prior-year period ($10.0 million) and lower total operating and administrative
expenses ($9.5 million). Euro base-currency income before income taxes was €33.1 million or 34.7%
lower than in the prior-year period primarily reflecting the decline in operating income (€33.9
million). U.S. dollar income before income taxes decreased $32.5 million or 26.6%.
| Increase | ||||||||||||||||
| Gas Utility | 2010 | 2009 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 1,047.5 | $ | 1,241.0 | $ | (193.5 | ) | (15.6 | )% | |||||||
Total margin (a) |
$ | 394.1 | $ | 387.8 | $ | 6.3 | 1.6 | % | ||||||||
Operating income |
$ | 175.3 | $ | 153.5 | $ | 21.8 | 14.2 | % | ||||||||
Income before income taxes |
$ | 134.8 | $ | 111.3 | $ | 23.5 | 21.1 | % | ||||||||
System throughput — billions of cubic feet (“bcf”) |
153.9 | 149.7 | 4.2 | 2.8 | % | |||||||||||
Degree days — % (warmer) colder than normal (b) |
(5.3 | )% | 4.1 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Deviation from average heating degree days for the 15-year period 1990-2004 based upon
weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”)
for airports located within Gas Utility’s service territory. |
Temperatures in the Gas Utility service territory based upon heating degree days were 5.3%
warmer than normal in Fiscal 2010 compared with temperatures that were 4.1% colder than normal in
Fiscal 2009. Total distribution system throughput increased 4.2 bcf in Fiscal 2010, despite the
warmer weather, principally reflecting an 8.5 bcf increase in low margin interruptible delivery
service volumes. Gas Utility’s core market volumes decreased 6.2 bcf (9.0%) due to the previously
mentioned warmer weather and to a lesser extent the sluggish economy and customer conservation. Gas
Utility’s core-market customers are comprised of firm- residential, commercial and industrial
(“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser
extent, residential and small commercial customers who purchase their gas from alternate suppliers.
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Table of Contents
Gas Utility revenues decreased $193.5 million during Fiscal 2010 principally reflecting a
decline in revenues from retail core-market customers ($232.3 million) partially offset by a $29.4
million increase in revenues from low-margin off-system sales. The decrease in retail core-market
revenues principally resulted from the effects of lower average PGC
rates ($135.0 million) and the
lower retail core-market volumes ($125.5 million). These decreases in revenues were partially
offset by the effects of the PNG Gas and CPG Gas base operating revenue increases that became
effective August 28, 2009. Increases or decreases in retail core-market 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 amounts 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 $653.4 million in Fiscal 2010 compared with
$853.2 million in Fiscal 2009 principally reflecting the previously mentioned lower retail
core-market sales and average PGC rates ($227.8 million) due to lower natural gas commodity prices.
Notwithstanding the decrease in distribution system volumes, Gas Utility total margin
increased $6.3 million in Fiscal 2010. The increase is principally the result of the PNG Gas and
CPG Gas base operating revenue increases ($28.2 million) substantially offset by the effect on
total margin from the lower core-market volumes.
Gas Utility operating income in Fiscal 2010 increased $21.8 million principally reflecting
lower operating and administrative costs ($15.6 million) and the previously mentioned increase in
total margin ($6.3 million). Fiscal 2010 operating and administrative costs include, among other
things, lower uncollectible accounts and customer assistance expenses ($11.5 million) and lower
costs associated with environmental matters ($6.6 million). These decreases were partially offset
by higher depreciation expense ($2.2 million) and higher pension expense ($2.1 million). The
increase in income before income taxes reflects the previously mentioned higher operating income
($21.8 million) and lower interest expense ($1.6 million) due to lower average bank loan
borrowings.
| Increase | ||||||||||||||||
| Electric Utility | 2010 | 2009 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 120.2 | $ | 138.5 | $ | (18.3 | ) | (13.2 | )% | |||||||
Total margin (a) |
$ | 36.5 | $ | 39.3 | $ | (2.8 | ) | (7.1 | )% | |||||||
Operating income |
$ | 13.7 | $ | 15.4 | $ | (1.7 | ) | (11.0 | )% | |||||||
Income before income taxes |
$ | 11.9 | $ | 13.7 | $ | (1.8 | ) | (13.1 | )% | |||||||
Distribution sales — millions of kilowatt hours (“gwh”) |
972.6 | 965.7 | 6.9 | 0.7 | % | |||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related
taxes, i.e. Electric Utility gross receipts taxes, of
$6.6 million and $7.6 million during
Fiscal 2010 and Fiscal 2009, respectively. For financial statement purposes,
revenue-related taxes are included in “Utility taxes other than income taxes” on the
Consolidated Statements of Income. |
Temperatures based upon heating degree days in Fiscal 2010 were approximately 6.8% warmer than
in Fiscal 2009. The impact on kilowatt-hour sales from the warmer heating-season weather was more
than offset by higher air-conditioning related sales from significantly warmer 2010 late spring and
summer weather.
Electric Utility revenues decreased $18.3 million principally as a result of certain
commercial and industrial customers switching to an alternate supplier for the generation portion
of their service and, to a lesser extent, lower default service (“DS”) rates effective January 1,
2010. Electric Utility decreased its DS rates effective January 1, 2010 pursuant to a January 22,
2009 settlement of its DS rate filing with the PUC. This reduced average costs to a residential
general and residential heating customer by nearly 10% and 4%, respectively, over such costs in
Fiscal 2009 and also reduced rates to commercial and industrial customers. Under DS rates, Electric
Utility is no longer subject to electric generation price and congestion cost risk as it is
permitted to pass these costs through to its customers using a reconcilable cost recovery
mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for
future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility can no
longer recover revenues in excess of actual costs of electricity as was possible under previous
Provider of Last Resort (“POLR”) rates in effect prior to January 1, 2010. Electric Utility cost of
sales declined to $77.1 million in Fiscal 2010 compared to $91.6 million in Fiscal 2009 principally
reflecting the effects of the previously mentioned generation supplier customer switching and lower
purchased power costs. For additional information on Electric Utility DS and POLR service, see Note
8 to Consolidated Financial Statements.
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Electric Utility total margin declined $2.8 million in Fiscal 2010 principally reflecting the
reduction in margin resulting from the implementation of lower DS rates effective January 1, 2010.
Electric Utility operating income and income before income taxes in Fiscal 2010 were $1.7
million and $1.8 million lower, respectively, than in Fiscal 2009 reflecting the lower total margin
($2.8 million) partially offset by lower operating and administrative expenses ($1.1 million).
| Increase | ||||||||||||||||
| Midstream & Marketing | 2010 | 2009 | Decrease | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 1,145.9 | $ | 1,224.7 | $ | (78.8 | ) | (6.4 | )% | |||||||
Total margin (a) |
$ | 135.2 | $ | 126.2 | $ | 9.0 | 7.1 | % | ||||||||
Operating income |
$ | 120.0 | $ | 64.8 | $ | 55.2 | 85.2 | % | ||||||||
Income before income taxes |
$ | 119.8 | $ | 64.8 | $ | 55.0 | 84.9 | % | ||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Midstream & Marketing total revenues decreased $78.8 million in Fiscal 2010 due to lower gas
marketing revenues ($114.1 million) principally from lower average natural gas prices partially
offset by the effects of higher retail power sales revenues ($36.8 million).
Total margin from Midstream & Marketing increased $9.0 million principally reflecting (1)
higher natural gas marketing margin ($10.5 million) due to higher natural gas marketing unit
margins and (2) higher total retail power marketing margin ($7.7 million) on higher volumes sold
and larger average unit margins. These increases in margin were partially offset by a decrease in
electric generation total margin ($6.9 million) principally from lower average unit margins. The
increase in natural gas marketing total margin includes the impact of marketing initiatives focused
on the small commercial customer segment. The increases in Midstream & Marketing’s operating income
and income before income taxes principally reflects a pre-tax gain from the sale of its Atlantic
Energy subsidiary ($36.5 million), the previously mentioned increase in total margin ($9.0 million)
and lower operating and administrative costs ($4.8 million), principally from lower total electric
generation operating and maintenance costs ($5.1 million) primarily costs associated with the
Hunlock generating station which ceased operating in May 2010 as it transitions to a gas-fired
generating station.
Interest Expense and Income Taxes. Consolidated interest expense decreased modestly to $133.8
million in Fiscal 2010 from $141.1 million in Fiscal 2009 principally due to lower interest expense
on AmeriGas Propane debt ($5.2 million) and lower interest on UGI Utilities revolving credit
agreement borrowings ($1.6 million). Our effective income tax
rate was modestly higher in Fiscal
2010 principally reflecting the effects of a lower percentage of pretax income from noncontrolling
interests, principally in AmeriGas Partners, generally not subject to income taxes.
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Table of Contents
Fiscal 2009 Compared with Fiscal 2008 Consolidated Results
Net Income (Loss) Attributable to UGI Corporation by Business Unit:
| Variance - Favorable | ||||||||||||||||||||||||
| 2009 | 2008 | Unfavorable | ||||||||||||||||||||||
| % of | % of | % of | ||||||||||||||||||||||
| (Millions of dollars) | Amount | Total | Amount | Total | Amount | Total | ||||||||||||||||||
AmeriGas Propane |
$ | 65.0 | 25.1 | % | $ | 43.9 | 20.4 | % | $ | 21.1 | 48.1 | % | ||||||||||||
International Propane |
78.3 | 30.3 | % | 52.3 | 24.3 | % | 26.0 | 49.7 | % | |||||||||||||||
Gas Utility |
70.3 | 27.2 | % | 60.3 | 28.0 | % | 10.0 | 16.6 | % | |||||||||||||||
Electric Utility |
8.0 | 3.1 | % | 13.1 | 6.1 | % | (5.1 | ) | (38.9 | )% | ||||||||||||||
Midstream & Marketing |
38.1 | 14.7 | % | 45.3 | 21.0 | % | (7.2 | ) | (15.9 | )% | ||||||||||||||
Corporate & Other |
(1.2 | ) | (0.4 | )% | 0.6 | 0.2 | % | (1.8 | ) | N.M. | ||||||||||||||
Net income attributable to UGI Corporation |
$ | 258.5 | 100.0 | % | $ | 215.5 | 100.0 | % | $ | 43.0 | 20.0 | % | ||||||||||||
N.M. — Variance is not meaningful. |
||
Highlights — Fiscal 2009 versus Fiscal 2008
| • | Higher unit margins at AmeriGas Propane and Antargaz in Fiscal 2009 reflect significant
declines in LPG commodity prices entering our critical heating season. |
| • | Most of our business units experienced Fiscal 2009 heating-season temperatures that
were to varying degrees colder than in Fiscal 2008. |
| • | Fiscal 2009 Gas Utility results include the benefit of the CPG Acquisition on October
1, 2008. |
| • | AmeriGas Partners’ sale of its California LPG storage terminal generated net income of
$10.4 million in Fiscal 2009. |
| • | The global economic recession reduced overall business activity in all of our business
units. |
| • | International Propane Fiscal 2009 results reflect a $10.0 million charge for the
Antargaz Competition Authority Matter. |
| • | Midstream & Marketing’s Fiscal 2009 results were adversely impacted by lower income
from electricity generation. |
| • | Electric Utility Fiscal 2009 results were lower reflecting the effects of higher cost
of sales and lower demand as a result of the recession. |
| Increase | ||||||||||||||||
| AmeriGas Propane | 2009 | 2008 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 2,260.1 | $ | 2,815.2 | $ | (555.1 | ) | (19.7 | )% | |||||||
Total margin (a) |
$ | 943.6 | $ | 906.9 | $ | 36.7 | 4.0 | % | ||||||||
Partnership EBITDA (b) |
$ | 381.4 | $ | 313.0 | $ | 68.4 | 21.9 | % | ||||||||
Operating income |
$ | 300.5 | $ | 235.0 | $ | 65.5 | 27.9 | % | ||||||||
Retail gallons sold (millions) |
928.2 | 993.2 | (65.0 | ) | (6.5 | )% | ||||||||||
Degree days — % (warmer) than normal (c) |
(3.1 | )% | (3.0 | )% | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
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| (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) 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
segment (see Note 21 to Consolidated Financial Statements). Partnership EBITDA and operating
income in Fiscal 2009 includes a pre-tax gain of $39.9 million associated with the sale of the
Partnership’s California LPG storage facility. |
|
| (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. Fiscal 2009 data has been
adjusted to correct a NOAA error. |
Based upon heating degree-day data, average temperatures in our service territories during
Fiscal 2009 were 3.1% warmer than normal compared with temperatures in the prior year that were
3.0% warmer than normal. Fiscal 2009 retail gallons sold were 6.5% lower than Fiscal 2008
reflecting, among other things, the adverse effects of the significant deterioration in general
economic activity which occurred over the last year and continued customer conservation. During
Fiscal 2009, average wholesale propane commodity prices at Mont Belvieu, Texas, one of the major
supply points in the U.S., were more than 50% lower than such prices in Fiscal 2008. The decrease
in the average wholesale commodity prices in Fiscal 2009 reflects the effects of a precipitous
decline in commodity propane prices principally during the first quarter of Fiscal 2009 following a
substantial increase in prices during most of the second half of Fiscal 2008. Although wholesale
propane prices in Fiscal 2009 rebounded modestly from prices experienced earlier in the year, at
September 30, 2009 such prices remained approximately 35% lower than at September 30, 2008.
Retail propane revenues declined $463.2 million in Fiscal 2009 reflecting a decrease as a
result of the lower retail volumes sold ($303.6 million) and a decrease due to lower average
selling prices ($159.6 million). Wholesale propane revenues declined $69.5 million reflecting a
decrease from lower wholesale selling prices ($83.7 million) partially offset by an increase from
higher wholesale volumes sold ($14.2 million). Total cost of sales decreased $591.8 million to
$1,316.5 million principally reflecting the effects of the previously mentioned lower propane
commodity prices.
Total margin was $36.7 million greater in Fiscal 2009 reflecting the beneficial impact of
higher than normal retail unit margins resulting from the previously mentioned rapid decline in
propane commodity costs that occurred primarily as we entered the critical winter heating season in
the first quarter of Fiscal 2009.
The $68.4 million increase in Fiscal 2009 Partnership EBITDA reflects the effects of a pre-tax
gain from the November 2008 sale of the Partnership’s California LPG storage facility ($39.9
million) and the previously mentioned increase in total margin ($36.7 million). These increases
were partially offset by slightly higher operating and administrative expenses ($4.7 million) and
slightly lower other income ($2.8 million). The slightly higher operating and administrative
expenses reflects, in large part, an increase in compensation and benefit expenses ($9.1 million)
and higher costs associated with facility maintenance projects ($6.4 million) offset principally by
lower vehicle fuel expenses ($14.2 million) due to lower propane, diesel and gasoline prices.
Operating income increased $65.5 million in Fiscal 2009 reflecting the previously mentioned
increase in EBITDA ($68.4 million) partially offset by slightly higher depreciation and
amortization expense ($3.4 million) reflecting acquisitions and plant and equipment expenditures
made since the prior year.
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| Increase | ||||||||||||||||
| International Propane | 2009 (a) | 2008 | (Decrease) | |||||||||||||
| (Millions of euros) (a) | ||||||||||||||||
Revenues |
€ | 712.7 | € | 749.8 | € | (37.1 | ) | (4.9 | )% | |||||||
Total margin (b) |
€ | 392.7 | € | 314.9 | € | 77.8 | 24.7 | % | ||||||||
Operating income |
€ | 116.3 | € | 70.4 | € | 45.9 | 65.2 | % | ||||||||
Income before income taxes |
€ | 95.3 | € | 48.8 | € | 46.5 | 95.3 | % | ||||||||
(Millions of dollars) (a) |
||||||||||||||||
Revenues |
$ | 955.3 | $ | 1,124.8 | $ | (169.5 | ) | (15.1 | )% | |||||||
Total margin (b) |
$ | 525.8 | $ | 472.9 | $ | 52.9 | 11.2 | % | ||||||||
Operating income |
$ | 151.4 | $ | 106.8 | $ | 44.6 | 41.8 | % | ||||||||
Income before income taxes |
$ | 122.0 | $ | 73.0 | $ | 49.0 | 67.1 | % | ||||||||
Antargaz retail gallons sold |
289.3 | 292.6 | (3.3 | ) | (1.1 | )% | ||||||||||
Degree days — % (warmer) than normal (c) |
(2.9 | )% | (4.1 | )% | — | — | ||||||||||
| (a) | Euro amounts represent amounts for Antargaz and Flaga. U.S. dollar amounts include Antargaz and
Flaga as well as our operations in China and certain non-operating entities associated with our
International Propane segment. |
|
| (b) | Total margin represents total revenues less total cost of sales. |
|
| (c) | Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30
locations in our French service territory. |
Based upon heating degree day data, temperatures in Antargaz’ service territory were
approximately 2.9% warmer than normal during Fiscal 2009 compared with temperatures that were
approximately 4.1% warmer than normal during Fiscal 2008. Temperatures in Flaga’s service territory
were warmer than normal and warmer than Fiscal 2008. Wholesale propane product costs declined
significantly during late Fiscal 2008 and the first quarter of Fiscal 2009 as we entered the
critical winter heating season. As a result, the average wholesale commodity price for propane in
northwest Europe in Fiscal 2009 was approximately 41% lower than such price in Fiscal 2008. Similar
declines in average wholesale butane prices were experienced in Fiscal 2009. Antargaz’ Fiscal 2009
retail LPG volumes were slightly lower than in Fiscal 2008 reflecting the colder Fiscal 2009
weather offset by the effects of the deterioration of general economic conditions in France,
customer conservation and competition from alternate energy sources.
During Fiscal 2009, the average currency translation rate was $1.35 per euro compared to a
rate of $1.51 per euro during Fiscal 2008. Although the stronger dollar resulted in lower
translated International Propane operating results, the effects of the stronger dollar on reported
International Propane net income attributable to UGI Corporation were substantially offset by gains
on forward currency contracts used to hedge purchases of dollar-denominated LPG.
International Propane euro-based revenues decreased €37.1 million or 4.9% in Fiscal 2009
reflecting a decline in revenues from Antargaz (€82.2 million), principally lower retail propane
revenues (€61.9 million) from lower average selling prices, and lower Antargaz wholesale revenues
(€20.4 million). Partially offsetting the decline in revenues from Antargaz was an increase in
Flaga revenues (€45.1 million) resulting from the consolidation of ZLH beginning in January 2009.
The lower average selling prices reflect the previously mentioned year-over-year decrease in
wholesale LPG product costs. In U.S. dollars, revenues declined $169.5 million or 15.1% reflecting
the previously mentioned total lower euro-based revenues and the effects of the stronger U.S.
dollar. International Propane’s total cost of sales decreased to €320.0 million in Fiscal 2009 from
€434.9 million in Fiscal 2008, a 26.4% decline, principally reflecting the lower per-unit LPG
commodity costs. On a U.S. dollar basis, cost of sales decreased $222.4 million or 34.1%.
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Table of Contents
International Propane euro-based total margin increased €77.8 million or 24.7% in Fiscal 2009
largely the result of higher total margin at Antargaz (€57.9 million) reflecting the beneficial
impact of higher than normal retail unit margins resulting from the rapid and sharp decline in LPG
commodity costs that occurred as Antargaz entered the winter heating season in the first quarter of
Fiscal 2009 and, to lesser extent, incremental total margin at Flaga from the consolidation of ZLH
beginning in January 2009 ($25.5 million). Also affecting the year-over-year comparison was the
fact that Antargaz was adversely affected by lower unit margins in Fiscal 2008 as a result of the
rapid increase in LPG product costs which occurred in Fiscal 2008. In U.S. dollars, total margin
increased $52.9 million or 11.2% reflecting the effects of the stronger dollar on translated euro
base-currency revenues and cost of sales.
International Propane euro-based operating income increased €45.9 million or 65.2% in Fiscal
2009 principally reflecting the previously mentioned increase in total margin (€77.8 million)
reduced by a charge related to a French Competition Authority Matter (€7.1 million) and an increase
in operating and administrative costs (€21.4 million). The higher operating and administrative
costs principally reflect higher operating and administrative costs at Flaga (€14.4 million)
resulting from the consolidation of the operations of ZLH and, to lesser extent, higher operating
expenses at Antargaz (€7.0 million). On a U.S. dollar basis, operating income increased $44.6
million or 41.8% principally reflecting the previously mentioned increase in U.S.
dollar-denominated total margin ($52.9 million) partially offset by the charge related to the
Antargaz Competition Authority Matter ($10.0 million). Euro-based income before income taxes was
€46.5 million (95.3%) greater than in the prior year principally reflecting the higher operating
income. In U.S. dollars, income before income taxes increased $49.0 million (67.1%) principally
reflecting the benefit of the higher dollar-denominated operating income. Loss from International
Propane equity investees was higher in Fiscal 2009 due to expenditures associated with the
anticipated closure of an LPG storage facility.
| Gas Utility | 2009 | 2008 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 1,241.0 | $ | 1,138.3 | $ | 102.7 | 9.0 | % | ||||||||
Total margin (a) |
$ | 387.8 | $ | 307.2 | $ | 80.6 | 26.2 | % | ||||||||
Operating income |
$ | 153.5 | $ | 137.6 | $ | 15.9 | 11.6 | % | ||||||||
Income before income taxes |
$ | 111.3 | $ | 100.5 | $ | 10.8 | 10.7 | % | ||||||||
System throughput — billions of cubic feet (“bcf”) |
149.7 | 133.7 | 16.0 | 12.0 | % | |||||||||||
Degree days — % colder (warmer) than normal (b) |
4.1 | % | (2.7 | )% | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
|
| (b) | Deviation from average heating degree days for the 15-year period 1990–2004 based upon
weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”)
for airports located within Gas Utility’s service territory. |
Temperatures in the Gas Utility service territory based upon heating degree days were 4.1%
colder than normal in Fiscal 2009 compared with temperatures that were 2.7% warmer than normal in
Fiscal 2008. Total distribution system throughput increased 16.0 bcf in Fiscal 2009 principally
reflecting the effects of the October 1, 2008 CPG Acquisition (22.2 bcf) and increases in
core-market volumes resulting from the colder Fiscal 2009 weather and year-over-year customer
growth. These increases in system throughput were partially offset by the effects on volumes sold
and transported due to lower demand from commercial and industrial customers as a result of the
deterioration in general economic activity and customer conservation.
Gas Utility revenues increased $102.7 million in Fiscal 2009 principally reflecting
incremental revenues from CPG Gas ($187.4 million) somewhat offset by lower revenues from
low-margin off-system sales ($90.3 million). Gas Utility’s cost of gas was $853.2 million in Fiscal
2009 compared with $831.1 million in Fiscal 2008 principally reflecting incremental cost of sales
associated with CPG Gas ($117.0 million) partially offset principally by the cost of sales effect
of the lower off-system revenues ($89.1 million).
Gas Utility total margin increased $80.6 million in Fiscal 2009 principally reflecting
incremental margin from CPG Gas ($70.4 million) and higher total core-market margin from UGI Gas
and PNG Gas ($11.3 million) resulting principally from the higher core-market volumes sold.
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Table of Contents
The increase in Gas Utility operating income during Fiscal 2009 principally reflects the
previously mentioned greater total margin ($80.6 million) partially offset by higher operating and
administrative and depreciation expenses ($59.3 million), principally incremental expenses
associated with CPG Gas ($47.2 million), higher costs associated with environmental matters ($4.1
million) and, to a lesser extent, higher pension and distribution system maintenance expenses.
Income before income taxes also increased reflecting the previously mentioned higher operating
income partially offset by higher interest expense associated with $108 million Senior Notes issued
to finance a portion of the CPG Acquisition ($7.2 million).
| Electric Utility | 2009 | 2008 | Decrease | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 138.5 | $ | 139.2 | $ | (0.7 | ) | (0.5 | )% | |||||||
Total margin (a) |
$ | 39.3 | $ | 47.0 | $ | (7.7 | ) | (16.4 | )% | |||||||
Operating income |
$ | 15.4 | $ | 24.4 | $ | (9.0 | ) | (36.9 | )% | |||||||
Income before income taxes |
$ | 13.7 | $ | 22.4 | $ | (8.7 | ) | (38.8 | )% | |||||||
Distribution sales — millions of kilowatt hours (“gwh”) |
965.7 | 1,004.4 | (38.7 | ) | (3.9 | )% | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes,
i.e. Electric Utility gross receipts taxes, of $7.6 million and $7.9 million during Fiscal
2009 and Fiscal 2008, 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 kilowatt-hour sales in Fiscal 2009 were lower than in Fiscal 2008.
Temperatures based upon heating degree days in Electric Utility’s service territory were
approximately 5.0% colder than last year resulting in greater sales to Electric Utility’s
residential heating customers. These greater sales were more than offset, however, by lower sales
to commercial and industrial customers as a result of the deterioration in general economic
activity and lower weather-related air-conditioning sales during the summer of Fiscal 2009.
Notwithstanding the lower sales, Electric Utility revenues were about equal with last year as a
result of higher POLR rates and greater revenues from spot market sales of electricity. Electric
Utility cost of sales increased to $91.6 million in Fiscal 2009 from $84.3 million in Fiscal 2008
principally reflecting greater purchased power costs.
Electric Utility total margin decreased $7.7 million during Fiscal 2009 principally reflecting
the higher cost of sales and, to a much lesser extent, the effects of the lower sales volumes.
Electric Utility operating income and income before income taxes in Fiscal 2009 were $9.0
million and $8.7 million lower than in Fiscal 2008, respectively, principally reflecting the
previously mentioned lower total margin ($7.7 million) and higher operating and administrative
costs ($0.9 million).
| Increase | ||||||||||||||||
| Midstream & Marketing | 2009 | 2008 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
Revenues |
$ | 1,224.7 | $ | 1,619.5 | $ | (394.8 | ) | (24.4 | )% | |||||||
Total margin (a) |
$ | 126.2 | $ | 124.1 | $ | 2.1 | 1.7 | % | ||||||||
Operating income |
$ | 64.8 | $ | 77.3 | $ | (12.5 | ) | (16.2 | )% | |||||||
Income before income taxes |
$ | 64.8 | $ | 77.3 | $ | (12.5 | ) | (16.2 | )% | |||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Midstream & Marketing total revenues declined $394.8 million or 24.4% in Fiscal 2009
principally reflecting the effects on revenues of lower unit prices for natural gas, electricity
and propane due to year-over-year declines in such energy commodity prices.
Total margin from Midstream & Marketing increased $2.1 million in Fiscal 2009 reflecting
greater total margin principally from peaking supply services ($4.4 million) and
retail electricity sales ($2.8 million) partially offset by lower electric generation total margin
($4.6 million). The decrease in electric generation total margin reflects lower spot-market prices
for electricity and, to a much lesser extent, lower volumes generated due in large part to
electricity generation facility outages. The decreases in Midstream & Marketing operating income
and income before income taxes in Fiscal 2009 largely reflects the previously mentioned increase in
total margin ($2.1 million) more than offset by higher electric generation operating and
maintenance costs ($5.9 million) including charges related to obligations associated with its
ongoing Hunlock Station repowering project and an increase in asset management costs ($3.4
million). The decrease in operating income and income before income taxes also reflects greater
costs associated with Energy Service’s receivables
securitization facility ($1.4 million) as a result of higher
amounts needed to fund futures brokerage account margin calls and greater facility fees subsequent
to the renewal of the securitization facility in April 2009.
40
Table of Contents
Interest Expense and Income Taxes. Consolidated interest expense decreased slightly to $141.1
million in Fiscal 2009 from $142.5 million in Fiscal 2008 principally due to a decline in
International Propane interest expense ($3.1 million), principally attributable to lower effective
interest rates and the stronger U.S. dollar, a decline in interest on UGI Utilities revolving
credit agreement borrowings ($2.4 million) and lower interest expense on AmeriGas Propane long-term
debt ($2.3 million). These decreases were largely offset by incremental interest expense on CPG
Acquisition debt ($7.2 million). Our effective income tax rate was slightly lower in Fiscal 2009
principally reflecting the effects of a higher percentage of pretax income from noncontrolling
interests, principally in AmeriGas Partners, not subject to income taxes.
Financial Condition and Liquidity
We depend on both internal and external sources of liquidity to provide funds for working
capital and to fund capital requirements. Our short-term cash requirements not met by cash from
operations are generally satisfied with borrowings under credit facilities and, in the case of
Midstream & Marketing, also from a receivables purchase facility. Long-term cash needs are
generally met through issuance of long-term debt or equity securities.
Our cash and cash equivalents, excluding cash included in commodity futures brokerage accounts
that is restricted from withdrawal, totaled $260.7 million at September 30, 2010 compared with
$280.1 million at September 30, 2009. Excluding cash and cash equivalents that reside at UGI’s
operating subsidiaries, at September 30, 2010 and 2009 UGI had $111.6 million and $102.7 million,
respectively, of cash and cash equivalents. Such cash is available to pay dividends on UGI Common
Stock and for investment purposes.
The primary sources of UGI’s cash and cash equivalents are the dividends and other cash
payments made to UGI or its corporate subsidiaries by its principal business units.
AmeriGas Propane’s ability to pay dividends to UGI is dependent upon distributions it receives
from AmeriGas Partners. At September 30, 2010, our 44% effective ownership interest in the
Partnership consisted of approximately 24.7 million Common Units and 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 Fourth Amended and Restated Agreement of Limited
Partnership of AmeriGas Partners, the “Partnership Agreement”) relating to such fiscal quarter.
AmeriGas Propane, as general partner of AmeriGas Partners, L.P., is entitled to receive incentive
distributions when AmeriGas Partners, L.P.’s quarterly distribution exceeds $0.605 per limited
partner unit (see Note 14 to Consolidated Financial Statements).
During Fiscal 2010, Fiscal 2009 and Fiscal 2008, our principal business units paid cash
dividends and made other cash payments to UGI and its subsidiaries as follows:
| Year Ended September 30, | 2010 | 2009 | 2008 | |||||||||
| (Millions of dollars) | ||||||||||||
AmeriGas Propane |
$ | 44.4 | $ | 39.3 | $ | 38.6 | ||||||
UGI Utilities |
74.0 | 61.2 | 68.8 | |||||||||
International Propane |
38.8 | 39.0 | 45.8 | |||||||||
Midstream & Marketing |
32.5 | — | 18.4 | |||||||||
Total |
$ | 189.7 | $ | 139.5 | $ | 171.6 | ||||||
Dividends in Fiscal 2010 from Midstream & Marketing resulted from the sale of Atlantic Energy
LLC. Dividends from AmeriGas Propane in Fiscal 2009 include the benefit of a one-time $0.17
increase in the August 2009 quarterly distribution resulting from the Partnership’s Fiscal 2009
sale of its California LPG storage facility (see below and Note 4 to Consolidated Financial
Statements). In Fiscal 2010 and 2009, Midstream & Marketing received capital contributions from UGI
totaling $51.0 million and $46.8 million, respectively, to fund major LNG storage and electric
generation capital projects.
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On April 27, 2010, UGI’s Board of Directors approved a 25% increase in the quarterly dividend
rate on UGI Common Stock to $0.25 per common share or $1.00 per common share on an annual basis.
The new quarterly dividend rate was effective with the dividend payable on July 1, 2010 to
shareholders of record on June 15, 2010. The higher than normal percentage dividend increase in
Fiscal 2010 reflects our confidence in UGI’s future prospects and strong cash flows. We expect that
the increase in the UGI dividend rate in Fiscal 2011 will be closer to UGI’s long-term goal of
increasing the dividend by approximately 4% a year.
On April 26, 2010, the General Partner’s Board of Directors approved a quarterly distribution
of $0.705 per Common Unit equal to an annual rate of $2.82 per Common Unit. This distribution
reflects an approximate 5% increase from the previous quarterly rate of $0.67 per Common Unit. The
new quarterly rate was effective with the distribution payable on May 18, 2010 to unitholders of
record on May 10, 2010. Our targeted annual distribution increase is approximately 5%.
Long-term Debt and Credit Facilities
The Company’s total debt outstanding at September 30, 2010 totaled $2,206.2 million (including
current maturities of long-term debt of $573.6 million and bank loan borrowings of $200.4 million)
compared to $2,296.2 million of total debt outstanding at September 30, 2009 (including current maturities of long-term
debt of $94.5 million and bank loan borrowings of
$163.1 million). The
significantly higher current maturities of long-term debt at September 30, 2010 primarily reflects
the scheduled maturity of Antargaz’ €380 million term loan ($518.1 million) in March 2011 and
Fiscal 2011 scheduled repayments under Flaga’s two term loans ($34.6 million). Total debt
outstanding at September 30, 2010 principally consists of $882.4 million of Partnership debt,
$653.6 million (€479.4 million) of International Propane debt, $657 million of UGI Utilities’ debt,
and $13.2 million of other debt. For a detailed description of the Company’s debt, see below and
Note 5 to Consolidated Financial Statements.
Due to the seasonal nature of the Company’s businesses, operating cash flows 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 historically has used its
Receivables Facility to satisfy its operating cash flow needs. Energy Services also has a
three-year $170 million credit facility, entered into in August 2010, which it can use for working
capital and general corporate purposes of it and its subsidiaries. There were no borrowings under
this facility during Fiscal 2010. During Fiscal 2010, Fiscal 2009 and Fiscal 2008, Antargaz
generally funded its operating cash flow needs without using its revolving credit facility.
AmeriGas Partners. AmeriGas Partners’ total debt at September 30, 2010 includes $779.7 million
of AmeriGas Partners’ Senior Notes, $11.7 million of other long-term debt and $91 million of
AmeriGas OLP bank loan borrowings.
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. In
order to meet its short-term cash needs, AmeriGas OLP has a $200 million unsecured credit agreement
(“Credit Agreement”) which expires on October 15, 2011. AmeriGas OLP also has a $75 million
unsecured revolving credit facility (“2009 Supplemental Credit Agreement”) which expires on June
30, 2011. AmeriGas OLP expects to renew these credit agreements prior to their expiration. AmeriGas
OLP’s Credit Agreement 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. The 2009
Supplemental Credit Agreement permits AmeriGas OLP to borrow up to $75 million for working capital
and general purposes.
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At September 30, 2010, there were $91 million of borrowings outstanding under the Credit
Agreement at an average interest rate of 1.31% and there were no amounts outstanding under the 2009
Supplemental Credit Agreement. There were no borrowings under AmeriGas OLP’s credit agreements at
September 30, 2009. Borrowings under AmeriGas OLP credit agreements are classified as bank loans on
the Consolidated Balance
Sheets. Issued and outstanding letters of credit under the Revolving Credit Facility, which
reduce the amount available for borrowings, totaled $35.7 million at September 30, 2010 and $37.0
million at September 30, 2009. The average daily and peak bank loan borrowings outstanding under
the credit agreements during Fiscal 2010 were $43.9 million and $135 million, respectively. The
average daily and peak bank loan borrowings outstanding under the credit agreements during Fiscal
2009 were $43.8 million and $184.5 million, respectively. The higher peak bank loan borrowings in
Fiscal 2009 resulted from amounts borrowed to fund counterparty cash collateral obligations
associated with derivative financial instruments used by the Partnership to manage propane price
risk associated with fixed sales price commitments to customers. These collateral obligations
resulted from the precipitous decline in propane commodity prices that occurred early in Fiscal
2009. At September 30, 2010, the Partnership’s available borrowing capacity under the credit
agreements was $148.3 million.
Based upon existing cash balances, cash expected to be generated from operations and
borrowings available under AmeriGas OLP’s credit agreements, the Partnership’s management believes
that the Partnership will be able to meet its anticipated contractual commitments and projected
cash needs during Fiscal 2011.
International Propane. International Propane’s total debt at September 30, 2010 includes $518.1
million (€380 million) outstanding under Antargaz’ Senior Facilities term loan and a combined $40.4
million (€29.6 million) outstanding under Flaga’s two term loans. Total International Propane debt
outstanding at September 30, 2010 also includes (1) $68.2 million (€50.0 million) outstanding under
Antargaz’ revolving credit facility; (2) combined borrowings of $24.2 million (€17.8 million)
outstanding under Flaga’s working capital facilities and (3) $2.7 million (€2.0 million) of other
long-term debt.
Antargaz. Antargaz has a Senior Facilities Agreement that expires on March 31, 2011. The
Senior Facilities Agreement consists of (1) a €380 million variable-rate term loan and (2) a €50
million revolving credit facility. The Senior Facilities Agreement also provides Antargaz a €50
million letter of credit guarantee agreement. Antargaz has executed interest rate swap agreements
to fix the underlying euribor rate for the duration of the term loan. The €380 million
variable-rate term loan matures on March 31, 2011. Antargaz intends to refinance this maturing
debt. Antargaz has entered into forward-starting interest rate swaps to hedge the underlying
euribor rate of interest relating to 4 1/2 years of quarterly interest payments on €300 million
notional amount of long-term debt commencing March 31, 2011 associated with the anticipated
refinancing. In order to minimize the interest margin it pays on Senior Facilities Agreement
borrowings, on September 23, 2010, Antargaz borrowed €50 million ($68.2 million), the total amount
available under its revolving credit facility, which amount remained outstanding at September 30,
2010. This borrowing was repaid by Antargaz on October 25, 2010.
Antargaz’ management believes that it will be able to meet its anticipated contractual
commitments and projected cash needs during Fiscal 2011 with cash generated from operations,
borrowings under its existing or new revolving credit facilities and guarantees under letter of
credit facilities.
Flaga. Flaga has two euro-based, amortizing variable-rate term loans. The principal
outstanding on the first term loan was €24.0 million ($32.7 million) at September 30, 2010. Flaga
has effectively fixed the euribor component of its interest rate on this term loan through
September 2011 at 3.91% by entering into an interest rate swap agreement. The effective interest
rate on this term loan at September 30, 2010 was 4.21%. The second term loan, executed in August
2009, had an outstanding principal balance of €5.6 million ($7.6 million) on September 30, 2010.
This term loan matures through June 2014. Flaga has effectively fixed the euribor component of its
interest rate on this term loan at 2.16% by entering into an interest rate swap agreement. The
effective interest rate on this term loan at September 30, 2010 was 5.03%.
Flaga has two working capital facilities totaling €24 million. Flaga has a multi-currency
working capital facility that provides for borrowings and issuances of guarantees totaling €16
million of which €9.8 million ($13.4 million) was outstanding at September 30, 2010 at an average
interest rate of 3.64%. Flaga also has an €8 million euro-denominated working capital facility of
which €7.9 million ($10.8 million) was outstanding at September 30, 2010 at an average interest
rate of 2.01%. Issued and outstanding guarantees, which reduce available borrowings under the
working capital facilities, totaled €5.4 million ($7.4 million) at September 30, 2010. Amounts
outstanding under the working capital facilities are classified as bank loans. During Fiscal 2010,
average and peak bank loan
borrowings totaled €12.7 million and €17.8 million, respectively. During Fiscal 2009, average
and peak bank loan borrowings totaled €11.5 million and €18.6 million, respectively. For a more
detailed discussion of Flaga’s debt, see Note 5 to Consolidated Financial Statements. In order to
provide for additional borrowing capacity, in November 2010, Flaga entered into an additional €8
million multi-currency working capital facility and an additional €4 million euro-denominated
working capital facility both of which expire in June 2011. Flaga expects to combine and extend
these new facilities along with the other working capital facilities described above prior to their
expiration in June 2011.
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Based upon cash generated from operations, borrowings under its working capital facilities and
capital contributions from UGI, Flaga’s management believes it will be able to meet its anticipated
contractual commitments and projected cash needs during Fiscal 2011.
UGI Utilities. UGI Utilities’ total debt at September 30, 2010 includes long-term debt comprising
$383 million of Senior Notes and $257 million of Medium-Term Notes. Total debt outstanding at
September 30, 2010 also includes $17 million outstanding under UGI Utilities’ Revolving Credit
Agreement.
UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement
which expires in August 2011. UGI Utilities expects to renew this facility before its expiration.
At September 30, 2010 and 2009, there were $17 million and $154 million of borrowings outstanding
under the Revolving Credit Agreement having average interest rates of 3.25% and 0.59%,
respectively. The higher average interest rate at September 30, 2010 is the result of a prime rate
borrowing compared to LIBOR borrowings at September 30, 2009. Borrowings under the Revolving Credit
Agreement are classified as bank loans on the Consolidated Balance Sheets. During Fiscal 2010 and
Fiscal 2009, average daily bank loan borrowings were $69.9 million and $180.0 million,
respectively, and peak bank loan borrowings totaled $203 million and $312 million, respectively.
Peak bank loan borrowings typically occur during the heating season months of December and January.
During Fiscal 2009, average daily and peak bank loan borrowings were higher than during Fiscal 2010
due in large part to higher margin deposits associated with natural gas futures accounts as a
result of declines in wholesale natural gas prices and higher Fiscal 2009 borrowings needed to fund
working capital.
Based upon cash expected to be generated from Gas Utility and Electric Utility operations and
borrowings available under the Revolving Credit Agreement, UGI Utilities’ management believes that
it will be able to meet its anticipated contractual and projected cash commitments during Fiscal
2011.
Midstream & Marketing. In August 2010, Energy Services entered into an unsecured credit agreement
(“Energy Services Credit Agreement”) with a group of
lenders providing for borrowings of up to $170 million
(including a $50 million sublimit for letters of credit) which expires in August 2013. The Energy
Services Credit Agreement can be used for general corporate purposes of Energy Services and its
subsidiaries and to fund dividend payments provided that, after giving effect to such dividend
payments, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy
Services Credit Agreement, does not exceed 2.00 to 1.00. There were no borrowings under this
facility during Fiscal 2010.
Energy Services also has a $200 million receivables purchase facility (“Receivables Facility”)
with an issuer of receivables-backed commercial paper. The Receivables Facility expires in April
2011, although the Receivables Facility may terminate prior to such date due to the termination of
commitments of the Receivables Facility’s back-up purchasers. Energy Services uses the Receivables
Facility to fund working capital, margin calls under commodity futures contracts and capital
expenditures. Energy Services intends to extend its Receivables Facility prior to its scheduled
expiration in April 2011.
Under the Receivables Facility, Energy Services 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 some or all of 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 Energy Services
and its affiliates, including UGI. Through September 30, 2010, this two-step transaction was
accounted for as a sale of receivables following GAAP for accounting for transfers and servicing of
financial assets and extinguishments of liabilities. At September 30, 2010, the outstanding balance
of ESFC trade receivables was $44.0
million which is net of $12.1 million that was sold to the commercial paper conduit and
removed from the balance sheet. At September 30, 2009, the outstanding balance of ESFC trade
receivables was $38.2 million which is net of $31.3 million that was sold to the commercial paper
conduit and removed from the balance sheet. During Fiscal 2010 and Fiscal 2009, peak sales of
receivables were $45.7 million and $139.7 million, respectively.
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Effective October 1, 2010, the Company will adopt a new accounting standard that will change
the accounting for the Receivables Facility. Beginning October 1, 2010, trade receivables
transferred to the commercial paper conduit will remain on the Company’s balance sheet and the
Company will reflect a liability equal to the amount advanced by the commercial paper conduit.
Additionally, the Company will record interest expense on amounts owed to the commercial paper
conduit. For further information on the effects of the accounting change, see Note 3 to
Consolidated Financial Statements.
Based upon cash expected to be generated from operations, borrowings available under the
Energy Services Credit Agreement and Receivables Facility, and capital contributions from UGI,
management believes that Energy Services will be able to meet its anticipated contractual and
projected cash needs during Fiscal 2011.
Cash Flows
Operating Activities. Year-to-year variations in cash flow from operations can be significantly
affected by changes in operating working capital especially during periods of volatile energy
commodity prices. During Fiscal 2010, commodity prices for LPG rose compared with LPG commodity
price declines experienced in Fiscal 2009. During Fiscal 2009, commodity prices of LPG and natural
gas decreased significantly compared with significant price increases experienced during most of
the second half of Fiscal 2008. The increase in Fiscal 2010 LPG prices resulted in increased cash
invested in accounts receivable and LPG inventories. The decline in Fiscal 2009 commodity prices
compared with Fiscal 2008 resulted in reduced investments in accounts receivable and LPG
inventories which had the effect of significantly increasing cash flow from operating activities in
Fiscal 2009 compared to Fiscal 2008.
Cash flow provided by operating activities was $598.8 million in Fiscal 2010, $665.0 million
in Fiscal 2009 and $464.4 million in Fiscal 2008. Cash flow from operating activities before
changes in operating working capital was $663.8 million in Fiscal 2010, $611.7 million in Fiscal
2009 and $525.3 million in Fiscal 2008. The increase in the Fiscal 2010 amount reflects in large
part higher noncash charges for deferred income taxes ($35.8 million) due primarily to a change in
tax accounting for distribution system repair and maintenance costs at UGI Utilities (see below and
Note 6 to Consolidate Financial Statements). The increase in Fiscal 2009 cash flow from operating
activities before changes in working capital compared with Fiscal 2008 reflects the improved
operating results. Changes in operating working capital (used) provided operating cash flow of
$(65.0) million in Fiscal 2010, $53.3 million in Fiscal 2009 and $(60.9) million in Fiscal 2008.
Cash flow from changes in operating working capital principally reflects the impacts of changes in
LPG and natural gas prices on cash receipts from customers as reflected in changes in accounts
receivable and accrued utility revenues; the timing of purchases and changes in LPG and natural gas
prices on our investments in inventories; the timing of natural gas cost recoveries through Gas
Utility’s PGC recovery mechanism; and the effects of the timing of payments and changes in purchase
price per gallon of LPG and natural gas on accounts payable. The lower Fiscal 2010 cash provided by
changes in working capital compared to Fiscal 2009 reflects in large part the effects on operating
working capital of an increase in LPG commodity prices in Fiscal 2010 compared to the effects on
operating working capital of a significant decrease in LPG commodity prices in Fiscal 2009. The
greater Fiscal 2009 cash provided by changes in operating working capital compared with cash
provided by such changes in Fiscal 2008 principally reflects the effects on net cash receipts from
customers and cash expenditures for purchases of inventories resulting from significantly lower
Fiscal 2009 LPG commodity prices compared with Fiscal 2008.
Investing Activities. Investing activity cash flow is principally affected by expenditures for
property, plant and equipment; cash paid for acquisitions of businesses; changes in restricted cash
balances and proceeds from sales of assets. Net cash flow used in investing activities was $399.3
million in Fiscal 2010, $519.9 million in Fiscal 2009 and $289.5 million in Fiscal 2008. Fiscal
2010 expenditures for property, plant and equipment were greater than in Fiscal 2009 primarily due
to higher Midstream & Marketing cash capital expenditures (an increase of $45.1 million)
principally associated with natural gas storage and electric generation projects. Acquisitions in
Fiscal 2010 include
$48.7 million of expenditures associated with our International Propane businesses and $34.3
million of acquisition capital expenditures at the Partnership. The primary reasons for the
increase in cash used by investing activities in Fiscal 2009 compared to Fiscal 2008 were the
acquisition of CPG ($292.6 million) and greater cash expenditures for property, plant and equipment
($69.6 million). Fiscal 2010, Fiscal 2009 and Fiscal 2008 investing activity cash flows also
reflect cash (used for) provided by changes in restricted cash in natural gas futures brokerage
accounts of $(27.8) million, $63.3 million and $(57.5) million, respectively. Changes in restricted
cash in futures and options brokerage accounts are the result of the timing of settlement of
natural gas futures contracts and changes in natural gas prices. During Fiscal 2010 and Fiscal
2009, we received $66.6 million and $42.4 million in cash proceeds from the sale of Atlantic Energy
and the sale of the Partnership’s California LPG storage facility, respectively.
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Financing Activities. Cash flow used by financing activities was $213.6 million, $114.6 million and
$180.1 million in Fiscal 2010, Fiscal 2009 and Fiscal 2008, 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
issuances of UGI and AmeriGas Partners equity instruments.
During Fiscal 2010, AmeriGas OLP repaid $80 million of maturing First Mortgage Notes using
borrowings under its revolving credit facilities and cash from operations and Flaga made scheduled
payments on its term loans of €7.4 million ($10.4 million) using cash from operations, UGI cash
contributions and borrowings under working capital facilities. Changes in bank loans during Fiscal
2010 principally reflect €50 million ($67.7 million) borrowed by Antargaz in September 2010 (repaid
in October 2010) in order to minimize the interest margin it pays on its Senior Facilities
Agreement; Partnership revolving credit facility borrowings of $91 million; and higher revolving
credit facility borrowings at Flaga ($16.2 million). These increases were largely offset by a $137
million decrease in bank loan borrowings at UGI Utilities due primarily to cash flow generated from
changes in operating working capital.
Capital Expenditures
In the following table, we present capital expenditures (which exclude acquisitions but
include capital leases) by our business segments for Fiscal 2010, Fiscal 2009 and Fiscal 2008. We
also provide amounts we expect to spend in Fiscal 2011. We expect to finance Fiscal 2011 capital
expenditures principally from cash generated by operations, borrowings under credit facilities and
cash on hand.
| Year Ended September 30, | 2011 | 2010 | 2009 | 2008 | ||||||||||||
| (Millions of dollars) | (estimate) | |||||||||||||||
AmeriGas Propane |
$ | 79.9 | $ | 83.2 | $ | 78.7 | $ | 62.8 | ||||||||
International Propane |
60.5 | 59.0 | 76.3 | 75.0 | ||||||||||||
Gas Utility |
76.7 | 73.5 | 73.8 | 58.3 | ||||||||||||
Electric Utility |
9.5 | 8.1 | 5.3 | 6.0 | ||||||||||||
Midstream & Marketing |
177.8 | 116.4 | 66.2 | 30.7 | ||||||||||||
Other |
1.2 | 12.7 | 1.4 | 1.4 | ||||||||||||
Total |
$ | 405.6 | $ | 352.9 | $ | 301.7 | $ | 234.2 | ||||||||
AmeriGas Propane capital expenditures in Fiscal 2010 and Fiscal 2009 include expenditures
associated with a system software replacement. The decline in International Propane capital
expenditures in Fiscal 2010 is principally due to lower expenditures for cylinders. The increases
in Midstream & Marketing’s capital expenditures in Fiscal 2010 and Fiscal 2009 principally reflect
capital expenditures related to natural gas storage and electric generation projects. These
Midstream & Marketing capital expenditures were financed in large part by capital contributions
from UGI and cash from operations. The higher “other” capital expenditures in Fiscal 2010
principally reflects capital improvements at UGI Corporation’s headquarters’ facility following a
fire. Midstream & Marketing’s estimated expenditures in Fiscal 2011, principally relating to the
completion of its Hunlock Station repowering project, the continued expansion of its LNG storage
assets and Marcellus Shale projects, are expected to be financed principally from capital
contributions from UGI and credit agreement borrowings.
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In August 2010, the Company announced that it plans to invest approximately $300 million over
the next two years on infrastructure projects to support the development of natural gas in the
Marcellus Shale region. This anticipated investment includes Midstream & Marketing’s potential
participation in the Pennsylvania natural gas pipeline project being jointly developed with
NiSource Gas Transmission and Storage Company (“NiSource”)
described below under “Contractual Cash Obligations and Commitments.” In addition the Company
plans to pursue the enhancement of its existing underground storage fields located in north-central
Pennsylvania, as well as to pursue additional projects to acquire and construct gas gathering
facilities that would make locally produced gas available to Pennsylvania and interstate markets.
The timing and extent of the Company’s investment in Marcellus infrastructure will depend on a
number of factors including the timing of development of Marcellus gas production, market
competition, any required regulatory approvals and construction schedules. Such investment is
expected to be financed with a combination of debt and UGI equity.
Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond Fiscal 2010. 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,
capital expenditures and derivative financial instruments. The following table presents contractual
cash obligations under agreements existing as of September 30, 2010:
| Payments Due by Period | ||||||||||||||||||||
| Fiscal | Fiscal | Fiscal | ||||||||||||||||||
| (Millions of dollars) | Total | 2011 | 2012 - 2013 | 2014 - 2015 | Thereafter | |||||||||||||||
Long-term debt (a) |
$ | 2,005.8 | $ | 573.6 | $ | 183.9 | $ | 440.6 | $ | 807.7 | ||||||||||
Interest on long-term fixed rate debt (b) |
678.3 | 107.2 | 183.6 | 163.4 | 224.1 | |||||||||||||||
Operating leases |
197.1 | 57.4 | 78.9 | 41.1 | 19.7 | |||||||||||||||
AmeriGas Propane supply contracts |
50.5 | 50.5 | — | — | — | |||||||||||||||
International Propane supply contracts |
5.4 | 5.4 | — | — | — | |||||||||||||||
Midstream & Marketing supply contracts |
391.6 | 277.7 | 113.9 | — | — | |||||||||||||||
Gas Utility and Electric Utility supply,
storage and transportation contracts |
598.4 | 225.2 | 190.2 | 92.8 | 90.2 | |||||||||||||||
Derivative financial instruments (c) |
72.6 | 50.2 | 20.0 | 2.4 | — | |||||||||||||||
Other purchase obligations (d) |
36.1 | 36.1 | — | — | — | |||||||||||||||
Total |
$ | 4,035.8 | $ | 1,383.3 | $ | 770.5 | $ | 740.3 | $ | 1,141.7 | ||||||||||
| (a) | Based upon stated maturity dates. |
|
| (b) | Based upon stated interest rates adjusted for the effects of interest rate swaps. |
|
| (c) | Represents the sum of amounts due from us if derivative financial instrument liabilities were
settled at the September 30, 2010 amounts reflected in the Consolidated Balance Sheet (but
excluding amounts associated with interest rate swaps). |
|
| (d) | Includes material capital expenditure obligations. |
Other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2010
principally comprise refundable tank and cylinder deposits (as further described in Note 2 to
Consolidated Financial Statements under the caption “Refundable Tank and Cylinder Deposits”);
litigation, property and casualty liabilities and obligations under environmental remediation
agreements (see Note 15 to Consolidated Financial Statements); pension and other postretirement
benefit liabilities recorded in accordance with accounting guidance relating to employee retirement
plans (see Note 7 to Consolidated Financial Statements); and liabilities associated with executive
compensation plans (see Note 13 to Consolidated Financial Statements). These liabilities are not
included in the table of Contractual Cash Obligations and Commitments because they are estimates of
future payments and not contractually fixed as to timing or amount. We believe we will be required
to make contributions to the UGI Utilities’ pension plans in Fiscal 2011 of approximately $20
million. Contributions to the pension plans in years beyond Fiscal 2011 will depend in large part
on future returns on pension plans assets. In addition, at September 30, 2010 we were committed to
invest over the next several years an additional $9.6 million in a limited partnership that focuses
on investments in the alternative energy sector.
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In August 2010, Energy Services entered into a Joint Marketing and Development Agreement with
NiSource to evaluate the feasibility of constructing a natural gas pipeline in the Marcellus Shale
gas production region of north-central Pennsylvania. The parties are currently working
cooperatively and sharing preliminary costs in developing a route, engineering design and cost
estimate for the pipeline and in marketing the project to potential customers.
Significant Dispositions and Acquisitions
On July 30, 2010, Energy Services sold all of its interest in its second-tier, wholly owned
subsidiary Atlantic Energy to DCP Midstream Partners, L.P. for $49.0 million cash plus an amount
for inventory and other working capital. Atlantic Energy owns and operates a 20 million gallon
marine import and transshipment facility located in the port of Chesapeake, Virginia. The Company
recorded a $36.5 million pre-tax gain on the sale which amount is
included in “Other income, net” in the Fiscal 2010 Consolidated Statement of Income. The gain
increased Fiscal 2010 net income attributable to UGI Corporation by $17.2 million or $0.16 per
diluted share.
On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL Gas
Utilities Corporation (now named UGI Central Penn Gas, Inc., “CPG”), the natural gas distribution
utility of PPL (the “CPG Acquisition”), for cash consideration of $303.0 million less a final
working capital adjustment of $9.7 million. Immediately after the closing of the CPG Acquisition,
CPG’s wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central Penn, LLC, “CPP”), its
retail propane distributor, sold its assets to AmeriGas OLP for cash consideration of $33.6 million
less a final working capital adjustment of $1.4 million (the “Penn Fuels Acquisition”). CPG
distributes natural gas to approximately 76,000 customers in eastern and central Pennsylvania, and
also distributes natural gas to several hundred customers in portions of one Maryland county. CPP
sold propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG
Acquisition with a combination of $120 million cash contributed by UGI on September 25, 2008,
proceeds from the issuance of $108 million principal amount of 6.375% Senior Notes due 2013 and
approximately $75.0 million of borrowings under UGI Utilities’ Revolving Credit Agreement. AmeriGas
OLP funded the acquisition of the assets of CPP with borrowings under the AmeriGas Credit
Agreement, and UGI Utilities used the $33.6 million of cash proceeds from the sale of the assets of
CPP to reduce its revolving credit agreement borrowings.
On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated above-ground LPG
storage facility located on leased property in California for net cash proceeds of $42.4 million.
The gain from the sale increased net income attributable to UGI Corporation by $10.4 million or
$0.10 per diluted share.
Antargaz Competition Authority Matter
On July 21, 2009, Antargaz received a Statement of Objections from France’s Autorité de la
concurrence (“Competition Authority”) with respect to the investigation of Antargaz by the General
Division of Competition, Consumption and Fraud Punishment (“DGCCRF”). A Statement of Objections
(“Statement”) is part of French competition proceedings and generally follows an investigation
under French competition laws. The Statement sets forth the Competition Authority’s findings; it is
not a judgment or final decision. The Statement alleges that Antargaz engaged in certain
anti-competitive practices in violation of French competition laws related
to the cylinder market during the period from 1999 through 2004. The alleged violations occurred
principally during periods prior to March 31, 2004, when UGI first obtained a controlling interest
in Antargaz. Based on an assessment of the information contained in the Statement, during the
quarter ended June 30, 2009 we recorded a provision of $10.0 million (€7.1 million) related to this
matter which amount is reflected in “Other income, net” on the Fiscal 2009 Consolidated Statement
of Income.
We filed our written response to the Statement of Objections with the Competition Authority on
October 21, 2009. The Competition Authority completed its review of Antargaz’ response and issued
its report on April 26, 2010. Antargaz filed its response to this report on June 28, 2010. A
hearing before the Competition Authority was held on September 21, 2010 and a decision is not
expected before the end of 2010. Based on our assessment of the information contained in the report
and the hearing, we believe that we have good defenses to the objections and that the reserve
established by management for this matter is adequate. However, the final resolution could result
in payment of an amount significantly different from the amount we have recorded (see Note 15 to
Consolidated Financial Statements).
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Pension Plans
As of September 30, 2010, we sponsor two defined benefit pension plans (“Pension Plans”) for
employees hired prior to January 1, 2009 of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other
domestic wholly owned subsidiaries. In addition, Antargaz employees are covered by certain defined
benefit pension and postretirement plans. The Antargaz plans’ assets and benefit obligations are
not material.
The fair value of Pension Plans’ assets totaled $287.9 million and $276.4 million at September
30, 2010 and 2009, respectively. At September 30, 2010 and 2009, the underfunded position of
Pension Plans, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension
Plans’ assets, was $177.1 million and $145.6 million, respectively.
We believe we are in compliance with regulations governing defined benefit pension plans,
including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations. We
anticipate that we will be required to make contributions to Pension Plans during Fiscal 2011 of
approximately $20 million. Pre-tax pension cost associated with Pension Plans in Fiscal 2010 was
$11.5 million. Pre-tax pension cost associated with Pension Plans in Fiscal 2011 is expected to be
approximately $14.9 million.
GAAP guidance associated with pension and other postretirement plans generally requires
recognition of an asset or liability in the statement of financial position reflecting the funded
status of pension and other postretirement benefit plans with current year changes recognized in
shareholders’ equity unless such amounts are subject to regulatory recovery. Based upon an August
2010 PUC order issued in response to UGI Utilities’ and PNG’s joint petition regarding the
regulatory treatment of the funded status of their combined pension plan, effective September 30,
2010, UGI Utilities recorded a regulatory asset of $142.4 million associated with the underfunded
position of the combined pension plan (see below and Note 8 to Consolidated Financial Statements).
Previously, the effects of such underfunded position were reflected in accumulated other
comprehensive income. Through September 30, 2010, we have recorded cumulative after-tax charges to
UGI Corporation’s stockholders’ equity of $12.8 million and recorded regulatory assets totaling
$159.2 million in order to reflect the funded status of our pension and other postretirement
benefit plans. For a more detailed discussion of the Pension Plans and other postretirement
benefit plans, see Note 7 to Consolidated Financial Statements.
Change in Tax Method of Accounting
The Company received Internal Revenue Service (“IRS”) consent to change its tax method of
accounting for capitalizing certain repair and maintenance costs associated with its Gas Utility
and Electric Utility assets beginning with the tax year ended September 30, 2009. The filing of the
Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax
benefits totaling approximately $30.2 million which was used to offset Fiscal 2010 federal and
state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 stand alone Pennsylvania
income tax return also produced a $43.4 million state net operating loss (“NOL”) carryforward.
Under current Pennsylvania state income tax law, the NOL stated above can be carried forward by UGI
Utilities for 20 years and used to reduce future Pennsylvania taxable income. Because the Company
believes that it is more likely than not that it will fully utilize this state NOL prior to its
expiration, no valuation allowance has been recorded. For more information on the change in tax
method of accounting, see Note 6 to Consolidated Financial Statements.
Related Party Transactions
During Fiscal 2010, Fiscal 2009 and Fiscal 2008, 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
UGI primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries.
These arrangements are not subject to the recognition and measurement guidance relating to
guarantees under accounting principles generally accepted in the United States of America “GAAP.”
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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 Matters
Gas Utility
On January 28, 2009, PNG and CPG filed separate requests with the PUC to increase base
operating revenues by $38.1 million annually for PNG and $19.6 million annually for CPG to fund
system improvements and operations necessary to maintain safe and reliable natural gas service and
energy assistance for low income customers as well as energy conservation programs for all
customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on
agreements with the opposing parties regarding the requested base operating revenue increases. On
August 27, 2009, the PUC approved the settlement agreements which resulted in a $19.8 million base
operating revenue increase for PNG Gas and a $10.0 million base operating revenue increase for CPG
Gas. The increases became effective August 28, 2009. The full-year effects of these rate increases
are reflected in Gas Utility’s Fiscal 2010 results.
Electric Utility
As a result of Pennsylvania’s ECC Act, all of Electric Utility’s customers are permitted to
acquire their electricity from entities other than Electric Utility. Electric Utility remains the
default service provider for its customers that are not served by an alternate electric generation
provider.
On July 17, 2008, the PUC approved Electric Utility’s DS procurement, implementation and
contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with
the PUC’s DS regulations. The approved plans specify how Electric Utility will solicit and acquire
DS supplies for residential customers for the period January 1, 2010 through May 31, 2014, and for
commercial and industrial customers for the period January 1, 2010 through May 31, 2011
(collectively, the “Settlement Term”). UGI Utilities filed a rate plan on August 29, 2008 for the
Settlement Term. On January 22, 2009, the PUC approved a settlement of the rate filing that
provides for Electric Utility to fully recover its DS costs. On October 1, 2009, UGI Utilities
filed a DS plan to establish procurement rules applicable to the period after May 31, 2011 for its
commercial and industrial customers. Because Electric Utility is assured the recovery of prudently
incurred costs during the Settlement Term, beginning January 1, 2010 Electric Utility is no longer
subject to the risk that actual costs for purchased power will exceed POLR revenues. However,
beginning January 1, 2010, Electric Utility no longer has the opportunity to recover revenues in
excess of actual costs. On May 6, 2010, the PUC approved the plan, as modified by the terms of a
March 2010 settlement.
Prior to January 1, 2010, the terms and conditions under which Electric Utility provided POLR
service, and rules governing the rates that could be charged for such service through December 31,
2009, were established in a series of PUC approved settlements (collectively, the “POLR
Settlement”), the latest of which became effective June 23, 2006. In accordance with the POLR
Settlement, Electric Utility could increase its POLR rates up to certain limits through December
31, 2009. Consistent with the terms of the POLR Settlement, Electric Utility increased its POLR
rates effective January 1, 2009, which increased the average cost to a residential heating customer
by approximately 1.5% over such costs in effect during calendar year 2008. Effective January 1,
2008, Electric Utility increased its POLR rates which increased the average cost to a residential
heating customer by approximately 5.5% over such costs in effect during calendar year 2007.
Regulatory Asset — UGI Utilities Pension Plan
On April 14, 2010, UGI Utilities, Inc. and PNG filed a petition with the PUC requesting
permission to record a regulatory asset or liability for amounts relating to their combined pension
plan that otherwise would be recorded to accumulated other comprehensive income under the FASB’s
Accounting Standards Codification (“ASC”) 715, “Compensation — Retirement Benefits.” On August 23,
2010, the PUC issued an order permitting UGI Utilities and PNG to establish regulatory assets for
such amounts relating to their regulated operations. Effective September 30, 2010, UGI Utilities
recorded a regulatory asset totaling $142.4 million associated with the underfunded position of the
combined pension plan.
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Subsequent Event — Approval of Transfer of CPG Storage Assets
On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved CPG’s application
to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas
storage facilities, along with related assets, to a special purpose entity, UGI Storage Company, a
subsidiary of Energy Services. CPG will transfer the natural gas storage facilities on or before
April 1, 2011. The net book value of the storage facility assets was approximately $11.0 million as
of September 30, 2010.
Manufactured Gas Plants
UGI Utilities
CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of
Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities
associated with environmental investigation and remediation work at certain properties in
Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP
Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition,
PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP.
The PNG-COA requires PNG to perform annually a specified level of activities associated with
environmental investigation and remediation work at certain properties on which MGP-related
facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures
relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 million and $1.1
million, respectively, in any calendar year. The CPG-COA terminates at the end of 2011 for the MGP
Properties and at the end of 2013 for well plugging activities. The PNG-COA 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 in March 2004. At September 30, 2010 and 2009, our accrued liabilities for
environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled
$21.4 million and $25.0 million, respectively. In accordance with GAAP related to rate-regulated
entities, we have recorded associated regulatory assets in equal amounts.
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, by the early 1950s
UGI Utilities divested all of its utility operations other than certain Pennsylvania operations,
including those which now constitute UGI Gas and Electric Utility.
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. At September 30, 2010, neither UGI Gas’ undiscounted
nor its accrued liability for environmental investigation and cleanup costs was material.
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 three claims against it relating
to out-of-state sites.
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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For additional information on the MGP sites outside of Pennsylvania currently subject to
third-party claims or litigation, see Note 15 to Consolidated Financial Statements.
AmeriGas OLP
By letter dated March 6, 2008, the New York State Department of Environmental Conservation
(“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in Saranac
Lake, New York on its Registry of Inactive Hazardous Waste Disposal Sites. A site characterization
study performed by DEC disclosed contamination related to former MGP operations on the site. DEC
has classified the site as a significant threat to public health or environment with further action
required. The Partnership has researched the history of the site and its ownership interest in the
site. The Partnership has reviewed the preliminary site characterization study prepared by the DEC,
the extent of contamination and the possible existence of other potentially responsible parties.
The Partnership has communicated the results of its research to DEC and is awaiting a response
before doing any additional investigation. Because of the preliminary nature of available
environmental information, the ultimate amount of expected clean up costs cannot be reasonably
estimated.
We cannot predict with certainty the final results of any of the MGP actions described above.
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.
Market Risk Disclosures
Our primary market risk exposures are (1) commodity price risk; (2) interest rate risk; and
(3) foreign currency exchange rate risk. 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.
Commodity Price Risk
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 propane and other energy commodities. Their profitability is sensitive to
changes in LPG supply costs. Increases in supply costs are generally passed on to customers. The
Partnership and International Propane may not, however, always be able to pass through 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 future U.S. dollar denominated LPG product purchases through the use of forward
foreign exchange contracts. Antargaz has used over-the-counter derivative commodity instruments and
may from time-to-time enter into other derivative 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 LPG purchases. Over-the-counter derivative commodity instruments
utilized to hedge forecasted purchases of propane are generally settled at expiration of the
contract.
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred
costs of natural gas it sells to its customers. The recovery clauses provide for a periodic
adjustment 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 uses
derivative financial instruments including natural gas futures and option contracts traded on the
New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its
retail core-market customers. The cost of these derivative financial instruments, net of any
associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. At September 30,
2010, the net fair value of Gas Utility’s natural gas futures and option contracts was a loss of $1.4
million. There were no gains or losses at September 30, 2009.
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Beginning January 1, 2010, Electric Utility’s DS tariffs contain clauses which permit recovery
of all prudently incurred power costs through the application of DS rates. The clauses provide for
periodic adjustments to DS rates for differences between the total amount of power costs collected
from customers and recoverable power costs incurred. Because of this ratemaking mechanism,
beginning January 1, 2010 there is limited power cost risk, including the cost of financial
transmission rights (“FTRs”), associated with our Electric Utility operations. FTRs are financial
instruments that entitle the holder to receive compensation for electricity transmission congestion
charges that result when there is insufficient electricity transmission capacity on the electricity
transmission grid. Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”)
auction process and, to a lesser extent, through purchases at monthly PJM auctions. PJM is a
regional transmission organization that coordinates the movement of wholesale electricity in all or
parts of 14 eastern and midwestern states.
Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures
and swap contracts for a portion of gasoline volumes expected to be used in their operations. These
gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected
in other income. The amount of unrealized gains on these contracts and associated volumes under
contract at September 30, 2010 were not material.
Midstream & Marketing purchases FTRs to economically hedge certain transmission costs that may
be associated with its fixed-price electricity sales contracts. Although Midstream & Marketing’s
FTRs are economically effective as hedges of congestion charges, they do not currently qualify for
hedge accounting treatment.
In order to manage market price risk relating to substantially all of Midstream & Marketing’s
fixed-price sales contracts for natural gas and electricity, Midstream & Marketing purchases
over-the-counter as well as exchange-traded natural gas and electricity futures contracts or enters
into fixed-price supply arrangements. Midstream & Marketing’s exchange-traded natural gas and
electricity futures contracts are traded on the NYMEX and have nominal credit risk. Although
Midstream & Marketing’s fixed-price supply arrangements mitigate most risks associated with its
fixed-price sales contracts, should any of the suppliers under these arrangements fail to perform,
increases, if any, in the cost of replacement natural gas or electricity would adversely impact
Midstream & Marketing’s results. In order to reduce this risk of supplier nonperformance,
Midstream & Marketing has diversified its purchases across a number of suppliers. Midstream &
Marketing has entered into 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, Midstream & Marketing enters into price swap
and option contracts.
UGID has entered into fixed-price sales agreements for a portion of the electricity expected
to be generated by its 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.
Interest Rate Risk
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 their 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 currently includes borrowings under AmeriGas OLP’s credit agreements,
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. Antargaz has effectively fixed the underlying euribor interest rate on its variable-rate
debt through its March 2011 maturity date and Flaga has fixed the underlying euribor interest rate
on a substantial portion of its term loans through their scheduled maturity dates through the use
of interest rate swaps. At September 30, 2010 combined borrowings outstanding under these
agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled $200.4 million.
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 2010 and Fiscal 2009,
an increase in short-term interest rates of 100 basis points (1%) would have increased our Fiscal
2010 and Fiscal 2009 interest expense by $1.3 million and $2.3 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 $94.7 million and $91.0 million at September 30, 2010 and 2009,
respectively. A 100 basis point decrease in market interest rates would result in increases in the
fair value of this fixed-rate debt of $104.8 million and $100.7 million at September 30, 2010 and
2009, respectively.
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Antargaz intends to refinance its variable-rate term loan maturing debt, subject to market
conditions, on a long-term basis by March 2011. As of September 30, 2010, Antargaz has entered into
forward-starting interest rate swaps to hedge the underlying euribor rate of interest relating to 4 1/2 years of quarterly interest payments on €300 million notional amount of long-term debt
commencing March 31, 2011.
Our 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. In order to reduce interest rate risk associated with
near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into
interest rate protection agreements (“IRPAs”).
Foreign Currency Exchange Rate Risk
Our primary currency 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 investments in foreign subsidiaries (“net investment hedges”). Realized gains or losses
on net investment hedges
remain in accumulated other comprehensive income until such foreign operations are liquidated. At
September 30, 2010, the fair value of unsettled net investment hedges was a gain of $0.8 million
which is included in foreign currency exchange rate risk in the table below. With respect to our
net investments in our International Propane operations, a 10% decline in the value of the
associated foreign currencies versus the U.S. dollar, excluding the effects of any net investment
hedges, would reduce their aggregate net book value by approximately $65.8 million, which amount
would be reflected in other comprehensive income.
In addition, in order to reduce volatility, Antargaz hedges a portion of its anticipated U.S.
dollar denominated LPG product purchases during the months of October through March through the use
of forward foreign exchange contracts. The amount of dollar-denominated purchases of LPG represents
approximately 20%-30% of estimated dollar-denominated purchases to occur during the heating-season
months of October to March.
Derivative Financial Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative financial
instrument counterparties. Our derivative financial instrument counterparties principally comprise
major energy companies and major U.S. and international financial institutions. We maintain credit
policies with regard to our counterparties that we believe reduce overall credit risk. These
policies include evaluating and monitoring our counterparties’ financial condition, including their
credit ratings, and entering into agreements with counterparties that govern credit limits. Certain
of these agreements call for the posting of collateral by the counterparty or by the Company in the
form of letters of credit, parental guarantees or cash. Additionally, our natural gas and
electricity exchange-traded futures contracts which are guaranteed by the NYMEX generally require
cash deposits in margin accounts. Declines in natural gas, LPG and electricity product costs can
require our business units to post collateral with counterparties or make margin deposits to
brokerage accounts. At September 30, 2010 and 2009, restricted cash in brokerage accounts totaled
$34.8 million and $7.0 million, respectively.
The following table summarizes the fair values of unsettled market risk sensitive derivative
instruments assets and (liabilities) held at September 30, 2010 and 2009. The table also includes
the changes in fair value that would result if there were a 10% adverse change in (1) the market
prices of commodity derivative instruments including the market prices of LPG, gasoline, natural
gas, electricity and electricity transmission congestion charges; (2) the three-month LIBOR and the
three- and nine-month Euribor; and (3) the value of the euro versus the U.S. dollar. Gas Utility’s
and Electric Utility’s derivative instruments are excluded from the table below because any
associated net gains or losses are refundable to or recoverable from customers in accordance with
Gas Utility and Electric Utility ratemaking.
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| Asset (Liability) | ||||||||
| Change in | ||||||||
| (Millions of dollars) | Fair Value | Fair Value | ||||||
September 30, 2010: |
||||||||
Commodity price risk |
$ | (37.2 | ) | $ | (40.2 | ) | ||
Interest rate risk |
(18.5 | ) | (3.7 | ) | ||||
Foreign currency exchange rate risk |
(2.2 | ) | (12.5 | ) | ||||
September 30, 2009: |
||||||||
Commodity price risk |
$ | 11.4 | $ | (30.2 | ) | |||
Interest rate risk |
(34.4 | ) | (6.0 | ) | ||||
Foreign currency exchange rate risk |
(5.7 | ) | (18.2 | ) | ||||
Because substantially all of our derivative instruments qualify as hedges under GAAP, 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 GAAP
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 PNG Gas and CPG Gas 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.
Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to regulation
by the PUC. In accordance with accounting guidance associated with rate-regulated entities, 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. Based upon GAAP related to rate-regulated entities
and an August 2010 PUC order issued in response to UGI Utilities’ and PNG’s April 2010 joint
petition regarding the regulatory treatment of their combined pension plan, effective September 30,
2010, UGI Utilities recorded a $142.4 million regulatory asset associated with amounts that would
otherwise be recorded in accumulated other comprehensive income under GAAP. As of September 30,
2010, our regulatory assets totaled $306.7 million. See Notes 2 and 8 to the Consolidated Financial
Statements.
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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, 2010, our net property, plant and equipment totaled $3,053.2 million and we recorded
depreciation expense of $187.6 million during Fiscal 2010. As of September 30, 2010, our net
intangible assets other than goodwill totaled $150.1 million and we recorded
amortization expense on intangible assets of $19.9 million during Fiscal 2010.
Purchase Price Allocations. From time to time, the Company enters into material business
combinations. In accordance with accounting guidance associated with business combinations, 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 appraisals.
Estimating fair values can be complex and subject to significant business judgment 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 GAAP, 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, 2010, our goodwill totaled
$1,562.7 million. We did not record any impairments of goodwill
in Fiscal 2010, Fiscal 2009 and
Fiscal 2008.
Pension Plan Assumptions. The cost 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 fixed income market
returns could have a material impact on future pension costs. We believe the two most critical
assumptions are (1) the expected rate of return on plan assets and (2) the discount rate. A
decrease in the expected rate of return on Pension Plans assets of 50 basis points to a rate of
8.0% would result in an increase in pre-tax pension cost of approximately $1.5 million in Fiscal
2011. A decrease in the discount rate of 50 basis points to a rate of 4.5% would result in an
increase in pre-tax pension cost of approximately $2.5 million in Fiscal 2011.
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. In Fiscal 2008, we adopted
new guidance which establishes standards for recognition and measurement of positions taken or
expected to be taken by an entity in its tax returns. Positions taken by an entity in its tax
returns must satisfy a more-likely-than-not recognition threshold assuming the position will be
examined by tax authorities with full knowledge of relevant information. 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, 2010, our net deferred tax liabilities
totaled $568.8 million.
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Newly Adopted and Recently Issued Accounting Pronouncements
See Note 3 to Consolidated Financial Statements for a discussion of the effects of accounting
guidance we adopted in Fiscal 2010 as well as recently issued accounting guidance not yet adopted.
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 disclosure controls and procedures are designed 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
required disclosure. 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 effective at the reasonable assurance level. |
| (b) | For “Management’s 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. |
ITEM 9B. OTHER INFORMATION
None.
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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 December 31, 2010.
| Captions of Proxy Statement | ||||
| Information | Incorporated by Reference | |||
| Directors, Executive Officers and Corporate Governance | Election of Directors — Nominees; Corporate Governance; Board Independence; Board Committees; Communications with the Board; Audit Committee; 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 Hugh J. Gallagher, Director, Treasury Services and Investor Relations, UGI Corporation, P. O. Box 858, Valley Forge, PA 19482. | ||||
| Executive Compensation | Compensation of Directors; Report of the Compensation and Management Development Committee of the Board of Directors; Compensation Discussion and Analysis; Compensation of Executive Officers; Compensation Committee Interlocks and Insider Participation | |||
| Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | Securities Ownership of Certain Beneficial Owners; Securities Ownership of Management | |||
| Certain Relationships and Related Transactions, and Director Independence | Election of Directors — Board Independence and -Board Committees; Policy for Approval of Related Person Transactions | |||
| Principal Accounting Fees and Services | The Independent Registered Public Accountants | |||
58
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Equity Compensation Table
The following table sets forth information as of the end of Fiscal 2010 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 |
7,392,720 | (1) | $ | 24.07 | 4,076,522 | |||||||
| 930,493 | (2) | $ | 0 | |||||||||
Equity compensation plans not approved by security holders |
164,325 | (3) | $ | 12.06 | 0 | |||||||
Total |
8,487,538 | $ | 23.81 | (4) | 4,076,522 | |||||||
| (1) | Represents 7,392,720 stock options under the 1997 Stock Option and Dividend Equivalent Plan,
the 2000 Directors’ Stock Option Plan, the 2000 Stock Incentive Plan and the UGI Corporation
2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006. |
|
| (2) | Represents 930,493 phantom share units under the UGI Corporation 2004 Omnibus Equity
Compensation Plan Amended and Restated as of December 5, 2006. |
|
| (3) | Column (a) represents 164,325 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. |
|
| (4) | Weighted-average exercise price of outstanding options; excludes phantom share units. |
The information concerning the Company’s executive officers required by Item 10 is set forth
below.
EXECUTIVE OFFICERS
| Name | Age | Position | ||||
Lon R. Greenberg
|
60 | Chairman and Chief Executive Officer | ||||
John L. Walsh
|
55 | President and Chief Operating Officer | ||||
Davinder S. Athwal
|
43 | Vice President — Accounting and Financial Control and Chief Risk Officer | ||||
Eugene V.N. Bissell
|
57 | President and Chief Executive Officer, AmeriGas Propane, Inc. | ||||
Bradley C. Hall
|
57 | Vice President — New Business Development | ||||
Peter Kelly
|
53 | Vice President — Finance and Chief Financial Officer | ||||
Robert H. Knauss
|
57 | Vice President and General Counsel and Assistant Secretary | ||||
François Varagne
|
55 | 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 re-appointed as
Chairman of the Board of Antargaz on April 1, 2010. 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.
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Lon R. Greenberg
Mr. Greenberg was elected Chairman of the Board of Directors 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 also serves on the board of
directors and the audit and compensation committees 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 AmeriGas Propane, Inc., and Director, Vice Chairman, (since
April 2005), President and Chief Executive Officer (since July 2009) of UGI Utilities, Inc. 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 to 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.
Davinder S. Athwal
Mr. Athwal is Vice President — Accounting and Financial Control and Chief Risk Officer (since
January 2009). He previously served as the Global Mergers & Acquisitions Controller of Nortel
Networks, Inc., a global supplier of telecommunications equipment and solutions, a position in
which he served since 2007. Mr. Athwal served as Director, Global Revenue Governance for Nortel
Networks, Inc. from 2006 through 2007. Mr. Athwal served in both accounting and risk management
roles for IBM Corporation, a globally integrated innovation and technology company (2003 to 2006).
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.
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) and UGI Energy Services, Inc. (since 1995). He
joined the Company in 1982 and held various positions in UGI Utilities, Inc., including Vice
President — Marketing and Rates.
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 to 2005). Mr.
Kelly currently serves on the board of directors and the audit and compensation and leadership
development committees of Plexus Corp., an electronics manufacturing services company. Mr. Kelly is
planning to retire in early 2011.
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Table of Contents
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.
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 to 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, 2010 and 2009
Consolidated Statements of Income for the years ended September 30, 2010, 2009 and 2008
Consolidated
Statements of Comprehensive Income for the years ended September 30, 2010, 2009 and 2008
Consolidated Statements of Cash Flows for the years ended September 30, 2010, 2009 and
2008
Consolidated
Statements of Changes in Equity for the years ended September 30, 2010,
2009 and 2008
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, 2010, 2009 and
2008
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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(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 | 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) | |||||||
| 4.2 | UGI’s (Second) Amended and Restated
Articles of Incorporation and
Bylaws referred to in 3.1 and 3.2
above |
|||||||||||
| 4.3 | Fourth Amended and Restated
Agreement of Limited Partnership of
AmeriGas Partners, L.P. dated as of
July 27, 2009
|
AmeriGas Partners, L.P. | Form 10-Q (6/30/09) | 3.1 | ||||||||
| 4.4 | 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 | ||||||||
| 4.5 | 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 | ||||||||
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Table of Contents
| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 4.6 | 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) | |||||||
| 4.7 | 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 | ||||||||
| 4.8 | Form of Fixed Rate Medium-Term Note
|
Utilities | Form 8-K (8/26/94) | 4 | (i) | |||||||
| 4.9 | Form of Fixed Rate Series B
Medium-Term Note
|
Utilities | Form 8-K (8/1/96) | 4 | (i) | |||||||
| 4.10 | Form of Floating Rate Series B Medium-Term Note
|
Utilities | Form 8-K (8/1/96) | 4 | (ii) | |||||||
| 4.11 | Officer’s Certificate establishing Medium-Term Notes Series
|
Utilities | Form 8-K (8/26/94) | 4 | (iv) | |||||||
| 4.12 | Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture
|
Utilities | Form 8-K (8/1/96) | 4 | (iv) | |||||||
| 4.13 | Form of Officers’ Certificate
establishing Series C Medium-Term
Notes under the Indenture
|
Utilities | Form 8-K (5/21/02) | 4.2 | ||||||||
| 4.14 | Forms of Floating Rate and Fixed
Rate Series C Medium-Term Notes
|
Utilities | Form 8-K (5/21/02) | 4.1 | ||||||||
| 10.1 | ** | UGI Corporation 2004 Omnibus Equity
Compensation Plan Amended and
Restated as of December 5, 2006
|
UGI | Form 8-K (3/27/07) | 10.1 | |||||||
| 10.2 | ** | UGI Corporation 2004 Omnibus Equity
Compensation Plan Amended and
Restated as of December 5, 2006 —
Terms and Conditions as amended and
restated effective January 1, 2009
|
UGI | Form 10-K (9/30/09) | 10.2 | |||||||
| 10.3 | ** | 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 | |||||||
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Table of Contents
| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.4 | ** | UGI Corporation Amended and
Restated 2004 Omnibus Equity
Compensation Plan Sub-Plan for
French Employees and Corporate
Officers effective May 20, 2008
|
UGI | Form 10-Q (6/30/08) | 10.1 | |||||||
| *10.5 | ** | UGI Corporation Amended and
Restated Directors’ Deferred
Compensation Plan as of January 1,
2005 |
||||||||||
| 10.6 | ** | UGI Corporation 2000 Directors’
Stock Option Plan Amended and
Restated as of May 24, 2005
|
UGI | Form 10-K (9/30/06) | 10.13 | |||||||
| *10.7 | ** | UGI Corporation 1997 Stock Option
and Dividend Equivalent Plan
Amended and Restated as of May 24,
2005 |
||||||||||
| 10.8 | ** | UGI Corporation 2000 Stock
Incentive Plan Amended and Restated
as of May 24, 2005
|
UGI | Form 10-K (9/30/06) | 10.14 | |||||||
| 10.9 | ** | UGI Corporation 2009 Deferral Plan
As Amended and Restated Effective
June 1, 2010
|
UGI | Form 10-Q (6/30/10) | 10.1 | |||||||
| 10.10 | ** | UGI Corporation Senior Executive
Employee Severance Plan as in
effect as of January 1, 2008
|
UGI | Form 10-Q (3/31/08) | 10.1 | |||||||
| 10.11 | a** | UGI Corporation Supplemental
Executive Retirement Plan and
Supplemental Savings Plan, as
Amended and Restated effective
January 1, 2009
|
UGI | Form 10-K (9/30/09) | 10.11 | |||||||
| 10.11 | b** | Amendment 2009-1 to the UGI
Corporation Supplemental Executive
Retirement Plan and Supplemental
Savings Plan as Amended and
Restated effective January 1, 2009
|
UGI | Form 10-Q (12/31/09) | 10.1 | |||||||
| 10.11 | c** | UGI Corporation 2009 Supplemental Executive Retirement Plan For New Employees |
UGI | Form 10-Q (12/31/09) | 10.2 | |||||||
| 10.12 | ** | UGI Corporation Executive Annual
Bonus Plan effective as of October
1, 2006
|
UGI | Form 10-K (9/30/07) | 10.8 | |||||||
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Table of Contents
| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.13 | ** | AmeriGas Propane, Inc. 2000
Long-Term Incentive Plan on Behalf
of AmeriGas Partners, L.P., as
amended and restated effective
January 1, 2005
|
AmeriGas Partners, L.P. | Form 10-K (9/30/08) | 10.7 | |||||||
| 10.14 | a** | AmeriGas Propane, Inc. 2010
Long-Term Incentive Plan on Behalf
of AmeriGas Partners, L.P.,
Effective July 30, 2010
|
AmeriGas Partners, L.P. | Form 8-K (7/30/10) | 10.2 | |||||||
| 10.14 | b** | AmeriGas Propane, Inc. 2010
Long-Term Incentive Plan on Behalf
of AmeriGas Partners, L.P. — Terms
and Conditions
|
AmeriGas Partners, L.P. | Form 10-K (9/30/10) | 10.10a | |||||||
| 10.15 | ** | AmeriGas Propane, Inc.
Non-Qualified Deferred Compensation
Plan, as amended and restated
effective January 1, 2009
|
AmeriGas Partners, L.P. | Form 10-K (9/30/08) | 10.44 | |||||||
| 10.16 | ** | AmeriGas Propane, Inc. Senior
Executive Employee Severance Plan,
as in effect January 1, 2008
|
AmeriGas Partners, L.P. | Form 10-K (9/30/09) | 10.12 | |||||||
| 10.17 | ** | AmeriGas Propane, Inc. Executive
Employee Severance Plan, as in
effect January 1, 2008
|
AmeriGas Partners, L.P. | Form 10-K (9/30/08) | 10.4 | |||||||
| 10.18 | ** | AmeriGas Propane, Inc. Supplemental
Executive Retirement Plan, as
Amended and Restated Effective
January 1, 2009
|
AmeriGas Partners, L.P. | Form 10-Q (12/31/09) | 10.1 | |||||||
| 10.19 | ** | 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 | |||||||
| 10.20 | ** | Summary of Antargaz Supplemental
Retirement Plans effective as of
September 1, 2009
|
UGI | Form 10-K (9/30/09) | 10.20 | |||||||
| 10.21 | ** | UGI Corporation 2004 Omnibus Equity
Compensation Plan Stock Unit Grant
Letter for Non Employee Directors,
dated January 8, 2010
|
UGI | Form 10-Q (3/31/10) | 10.7 | |||||||
| 10.22 | ** | UGI Corporation 2004 Omnibus Equity
Compensation Plan Stock Unit Grant
Letter for UGI Employees, dated
January 1, 2009
|
UGI | Form 10-Q (3/31/09) | 10.8 | |||||||
| 10.23 | ** | UGI Corporation 2004 Omnibus Equity
Compensation Plan Stock Unit Grant
Letter for Utilities Employees,
dated January 1, 2009
|
UGI | Form 10-K (9/30/09) | 10.23 | |||||||
65
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| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.24 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 8, 2010 |
UGI | Form 10-Q (3/31/10) | 10.4 | |||||||
| 10.25 | ** | UGI Corporation 2004 Omnibus Equity
Compensation Plan Nonqualified
Stock Option Grant Letter for UGI
Employees, dated January 1, 2010
|
UGI | Form 10-Q (3/31/10) | 10.5 | |||||||
| 10.26 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for AmeriGas Employees, dated January 1, 2010 |
UGI | Form 10-Q (3/31/10) | 10.3 | |||||||
| 10.27 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Utilities Employees, dated January 1, 2010 |
UGI | Form 10-Q (3/31/10) | 10.6 | |||||||
| 10.28 | ** | UGI Corporation 2004 Omnibus Equity
Compensation Plan Performance Unit
Grant Letter for UGI Employees,
dated January 1, 2010
|
UGI | Form 10-Q (3/31/10) | 10.1 | |||||||
| 10.29 | ** | UGI Corporation 2004 Omnibus Equity
Compensation Plan Performance Unit
Grant Letter for UGI Utilities
Employees, dated January 1, 2010
|
UGI | Form 10-Q (3/31/10) | 10.2 | |||||||
| 10.30 | ** | AmeriGas Propane, Inc. 2000
Long-Term Incentive Plan on Behalf
of AmeriGas Partners, L.P., as
amended and restated effective
January 1, 2005, Restricted Unit
Grant Letter dated as of December
31, 2009
|
AmeriGas Partners, L.P. | Form 10-Q (3/31/10) | 10.2 | |||||||
| *10.31 | a** | Amended and Restated UGI
Corporation 2004 Omnibus Equity
Compensation Plan Sub-Plan for
French Employees and Corporate
Officers Stock Option Grant Letter
effective January 1, 2010 |
||||||||||
66
Table of Contents
| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| *10.31 | b** | Amended and Restated UGI
Corporation 2004 Omnibus Equity
Compensation Plan Sub-Plan for
French Employees and Corporate
Officers Performance Unit Grant
Letter effective January 1, 2010 |
||||||||||
| *10.32 | a** | Description of oral compensation
arrangements for Messrs. Greenberg,
Kelly, Varagne and Walsh |
||||||||||
| 10.32 | b** | Description of oral compensation
arrangement for Mr. Bissell |
AmeriGas Partners, L.P. | Form 10-K (9/30/10) | 10.22b | |||||||
| *10.33 | ** | Summary of Director Compensation as
of October 1, 2010 |
||||||||||
| 10.34 | ** | Form of Change in Control Agreement
Amended and Restated as of May 12,
2008 for Messrs. Greenberg, Hall,
Kelly, Knauss and Walsh
|
UGI | Form 10-Q (6/30/08) | 10.3 | |||||||
| 10.35 | ** | Form of Change in Control Agreement
Amended and Restated as of May 12,
2008 for Mr. Bissell
|
AmeriGas Partners, L.P. | Form 10-Q (6/30/08) | 10.1 | |||||||
| 10.36 | ** | Form of Confidentiality and
Post-Employment Activities
Agreement with AmeriGas Propane,
Inc. for Mr. Bissell
|
AmeriGas Partners, L.P. | Form 10-Q (3/31/05) | 10.3 | |||||||
| *10.37 | Trademark License Agreement dated
April 19, 1995 among UGI
Corporation, AmeriGas, Inc.,
AmeriGas Propane, Inc., AmeriGas
Partners, L.P. and AmeriGas
Propane, L.P. |
|||||||||||
| 10.38 | 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 | ||||||||
| *10.39 | Credit Agreement, dated as of April
17, 2009, among AmeriGas Propane,
L.P., as Borrower, AmeriGas
Propane, Inc., as Guarantor,
Petrolane Incorporated, as
Guarantor, Citizens Bank of
Pennsylvania, as Syndication Agent,
JPMorgan Chase, N.A., as
Documentation Agent and Wachovia
Bank, National Association, as
Administrative Agent |
|||||||||||
67
Table of Contents
| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.40 | Amendment No. 1 to Credit
Agreement, dated as of July 1,
2010, among the Partnership, as
Borrower, AmeriGas Propane, Inc.,
as Guarantor, Petrolane
Incorporated, as Guarantor,
Citizens Bank of Pennsylvania, as
Syndication Agent, JPMorgan Chase
Bank, N.A., as Documentation Agent
and Wells Fargo Bank, N.A., as
Administrative Agent
|
AmeriGas Partners, L.P. | Form 8-K (7/1/10) | 10.1 | ||||||||
| 10.41 | 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 April
17, 2009
|
AmeriGas Partners, L.P. | Form 8-K (7/20/09) | 10.3 | ||||||||
| *10.42 | 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 |
|||||||||||
| 10.43 | 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 | ||||||||
| 10.44 | 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 | ||||||||
68
Table of Contents
| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.45 | 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 | ||||||||
| *10.46 | Receivables Purchase Agreement,
dated as of November 30, 2001, as
amended through and including
Amendment No. 8 thereto dated April
22, 2010 and Amendment No. 9
thereto dated August 26, 2010, by
and among UGI Energy Services,
Inc., as servicer, Energy Services
Funding Corporation, as seller,
Market Street Funding, LLC, as
issuer, and PNC Bank, National
Association, as administrator |
|||||||||||
| *10.47 | Purchase and Sale Agreement, dated
as of November 30, 2001, as amended
through and including Amendment No.
3 thereto dated August 26, 2010, by
and between UGI Energy Services,
Inc. and Energy Services Funding
Corporation |
|||||||||||
| *10.48 | Credit Agreement, dated as of
August 26, 2010, among UGI Energy
Services, Inc., as borrower, and
JPMorgan Chase Bank, N.A., as
administrative agent, PNC Bank,
National Association, as
syndication agent, and Wells Fargo
Bank, National Association and
Credit Suisse AG, Cayman Islands
Branch, as co-documentation agents |
|||||||||||
| 10.49 | 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 | ||||||||
69
Table of Contents
| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.50 | Amendment Agreement dated October
6, 2008 to Senior Facilities
Agreement dated December 7, 2005 by
and among AGZ Holding, Antargaz,
Calyon and the Financial
Institutions named therein
|
UGI | Form 10-K (9/30/08) | 10.67 | (a) | |||||||
| *10.51 | 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 |
|||||||||||
| *10.52 | 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 |
|||||||||||
| 10.53 | 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 | ||||||||
| 10.54 | 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 | ||||||||
| 10.55 | 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 | ||||||||
| 10.56 | 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 | ||||||||
| 10.57 | ** | AmeriGas Propane, Inc. 2010
Long-Term Incentive Plan on Behalf
of AmeriGas Partners, L.P.
Effective July 30, 2010
|
AmeriGas Partners, L.P. | Form 8-K (7/30/10) | 10.2 | |||||||
70
Table of Contents
| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.58 | ** | AmeriGas Propane, Inc. 2010
Long-Term Incentive Plan on Behalf
of AmeriGas Partners, L.P.
Effective July 30, 2010 — Terms and
Conditions
|
AmeriGas Partners, L.P. | Form 10-K (9/30/10) | 10.10 | |||||||
| 10.59 | Gas Supply and Delivery Service
Agreement between UGI Utilities,
Inc. and UGI Energy Services, Inc.
effective as of May 1, 2007
|
Utilities | Form 10-Q (6/30/10) | 10.1 | ||||||||
| *10.60 | 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) |
|||||||||||
| 10.61 | 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 | ||||||||
| 10.62 | SST Service Agreement No. 79133
dated November 1, 2004 between
Columbia Gas Transmission
Corporation and UGI Utilities, Inc.
|
Utilities | Form 10-Q (6/30/10) | 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 |
|||||||||||
71
Table of Contents
| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| *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, 2010 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, 2010 pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002 |
|||||||||||
| *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, 2010, pursuant to Section 906
of the Sarbanes-Oxley Act of 2002 |
|||||||||||
| *101 | The following materials from UGI Corporation’s Annual Report on Form 10-K for the year ended September 30, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) the
Consolidated Balance Sheets; (ii) the Consolidated Statements of Income; (iii) the Consolidated Statements of
Comprehensive Income; (iv) the Consolidated Statements of Cash Flows;
(v) the Consolidated Statements of Changes in Equity; and
(vi) Notes to Consolidated Financial Statements, tagged as
blocks of text. This Exhibit 101 is deemed not filed for purposes
of Section 11 or 12 of the Securities Act of 1933 and Section 18 of the
Securities Exchange Act of 1934, and otherwise is not subject to liability
under these sections.
|
|||||||||||
| * | Filed herewith. |
|
| ** | As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or
arrangement. |
72
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 19, 2010
|
By: | /s/ Peter Kelly | ||||
| Vice President — Finance and Chief Financial Officer | ||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been
signed below on November 19, 2010, 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, Chief Financial Officer (Principal Financial Officer) |
|
/s/ Davinder S. Athwal
|
Vice President — Accounting and Financial Control, Chief Risk Officer (Principal Accounting Officer) |
|
/s/ Stephen D. Ban
|
Director | |
/s/ Richard C. Gozon
|
Director | |
/s/ Ernest E. Jones
|
Director | |
/s/ Anne Pol
|
Director | |
/s/ M. Shawn Puccio
|
Director | |
/s/ Marvin O. Schlanger
|
Director | |
/s/ Roger B. Vincent
|
Director |
73
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
FINANCIAL INFORMATION
FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K
YEAR ENDED SEPTEMBER 30, 2010
Table of Contents
UGI CORPORATION
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
| Pages | ||||
| F-3 | ||||
| F-4 | ||||
| F-5 | ||||
| F-6 | ||||
| F-7 | ||||
| F-8 | ||||
| F-9 | ||||
| F-10 to F-58 | ||||
Financial Statement Schedules: |
||||
For the years ended September 30, 2010, 2009 and 2008: |
||||
| S-1 to S-3 | ||||
| S-4 to S-5 | ||||
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 (i) overseeing the financial reporting
process and the adequacy of internal control and (ii) 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 the 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 under the
supervision and participation of management including our Chief Executive Officer and our 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’s internal control over
financial reporting was effective as of September 30, 2010, based on the COSO Framework.
PricewaterhouseCoopers LLP, our independent registered public accounting firm, audited the
effectiveness of the Company’s internal control over financial reporting as of September 30, 2010,
as stated in their report, which appears herein.
/s/ Lon R. Greenberg
Chief Executive Officer
Chief Executive Officer
/s/ Peter Kelly
Chief Financial Officer
Chief Financial Officer
/s/ Davinder S. Athwal
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, comprehensive income, changes in equity and cash flows present fairly, in all
material respects, the financial position of UGI Corporation and its subsidiaries at September 30,
2010 and 2009, and the results of their operations and their cash flows for each of the three years
in the period ended September 30, 2010 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, 2010 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 over financial reporting 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 Note 3 to the consolidated financial statements, the Company adopted new accounting
guidance regarding the accounting for and presentation of noncontrolling interests effective
October 1, 2009.
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.
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.
/s/ PricewaterhouseCoopers
Philadelphia, Pennsylvania
November 19, 2010
Philadelphia, Pennsylvania
November 19, 2010
F-4
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
(Millions of dollars)
| September 30, | ||||||||
| 2010 | 2009 | |||||||
ASSETS |
||||||||
Current assets |
||||||||
Cash and cash equivalents |
$ | 260.7 | $ | 280.1 | ||||
Restricted cash |
34.8 | 7.0 | ||||||
Accounts receivable (less allowances for doubtful accounts of
$34.6 and $38.3, respectively) |
467.8 | 405.9 | ||||||
Accrued utility revenues |
14.0 | 21.0 | ||||||
Inventories |
314.0 | 363.2 | ||||||
Deferred income taxes |
32.6 | 34.5 | ||||||
Utility regulatory assets |
26.1 | 19.6 | ||||||
Derivative financial instruments |
11.3 | 20.3 | ||||||
Prepaid expenses and other current assets |
58.8 | 33.5 | ||||||
Total current assets |
1,220.1 | 1,185.1 | ||||||
Property, plant and equipment |
||||||||
Utilities |
2,129.3 | 2,056.9 | ||||||
Non-utility |
2,840.4 | 2,635.5 | ||||||
| 4,969.7 | 4,692.4 | |||||||
Accumulated depreciation and amortization |
(1,916.5 | ) | (1,788.8 | ) | ||||
Net property, plant, and equipment |
3,053.2 | 2,903.6 | ||||||
Goodwill |
1,562.7 | 1,582.3 | ||||||
Intangible assets, net |
150.1 | 165.5 | ||||||
Other assets |
388.2 | 206.1 | ||||||
Total assets |
$ | 6,374.3 | $ | 6,042.6 | ||||
LIABILITIES AND EQUITY |
||||||||
Current liabilities |
||||||||
Current maturities of long-term debt |
$ | 573.6 | $ | 94.5 | ||||
Bank loans |
200.4 | 163.1 | ||||||
Accounts payable |
372.6 | 334.9 | ||||||
Employee compensation and benefits accrued |
86.3 | 89.9 | ||||||
Deposits and advances |
165.3 | 159.6 | ||||||
Derivative financial instruments |
58.0 | 37.5 | ||||||
Other current liabilities |
218.5 | 217.8 | ||||||
Total current liabilities |
1,674.7 | 1,097.3 | ||||||
Debt and other liabilities |
||||||||
Long-term debt |
1,432.2 | 2,038.6 | ||||||
Deferred income taxes |
601.4 | 504.9 | ||||||
Deferred investment tax credits |
5.3 | 5.7 | ||||||
Other noncurrent liabilities |
599.1 | 579.3 | ||||||
Total liabilities |
4,312.7 | 4,225.8 | ||||||
Commitments and contingencies (note 15) |
||||||||
Equity: |
||||||||
UGI Corporation stockholders’ equity: |
||||||||
UGI Common Stock, without par value (authorized - 300,000,000 shares;
issued - 115,400,294 and 115,261,294 shares, respectively) |
906.1 | 875.6 | ||||||
Retained earnings |
966.7 | 804.3 | ||||||
Accumulated other comprehensive loss |
(10.1 | ) | (38.9 | ) | ||||
Treasury stock, at cost |
(38.2 | ) | (49.6 | ) | ||||
Total UGI Corporation stockholders’ equity |
1,824.5 | 1,591.4 | ||||||
Noncontrolling interests, principally in AmeriGas Partners |
237.1 | 225.4 | (1) | |||||
Total equity |
2,061.6 | 1,816.8 | (1) | |||||
Total liabilities and equity |
$ | 6,374.3 | $ | 6,042.6 | ||||
| (1) | As adjusted in accordance with the transition provisions for accounting for noncontrolling
interests in consolidated subsidiaries (Note 3). |
See accompanying notes to consolidated financial statements.
F-5
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
(Millions of dollars, except per share amounts)
| Year Ended September 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Revenues |
||||||||||||
Utilities |
$ | 1,167.7 | $ | 1,379.5 | $ | 1,277.5 | ||||||
Non-utility and other |
4,423.7 | 4,358.3 | 5,370.7 | |||||||||
| 5,591.4 | 5,737.8 | 6,648.2 | ||||||||||
Costs and Expenses |
||||||||||||
Cost of sales (excluding depreciation shown below): |
||||||||||||
Utilities |
730.5 | 944.8 | 915.4 | |||||||||
Non-utility and other |
2,853.5 | 2,725.8 | 3,829.2 | |||||||||
Operating and administrative expenses |
1,177.4 | 1,220.0 | 1,157.3 | |||||||||
Utility taxes other than income taxes |
18.6 | 16.9 | 18.3 | |||||||||
Depreciation |
187.6 | 180.2 | 163.8 | |||||||||
Amortization |
22.6 | 20.7 | 20.6 | |||||||||
Other income, net |
(58.0 | ) | (55.9 | ) | (41.6 | ) | ||||||
| 4,932.2 | 5,052.5 | 6,063.0 | ||||||||||
Operating income |
659.2 | 685.3 | 585.2 | |||||||||
Loss from equity investees |
(2.1 | ) | (3.1 | ) | (2.9 | ) | ||||||
Interest expense |
(133.8 | ) | (141.1 | ) | (142.5 | ) | ||||||
Income before income taxes |
523.3 | 541.1 | 439.8 | |||||||||
Income taxes |
(167.6 | ) | (159.1 | ) | (134.5 | ) | ||||||
Net income |
355.7 | 382.0 | (1) | 305.3 | (1) | |||||||
Less: net income attributable to noncontrolling interests,
principally in AmeriGas Partners |
(94.7 | ) | (123.5) | (1) | (89.8) | (1) | ||||||
Net income attributable to UGI Corporation |
$ | 261.0 | $ | 258.5 | (1) | $ | 215.5 | (1) | ||||
Earnings per common share attributable to UGI Corporation stockholders: |
||||||||||||
Basic |
$ | 2.38 | $ | 2.38 | $ | 2.01 | ||||||
Diluted |
$ | 2.36 | $ | 2.36 | $ | 1.99 | ||||||
Average common shares outstanding (thousands): |
||||||||||||
Basic |
109,588 | 108,523 | 107,396 | |||||||||
Diluted |
110,511 | 109,339 | 108,521 | |||||||||
| (1) | As adjusted in accordance with the transition provisions for accounting for noncontrolling
interests in consolidated subsidiaries (Note 3). |
See accompanying notes to consolidated financial statements.
F-6
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of dollars)
(Millions of dollars)
| Year Ended September 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Net income |
$ | 355.7 | $ | 382.0 | (1) | $ | 305.3 | (1) | ||||
Net losses
on derivative instruments (net of tax of $(29.2), $82.1 and
$21.6, respectively) |
(16.8 | ) | (204.1 | ) | (49.4 | ) | ||||||
Reclassifications of net losses (gains) on derivative instruments (net
of tax of $(25.3), $(78.6) and $2.1, respectively) |
22.9 | 225.0 | (32.9 | ) | ||||||||
Foreign currency translation adjustments (net of tax of $7.9, $(8.4) and
$1.2, respectively) |
(39.4 | ) | 29.5 | (6.6 | ) | |||||||
Benefit plans (net of tax of $12.7, $31.1 and $20.3, respectively) |
(18.7 | ) | (44.4 | ) | (28.5 | ) | ||||||
Reclassification of benefit plans actuarial losses and prior service
costs (net of tax of $(2.9), $(1.6) and $(0.1),
respectively) to net income |
4.2 | 2.3 | 0.2 | |||||||||
Reclassification of pension plans actuarial losses and prior service
costs (net of tax of $(59.1)) to regulatory assets |
83.3 | — | — | |||||||||
Cumulative effect from initial adoption of new accounting for uncertain
tax positions |
— | — | (1.2 | ) | ||||||||
Comprehensive income |
391.2 | 390.3 | 186.9 | |||||||||
Less: comprehensive income attributable to noncontrolling interests,
principally in AmeriGas Partners |
(101.4 | ) | (155.5 | ) | (45.5 | ) | ||||||
Comprehensive income attributable to UGI Corporation |
$ | 289.8 | $ | 234.8 | $ | 141.4 | ||||||
| (1) | As adjusted in accordance with the transition provisions for accounting for noncontrolling
interests in consolidated subsidiaries (Note 3). |
See accompanying notes to consolidated financial statements.
F-7
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
(Millions of dollars)
| Year Ended September 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||||||
Net income |
$ | 355.7 | $ | 382.0 | (1) | $ | 305.3 | (1) | ||||
Reconcile to net cash provided by operating activities: |
||||||||||||
Depreciation and amortization |
210.2 | 200.9 | 184.4 | |||||||||
Gains on sales of LPG storage facilities |
(36.5 | ) | (39.9 | ) | — | |||||||
Deferred income taxes, net |
62.6 | 26.8 | (0.9 | ) | ||||||||
Provision for uncollectible accounts |
27.1 | 34.1 | 37.1 | |||||||||
Stock-based compensation expense |
13.2 | 11.4 | 11.8 | |||||||||
Net change in realized gains and losses deferred as cash flow hedges |
23.8 | (21.0 | ) | (3.8 | ) | |||||||
Other, net |
7.7 | 17.4 | (8.6 | ) | ||||||||
Net change in: |
||||||||||||
Accounts receivable and accrued utility revenues |
(94.6 | ) | 79.5 | (22.2 | ) | |||||||
Inventories |
34.3 | 67.0 | (42.3 | ) | ||||||||
Utility deferred fuel costs, net of changes in
unsettled derivatives |
(18.5 | ) | 10.3 | 21.5 | ||||||||
Accounts payable |
47.1 | (146.1 | ) | (6.0 | ) | |||||||
Other current assets |
(9.4 | ) | 30.3 | (28.5 | ) | |||||||
Other current liabilities |
(23.9 | ) | 12.3 | 16.6 | ||||||||
Net cash provided by operating activities |
598.8 | 665.0 | 464.4 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||||||
Expenditures for property, plant and equipment |
(347.3 | ) | (301.7 | ) | (232.1 | ) | ||||||
Acquisitions of businesses, net of cash acquired |
(83.0 | ) | (322.6 | ) | (1.3 | ) | ||||||
Net proceeds from sale of Partnership LPG storage facility |
— | 42.4 | — | |||||||||
Net proceeds from sale of Atlantic Energy, LLC |
66.6 | — | — | |||||||||
(Increase) decrease in restricted cash |
(27.8 | ) | 63.3 | (57.5 | ) | |||||||
Other, net |
(7.8 | ) | (1.3 | ) | 1.4 | |||||||
Net cash used by investing activities |
(399.3 | ) | (519.9 | ) | (289.5 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||||||
Dividends on UGI Common Stock |
(98.6 | ) | (85.1 | ) | (80.9 | ) | ||||||
Distributions on AmeriGas Partners publicly held Common Units |
(89.1 | ) | (90.4 | ) | (80.9 | ) | ||||||
Issuances of debt |
— | 118.0 | 34.0 | |||||||||
Repayments of debt |
(94.8 | ) | (82.2 | ) | (15.7 | ) | ||||||
Increase (decrease) in bank loans |
37.9 | 13.1 | (60.9 | ) | ||||||||
Issuances of UGI Common Stock |
27.5 | 10.8 | 20.9 | |||||||||
Other |
3.5 | 1.2 | 3.4 | |||||||||
Net cash used by financing activities |
(213.6 | ) | (114.6 | ) | (180.1 | ) | ||||||
EFFECT OF EXCHANGE RATE CHANGES ON CASH |
(5.3 | ) | 4.4 | (1.4 | ) | |||||||
Cash and cash equivalents (decrease) increase |
$ | (19.4 | ) | $ | 34.9 | $ | (6.6 | ) | ||||
Cash and cash equivalents: |
||||||||||||
End of year |
$ | 260.7 | $ | 280.1 | $ | 245.2 | ||||||
Beginning of year |
280.1 | 245.2 | 251.8 | |||||||||
(Decrease) increase |
$ | (19.4 | ) | $ | 34.9 | $ | (6.6 | ) | ||||
SUPPLEMENTAL CASH FLOW INFORMATION: |
||||||||||||
Cash paid for: |
||||||||||||
Interest |
$ | 130.5 | $ | 136.3 | $ | 144.9 | ||||||
Income taxes |
$ | 128.5 | $ | 130.2 | $ | 134.8 | ||||||
| (1) | As adjusted in accordance with the transition provisions for accounting for noncontrolling
interests in consolidated subsidiaries (Note 3). |
See accompanying notes to consolidated financial statements.
F-8
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Millions of dollars, except per share amounts)
(Millions of dollars, except per share amounts)
| Year Ended September 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Common stock, without par value |
||||||||||||
Balance, beginning of year |
$ | 875.6 | $ | 858.3 | $ | 831.6 | ||||||
Common Stock issued: |
||||||||||||
Employee and director plans |
14.4 | 2.9 | 11.2 | |||||||||
Dividend reinvestment plan |
1.7 | 1.6 | 1.7 | |||||||||
Excess tax benefits realized on equity-based compensation |
4.2 | 2.9 | 3.4 | |||||||||
Stock-based compensation expense |
10.2 | 9.9 | 10.4 | |||||||||
Balance, end of year |
$ | 906.1 | $ | 875.6 | $ | 858.3 | ||||||
Retained earnings |
||||||||||||
Balance, beginning of year |
$ | 804.3 | $ | 630.9 | $ | 497.5 | ||||||
Net income attributable to UGI Corporation |
261.0 | 258.5 | (1) | 215.5 | (1) | |||||||
Cumulative effect from initial adoption of new accounting for
uncertain tax positions |
— | — | (1.2 | ) | ||||||||
Cash dividends on Common Stock ($0.90, $0.785 and $0.755
per share, respectively) |
(98.6 | ) | (85.1 | ) | (80.9 | ) | ||||||
Balance, end of year |
$ | 966.7 | $ | 804.3 | $ | 630.9 | ||||||
Accumulated other comprehensive income (loss) |
||||||||||||
Balance, beginning of year |
$ | (38.9 | ) | $ | (15.2 | ) | $ | 57.7 | ||||
Net losses on derivative instruments, net of tax |
(37.8 | ) | (127.3 | ) | (34.9 | ) | ||||||
Reclassification of net losses (gains) on derivative instruments,
net of tax |
37.2 | 116.2 | (3.1 | ) | ||||||||
Benefit plans, principally actuarial losses, net of tax |
(18.7 | ) | (44.4 | ) | (28.5 | ) | ||||||
Reclassification of benefit plans actuarial losses and prior service
costs, net of tax, to net income |
4.2 | 2.3 | 0.2 | |||||||||
Reclassifications of pension plans actuarial losses and prior service
cost, net of tax, to regulatory assets |
83.3 | — | — | |||||||||
Foreign currency translation adjustments, net of tax |
(39.4 | ) | 29.5 | (6.6 | ) | |||||||
Balance, end of year |
$ | (10.1 | ) | $ | (38.9 | ) | $ | (15.2 | ) | |||
Treasury stock |
||||||||||||
Balance, beginning of year |
$ | (49.6 | ) | $ | (56.3 | ) | $ | (64.9 | ) | |||
Common Stock issued: |
||||||||||||
Employee and director plans |
10.6 | 5.9 | 8.1 | |||||||||
Dividend reinvestment plan |
0.8 | 0.8 | 0.5 | |||||||||
Balance, end of year |
$ | (38.2 | ) | $ | (49.6 | ) | $ | (56.3 | ) | |||
Total UGI Corporation stockholders’ equity |
$ | 1,824.5 | $ | 1,591.4 | $ | 1,417.7 | ||||||
Noncontrolling interests |
||||||||||||
Balance, beginning of year |
$ | 225.4 | $ | 159.2 | (1) | $ | 192.2 | (1) | ||||
Net income attributable to noncontrolling interests,
principally in AmeriGas Partners |
94.7 | 123.5 | (1) | 89.8 | (1) | |||||||
Net gains (losses) on derivative instruments |
21.0 | (76.8) | (1) | (14.5) | (1) | |||||||
Reclassification of net (gains) losses on derivative instruments |
(14.3 | ) | 108.8 | (1) | (29.8) | (1) | ||||||
Dividends and distributions |
(89.1 | ) | (91.7) | (1) | (80.9) | (1) | ||||||
Other |
(0.6 | ) | 2.4 | (1) | 2.4 | (1) | ||||||
Balance, end of year |
$ | 237.1 | $ | 225.4 | (1) | $ | 159.2 | (1) | ||||
Total equity |
$ | 2,061.6 | $ | 1,816.8 | (1) | $ | 1,576.9 | (1) | ||||
| (1) | As adjusted in accordance with the transition provisions for accounting for noncontrolling
interests in consolidated subsidiaries (Note 3). |
See accompanying notes to consolidated financial statements.
F-9
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)
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Index to Notes
Note 1 — Nature of Operations |
||||
Note 2 — Significant Accounting Policies |
||||
Note 3 — Accounting Changes |
||||
Note 4 — Acquisitions and Dispositions |
||||
Note 5 — Debt |
||||
Note 6 — Income Taxes |
||||
Note 7 — Employee Retirement Plans |
||||
Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters |
||||
Note 9 — Inventories |
||||
Note 10 — Property, Plant and Equipment |
||||
Note 11 — Goodwill and Intangible Assets |
||||
Note 12 — Series Preferred Stock |
||||
Note 13 — Common Stock and Equity-Based Compensation |
||||
Note 14 — Partnership Distributions |
||||
Note 15 — Commitments and Contingencies |
||||
Note 16 — Fair Value Measurements |
||||
Note 17 — Disclosures About Derivative Instruments and Hedging Activities |
||||
Note 18 — Energy Services Accounts Receivable Securitization Facility |
||||
Note 19 — Other Income, Net |
||||
Note 20 — Quarterly Data (unaudited) |
||||
Note 21 — Segment Information |
Note 1 — Nature of Operations
UGI Corporation (“UGI”) is a holding company that,
through subsidiaries and affiliates, distributes and markets energy products and related services.
In the United States, we own and operate (1) a retail propane marketing and distribution business;
(2) natural gas and electric distribution utilities; (3) electricity generation facilities; and (4)
an energy marketing, midstream infrastructure and energy services business. Internationally, we
market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe and China. We
refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”
We conduct a domestic propane marketing and distribution business through AmeriGas Partners,
L.P. (“AmeriGas Partners”), a publicly traded limited partnership, and its principal operating
subsidiaries AmeriGas Propane, L.P. (“AmeriGas OLP”) and AmeriGas OLP’s subsidiary, AmeriGas Eagle
Propane, L.P. (together with AmeriGas OLP, the “Operating Partnerships”). AmeriGas Eagle Propane,
L.P. merged with and into AmeriGas OLP on October 1, 2010. AmeriGas Partners and the Operating
Partnerships 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. 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, 2010, the General Partner held a 1% general partner interest and 42.8% limited
partner interest in AmeriGas Partners and an effective 44.4% ownership interest in AmeriGas OLP.
Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners Common
Units (“Common Units”). The remaining 56.2% interest in AmeriGas Partners comprises 32,397,300
Common Units held by the general public as limited partner interests. Effective October 1, 2010,
AmeriGas Eagle Propane, L.P. merged with and into AmeriGas OLP.
Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries (1)
conducts an LPG distribution business in France (“Antargaz”); (2) conducts an LPG distribution
business in other European countries (“Flaga”); and (3) conducts an LPG distribution business in
the Nantong region of China. We refer to our foreign operations collectively as “International
Propane.” Enterprises, through Energy Services, Inc. and its subsidiaries, conducts an energy
marketing, midstream infrastructure and energy services business primarily in the Mid-Atlantic
region of the United States. In addition, Energy Services’ wholly owned subsidiary, UGI Development
Company (“UGID”), owns all or a portion of electric generation facilities located in Pennsylvania.
The businesses of Energy Services and its subsidiaries, including UGID, are referred to herein
collectively as “Midstream & Marketing.” Enterprises also conducts heating, ventilation,
air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region
through first-tier subsidiaries.
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)
Our natural gas and electric distribution utility businesses are conducted through our wholly
owned subsidiary UGI Utilities, Inc. (“UGI Utilities”) and its subsidiaries UGI Penn Natural Gas,
Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate
natural gas distribution utilities in eastern, northeastern and central Pennsylvania. UGI Utilities
also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric
Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas;” PNG’s
natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution
utility is referred to as “CPG Gas.” UGI Gas, PNG Gas and CPG Gas are collectively referred to as
“Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission
(“PUC”) and the Maryland Public Service Commission, and Electric Utility is subject to regulation
by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”
Note 2 — Significant Accounting Policies
Basis of Presentation
Our consolidated financial statements are prepared in accordance with accounting principles
generally accepted in the United States of America (“GAAP”).
The preparation of financial statements in accordance with GAAP requires management to make
estimates and assumptions that affect the reported amounts of assets, liabilities, revenues,
expenses and costs. These estimates are based on management’s knowledge of current events,
historical experience and various other assumptions that are believed to be reasonable under the
circumstances. Accordingly, actual results may be different from these estimates and assumptions.
Certain prior-year amounts have been reclassified to conform to the current-year presentation.
As discussed in Note 3, the consolidated financial statements have been adjusted to comply with
recently adopted Financial Accounting Standards Board’s (“FASB’s”) accounting guidance regarding
the presentation of noncontrolling interests in consolidated financial statements.
Principles of Consolidation
The consolidated financial statements include the accounts of UGI and its controlled
subsidiary companies which, except for the Partnership, are majority owned. We report the general
public’s interests in the Partnership and other parties’ interests in consolidated but less than
100% owned subsidiaries as noncontrolling interests. We eliminate all significant intercompany
accounts and transactions when we consolidate. Investments in business entities in which we do not
have control, but have significant influence over operating or financial policies, are accounted
for under the equity method of accounting and our proportionate share of income or loss is recorded
in loss from equity investees on the Consolidated Statements of Income. Undistributed net earnings
of our equity investees included in consolidated retained earnings were not material at September
30, 2010. Investments in business entities that are not publicly traded and in which we hold less
than 20% of voting rights are accounted for using the cost method. Such investments are recorded in
other assets and totaled $68.8 and $55.0 at September 30, 2010 and 2009, respectively.
On January 29, 2009, Flaga purchased for cash consideration the 50% equity interest in
Zentraleuropa LPG Holdings GmbH (“ZLH”) it did not already own from its joint-venture partner,
Progas GmbH & Co. KG. As a result, the operations of ZLH are consolidated with those of the Company
beginning in January 2009.
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)
Effects of Regulation
UGI Utilities accounts for the financial effects of regulation in accordance with the FASB’s
guidance in Accounting Standards Codification (“ASC”) 980
related to regulated entities whose rates are designed to recover the costs of providing service.
In accordance with this guidance, incurred costs and estimated future expenditures that would
otherwise be charged to expense are capitalized and recorded as regulatory assets when it is
probable that the incurred costs or estimated future expenditures will be recovered in rates in the
future. Similarly, we recognize regulatory liabilities when it is probable that regulators will
require customer refunds through future rates or when revenue is collected from customers for
expenditures that have not yet been incurred. Generally, regulatory assets are amortized into
expense and regulatory liabilities are amortized into income over the period authorized by the
regulator.
For additional information regarding the effects of rate regulation on our utility operations,
see Note 8.
Fair Value Measurements
We apply fair value measurements to certain assets and liabilities, principally our commodity,
foreign currency and interest rate derivative instruments. We adopted new accounting guidance with
respect to determining fair value measurements effective October 1, 2008. The new guidance defines
fair value as the price that would be received to sell an asset or paid to transfer a liability (an
exit price) in an orderly transaction between market participants at the measurement date. The new
guidance clarifies that fair value should be based upon assumptions that market participants would
use when pricing an asset or liability, including assumptions about risk and risks inherent in
valuation techniques and inputs to valuations. This includes not only the credit standing of
counterparties and credit enhancements but also the impact of our own nonperformance risk on our
liabilities. The new guidance requires fair value measurements to assume that the transaction
occurs in the principal market for the asset or liability or in the absence of a principal market,
the most advantageous market for the asset or liability (the market for which the reporting entity
would be able to maximize the amount received or minimize the amount paid). We evaluate the need
for credit adjustments to our derivative instrument fair values in accordance with the requirements
noted above. Such adjustments were not material to the fair values of our derivative instruments.
We use the following fair value hierarchy, which prioritizes the inputs to valuation
techniques used to measure fair value into three broad levels:
| • | Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities
that we have the ability to access at the measurement date. Instruments categorized in Level 1
consist of our exchange-traded commodity futures and option contracts and non exchange-traded
commodity futures and non exchange-traded electricity forward contracts whose underlying is
identical to an exchange-traded contract. |
| • | Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or
indirectly observable for the asset or liability, including quoted prices for similar assets
or liabilities in active markets, quoted prices for identical or similar assets or liabilities
in inactive markets, inputs other than quoted prices that are observable for the asset or
liability, and inputs that are derived from observable market data by correlation or other
means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over
the counter commodity price swap and option contracts, interest rate swaps and interest rate
protection agreements, foreign currency forward contracts, financial transmission rights
(“FTRs”) and non exchange-traded electricity forward contracts that do not qualify for Level
1. |
| • | Level 3 — Unobservable inputs for the asset or liability including situations where there is
little, if any, market activity for the asset or liability. We did not have any derivative
financial instruments categorized as Level 3 at September 30, 2010 or 2009. |
The fair value hierarchy gives the highest priority to quoted prices in active markets (Level
1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure
fair value might fall into different levels of the fair value hierarchy. The lowest level input
that is significant to a fair value measurement in its entirety determines the applicable level in
the fair value hierarchy. Assessing the significance of a particular input to the fair
value measurement in its entirety requires judgment, considering factors specific to the asset
or liability. The adoption of the new fair value guidance effective October 1, 2008 did not have a
material impact on our financial statements. See Note 16 for additional information on fair value
measurements.
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)
Derivative Instruments
We account for derivative instruments and hedging activities in accordance with guidance
provided by the FASB which 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.
A substantial portion of our derivative financial instruments are designated and qualify as
cash flow hedges or net investment hedges or, in the case of natural gas derivative financial
instruments used by Gas Utility and certain Electric Utility derivative financial instruments, are
included in deferred fuel and power costs or deferred fuel and power refunds in accordance with
FASB guidance regarding accounting for rate-regulated entities. For cash flow hedges, changes in
the fair value of the derivative financial instruments are recorded in accumulated other
comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting
changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash
flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer
probable. Gains and losses on net investment hedges which relate to our foreign operations are
included in AOCI until such foreign operations are liquidated. Certain of our derivative financial
instruments, although generally effective as hedges, do not qualify for hedge accounting treatment.
Changes in the fair values of these derivative instruments are reflected in net income. Cash flows
from derivative financial instruments, other than net investment hedges, are included in cash flows
from operating activities. Cash flows from net investment hedges are included in cash flows from
investing activities.
For a more detailed description of the derivative instruments we use, our accounting for
derivatives, our objectives for using them and related supplemental information required by GAAP,
see Note 17.
Foreign Currency Translation
Balance sheets of international subsidiaries 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.
Revenue Recognition
Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing
records revenues when energy products are delivered or services are provided to customers. Revenues
from the sale of appliances and equipment are recognized at the later of sale or installation.
Revenues from repair or maintenance services are recognized upon completion of services.
UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered
and include estimated amounts for distribution service and commodities rendered but not billed at
the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or
decreases at the time they become effective.
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.
LPG Delivery Expenses
Expenses associated with the delivery of LPG to customers of the Partnership and our
International Propane operations (including vehicle expenses, expenses of delivery personnel,
vehicle repair and maintenance and general liability expenses) are classified as operating and
administrative expenses on the Consolidated Statements of Income.
Depreciation expense associated with the Partnership and International Propane delivery
vehicles is classified in depreciation on the Consolidated Statements of Income.
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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)
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 (1) our share of 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
and state income taxes. Legislation in certain states allows for taxation of partnership income and
the accompanying financial statements reflect state income taxes resulting from such legislation.
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, principally the result of accelerated tax depreciation for state income tax purposes,
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. Investment
tax credits associated with Midstream & Marketing’s qualifying solar energy property under the
Emergency Economic Stabilization Act of 2008 are reflected in income tax expense when such property
is placed in service.
We record interest on tax deficiencies and income tax penalties in income taxes on the
Consolidated Statements of Income. For Fiscal 2010, Fiscal 2009 and Fiscal 2008, interest (income)
expense of $(0.2), $(0.4) and $0.2, respectively, was recognized in income taxes in the
Consolidated Statements of Income.
Effective
October 1, 2007, we adopted new interpretive guidance issued by the
FASB on accounting for uncertainty related to income taxes. The
cumulative effect from the adoption of the new guidance was recorded
as a $1.2 decrease to the October 1, 2007 retained earnings.
Earnings Per Common Share
Basic earnings per share attributable to UGI Corporation stockholders 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 2010, Fiscal 2009 and
Fiscal 2008:
| (Thousands of shares) | 2010 | 2009 | 2008 | |||||||||
Average common shares outstanding for basic computation |
109,588 | 108,523 | 107,396 | |||||||||
Incremental shares issuable for stock options and common stock awards |
923 | 816 | 1,125 | |||||||||
Average common shares outstanding for diluted computation |
110,511 | 109,339 | 108,521 | |||||||||
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, actuarial gains and losses on postretirement benefit plans and
foreign currency translation adjustments. Other comprehensive income in Fiscal 2010 also includes
the reclassification of $83.3 of accumulated other comprehensive losses associated with a UGI
Utilities’ pension plan, principally actuarial losses, to regulatory assets and deferred income
taxes as a result of an August 2010 PUC order regarding regulatory treatment of the pension plan’s
funded status (see Note 8).
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)
The components of AOCI at September 30, 2010 and 2009 follow:
| Foreign | ||||||||||||||||
| Derivative | Currency | |||||||||||||||
| Postretirement | Instruments Net | Translation | ||||||||||||||
| Benefit Plans | Losses | Adjustments | Total | |||||||||||||
Balance, September 30, 2010 |
$ | (12.8 | ) | $ | (54.1 | ) | $ | 56.8 | $ | (10.1 | ) | |||||
Balance, September 30, 2009 |
$ | (81.5 | ) | $ | (53.6 | ) | $ | 96.2 | $ | (38.9 | ) | |||||
Cash and Cash Equivalents
All highly liquid investments with maturities of three months or less when purchased are
classified as cash equivalents.
Restricted Cash
Restricted cash represents those cash balances in our commodity futures and option brokerage
accounts which are restricted from withdrawal.
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.
Property, Plant and Equipment and Related Depreciation
We record property, plant and equipment at original cost. The amounts assigned to property,
plant and equipment of acquired businesses are based upon estimated fair value at date of
acquisition.
We record depreciation expense on non-utility plant and equipment on a straight-line basis
over estimated economic useful lives ranging from 15 to 40 years for buildings and improvements; 7
to 40 years for storage and customer tanks and cylinders; 25 years for currently operating
electricity generation facilities; and 2 to 12 years for vehicles, equipment and office furniture
and fixtures. 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 record depreciation expense for Utilities’ plant and equipment on a straight-line basis
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
2.5% in Fiscal 2010, and 2.4% in Fiscal 2009 and Fiscal 2008. Depreciation expense as a percentage
of the related average depreciable base for Electric Utility was 2.6% in Fiscal 2010, 2.9% in
Fiscal 2009 and 2.6% in Fiscal 2008. When Utilities 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.
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.
No depreciation expense is included in cost of sales in the Consolidated Statements of Income.
F-15
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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)
Goodwill and Intangible Assets
In accordance with GAAP relating to goodwill and other intangibles, we amortize intangible
assets over their estimated useful lives unless we determine 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. 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 intangible asset impairments were recorded during Fiscal 2010, Fiscal 2009 or
Fiscal 2008.
No amortization expense is included in cost of sales in the Consolidated Statements of Income.
For further information, see Note 11.
Impairment of Long-Lived Assets
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. No provisions
for impairments were recorded during Fiscal 2010, Fiscal 2009 or Fiscal 2008.
Refundable Tank and Cylinder Deposits
Included in “Other noncurrent liabilities” on our Consolidated Balance Sheets are customer
paid deposits on Antargaz owned tanks and cylinders of $211.8 and $230.3 at September 30, 2010 and
2009, respectively. Deposits are refundable to customers when the tanks or cylinders are returned
in accordance with contract terms.
Environmental Matters
We are subject to environmental laws and regulations intended to mitigate or remove the effect
of past operations and improve or maintain the quality of the environment. These laws and
regulations require the removal or remedy of the effect on the environment of the disposal or
release of certain specified hazardous substances at current or former operating sites.
Environmental reserves are accrued when assessments indicate that it is probable that a
liability has been incurred and an amount can reasonably be estimated. Amounts recorded as
environmental liabilities on the balance sheets represent our best estimate of costs expected to be
incurred or, if no best estimate can be made, the minimum liability associated with a range of
expected environmental investigation and remediation 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. CPG Gas and PNG Gas base rate revenues
include amounts for estimated environmental investigation and remediation costs associated with
Pennsylvania sites. For further information, see Note 15.
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 assets of our pension and other postretirement plans. The
market-related value of plan assets, other than equity investments, is based upon fair values. 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 7).
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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)
Equity-Based Compensation
All of our equity-based compensation, principally comprising UGI stock options, grants of UGI
stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with
UGI stock-based equity instruments, “Units”), is measured at fair value on the grant date, date of
modification or end of the period, as applicable. Compensation expense is recognized on a
straight-line basis over the requisite service period. Depending upon the settlement terms of the
awards, all or a portion of the fair value of equity-based awards may be presented as a liability
or as equity in our Consolidated Balance Sheets. 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 at the
grant date and remeasured as of the end of each period.
We have calculated a tax windfall pool using the shortcut method. We record deferred tax
assets for awards that we expect will result in deductions on our income tax returns, based on the
amount of compensation cost recognized and the statutory tax rate in the jurisdiction in which we
will receive a deduction. Differences between the deferred tax assets recognized for financial
reporting purposes and the actual tax benefit received on the income tax return are recorded in
Common Stock (if the tax benefit exceeds the deferred tax asset) or in the Consolidated Statements
of Income (if the deferred tax asset exceeds the tax benefit and no tax windfall pool exists from
previous awards).
For additional information on our equity-based compensation plans and related disclosures, see
Note 13.
Note 3 — Accounting Changes
Adoption of New Accounting Standards
Noncontrolling Interests. Effective October 1, 2009, we adopted new guidance regarding the
accounting for and presentation of noncontrolling interests in consolidated financial statements.
The new guidance changed the accounting and reporting relating to noncontrolling interests in a
consolidated subsidiary. Noncontrolling interests are now classified within equity on the
Consolidated Balance Sheets, a change from their prior classification between liabilities and
stockholders’ equity. Earnings (losses) attributable to noncontrolling interests are now included
in net income (loss) and deducted from net income (loss) to determine net income (loss)
attributable to UGI Corporation. In addition, changes in a parent’s ownership interest while
retaining control are accounted for as equity transactions and any retained noncontrolling equity
investments in a former subsidiary are initially measured at fair value. In accordance with the new
guidance, previous periods have been adjusted to conform to the new presentation.
Business Combinations. Effective October 1, 2009, we adopted new guidance on accounting for
business combinations. The new guidance applies to all transactions or other events in which an
entity obtains control of one or more businesses. The new guidance establishes, among other things,
principles and requirements for how the acquirer (1) recognizes and measures in its financial
statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling
interest in the acquiree; (2) recognizes and measures the goodwill acquired in a business
combination or gain from a bargain purchase; and (3) determines what information with respect to a
business combination should be disclosed. The new guidance applies prospectively to business
combinations for which the acquisition date is on or after October 1, 2009. Among the more
significant changes in accounting for acquisitions are (1) transaction costs are generally expensed
(rather than being included as costs of the acquisition); (2) contingencies, including contingent
consideration, are generally recorded at fair value with subsequent adjustments recognized in
operations (rather than as adjustments to the purchase price); and (3) decreases in valuation
allowances on acquired deferred tax assets are recognized in operations (rather than as decreases
in goodwill). The new guidance did not have a material impact on our Fiscal 2010 financial
statements.
Intangible Asset Useful Lives. Effective October 1, 2009, we adopted new accounting guidance which
amends the factors that should be considered in developing renewal or extension assumptions used to
determine the useful life of a recognized intangible asset under GAAP. The intent of the new
guidance is to improve the consistency between the useful life of a recognized intangible asset
under GAAP relating to intangible asset accounting and the period of expected cash flows used to
measure the fair value of the asset under GAAP relating to business combinations and other
applicable accounting literature. The new guidance must be applied prospectively to intangible
assets acquired after the effective date. The adoption of the new guidance did not impact our
financial statements.
Enhanced Disclosures of Postretirement Plan Assets. Effective September 30, 2010, we adopted
accounting guidance requiring more detailed disclosures about employers’ postretirement plan
assets, including employers’ investment strategies, major categories of plan assets, concentrations
of risk within plan assets, and valuation
techniques used to measure the fair value of plan assets. Because this new guidance relates to
disclosures only, it did not impact the financial statements. The enhanced disclosures are
presented in Note 7.
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)
Fair Value Measurements. In January 2010, the FASB issued new guidance with respect to fair value
measurements disclosures. The new guidance requires additional disclosure related to transfers
between Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements
related to Level 3. The new guidance clarifies existing disclosure guidance about inputs and
valuation techniques for fair value measurements and levels of disaggregation. We apply fair value
measurements to certain assets and liabilities, principally commodity, foreign currency and
interest rate derivative instruments. The new disclosures and clarifications of existing
disclosures are effective for interim and annual reporting periods beginning after December 15,
2009 except for the disclosures about purchases, sales, issuances, and settlements in the roll
forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal
years beginning after December 15, 2009 (Fiscal 2011) and interim periods thereafter. The adoption
of the new guidance that became effective during Fiscal 2010 did not have a material effect on our
disclosures. See Notes 2 and 16 for further information on fair value measurements.
New Accounting Standards Not Yet Adopted
Transfers of Financial Assets. In June 2009, the FASB issued new guidance regarding accounting for
transfers of financial assets. Among other things, the new guidance eliminates the concept of
Qualified Special Purpose Entities (“QSPEs”). It also amends previous derecognition guidance. The
new guidance is effective for financial asset transfers occurring after the beginning of an
entity’s fiscal year that begins after November 15, 2009 (Fiscal 2011). The adoption of the new
accounting guidance will change the accounting for transfers of accounts receivable to a commercial
paper conduit of a major bank under the Energy Services Receivables Facility (see Note 18).
Beginning October 1, 2010, trade receivables transferred to the commercial paper conduit will
remain on the Company’s balance sheet and the Company will reflect a liability equal to the amount
advanced by the commercial paper conduit. Under current accounting guidance, trade accounts
receivable sold to the commercial paper conduit are removed from the balance sheet. Additionally,
the Company will record interest expense on amounts owed to the commercial paper conduit.
Currently, losses on sales of accounts receivable are reflected in other income, net.
Note 4 — Acquisitions & Dispositions
During Fiscal 2010, AmeriGas OLP acquired a number of domestic retail propane distribution
businesses for $34.3 cash, and our International Propane operations acquired propane distribution
businesses in Denmark, Hungary and Switzerland, and an additional 46% interest in our retail
business in China, for total cash consideration of $48.7. During Fiscal 2009, AmeriGas OLP, in
addition to the acquisition of the assets of CPP described below, acquired several retail propane
distribution businesses for total cash consideration of $17.9 and Flaga acquired the 50% of ZLH it
did not already own for $18.2. During Fiscal 2008, AmeriGas OLP acquired several retail propane
distribution businesses for total cash consideration of $2.5.
On October 1, 2008, UGI Utilities acquired all of the outstanding stock of PPL Gas Utilities
Corporation (now CPG), the natural gas distribution utility of PPL Corporation (“PPL”) for cash
consideration of $267.6 plus estimated working capital of $35.4 (the “CPG Acquisition”).
Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary Penn Fuel
Propane, LLC (now named UGI Central Penn Propane, LLC, “CPP”), its retail propane distributor, sold
its assets to AmeriGas OLP. CPG distributes natural gas to approximately 76,000 customers in
eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in
portions of one Maryland county. CPP sold propane to customers principally in eastern Pennsylvania.
UGI Utilities funded the CPG Acquisition at closing with a combination of $120 cash contributed by
UGI on September 25, 2008, proceeds from the issuance on October 1, 2008 of $108 principal amount
of 6.375% Senior Notes due 2013 and approximately $75.0 of borrowings under UGI Utilities’
Revolving Credit Agreement. AmeriGas OLP funded its acquisition of the assets of CPP with
borrowings under the AmeriGas Credit Agreement, and UGI Utilities used the $33.6 cash proceeds from
the sale of the assets of CPP to AmeriGas OLP to reduce its revolving credit agreement borrowings.
The assets and liabilities resulting from the CPG Acquisition which reflect the final purchase
price allocation are included in our Consolidated Balance Sheets at September 30, 2010 and 2009.
Pursuant to the CPG Acquisition
purchase agreement, the purchase price was subject to adjustment for the difference between
the estimated working capital of $35.4 and the actual working capital as of the closing date agreed
to by both UGI Utilities and PPL. During Fiscal 2009, UGI Utilities and PPL reached an agreement on
the working capital adjustment pursuant to which PPL paid UGI Utilities $9.7 in cash, including
interest.
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 purchase price of the CPG Acquisition, including transaction fees and expenses and
incurred liabilities totaling approximately $2.9, has been allocated to the assets acquired and
liabilities assumed as follows:
Current assets less current liabilities |
$ | 22.7 | ||
Property, plant and equipment |
236.1 | |||
Goodwill |
36.8 | |||
Utility regulatory assets |
22.5 | |||
Other assets |
12.5 | |||
Noncurrent liabilities |
(34.4 | ) | ||
Total |
$ | 296.2 | ||
The goodwill above is primarily the result of synergies between the acquired businesses and
our existing utility and propane businesses. Substantially all of the goodwill is deductible for
income tax purposes over a fifteen-year period.
The operating results of CPG and CPP are included in our consolidated results beginning
October 1, 2008. The following table presents pro forma income statement and basic and diluted per
share data for Fiscal 2008 as if the CPG Acquisition had occurred as of October 1, 2007:
| 2008 | ||||
| (pro forma) | ||||
Revenues |
$ | 6,867.6 | ||
Net income attributable to UGI Corporation |
$ | 224.4 | ||
Earnings per share: |
||||
Basic |
$ | 2.09 | ||
Diluted |
$ | 2.07 | ||
The pro forma results of operations reflect CPG’s and CPP’s 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 CPG Acquisition been completed as of the date indicated,
nor are they necessarily indicative of future operating results.
On July 30, 2010, Energy Services sold all of its interest in its second-tier, wholly owned
subsidiary Atlantic Energy, LLC (“Atlantic Energy”) to DCP Midstream Partners, L.P. for $49.0 in
cash plus an amount for inventory and other working capital. Atlantic Energy owns and operates a 20
million gallon marine import and transshipment facility located in the port of Chesapeake,
Virginia. The Company recorded a $36.5 pre-tax gain on the sale which amount is included in “Other
income, net” in the Fiscal 2010 Consolidated Statement of Income. The gain increased Fiscal 2010
net income attributable to UGI Corporation by $17.2 or $0.16 per diluted share. Atlantic Energy’s
income from operations was not material in Fiscal 2010, 2009 and 2008.
On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated above-ground LPG
storage facility located on leased property in California. The Partnership recorded a $39.9 pre-tax
gain on the sale which amount is included in “Other income, net” in the Fiscal 2009 Consolidated
Statement of Income. The gain increased Fiscal 2009 net income attributable to UGI Corporation by
$10.4 or $0.10 per diluted share.
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 5 — Debt
Long-term debt comprises the following at September 30:
| 2010 | 2009 | |||||||
AmeriGas Propane: |
||||||||
AmeriGas Partners Senior Notes: |
||||||||
8.875% Note, due May 2011 |
$ | 14.7 | $ | 14.7 | ||||
7.25% Note, due May 2015 |
415.0 | 415.0 | ||||||
7.125% Note, due May 2016 |
350.0 | 350.0 | ||||||
AmeriGas OLP Series E First Mortgage |
||||||||
Notes, 8.5%, due July 2010 |
— | 80.0 | ||||||
Other |
11.7 | 5.9 | ||||||
Total AmeriGas Propane |
791.4 | 865.6 | ||||||
International Propane: |
||||||||
Antargaz Senior Facilities term loan, due March 2011 |
518.1 | 556.1 | ||||||
Flaga term loan, due through September 2011 |
32.7 | 43.9 | ||||||
Flaga term loan, due through June 2014 |
7.6 | 10.2 | ||||||
Other |
2.7 | 3.6 | ||||||
Total International Propane |
561.1 | 613.8 | ||||||
UGI Utilities: |
||||||||
Senior Notes: |
||||||||
6.375% Notes, due September 2013 |
108.0 | 108.0 | ||||||
5.75% Notes, due October 2016 |
175.0 | 175.0 | ||||||
6.21% Notes, due October 2036 |
100.0 | 100.0 | ||||||
Medium- Term Notes: |
||||||||
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 | 20.0 | ||||||
7.25% Notes, due November 2017 |
20.0 | 20.0 | ||||||
5.67% Notes, due January 2018 |
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 |
640.0 | 640.0 | ||||||
Other |
13.3 | 13.7 | ||||||
Total long-term debt |
2,005.8 | 2,133.1 | ||||||
Less: current maturities |
(573.6 | ) | (94.5 | ) | ||||
Total long-term debt due after one year |
$ | 1,432.2 | $ | 2,038.6 | ||||
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 2011 to 2015 follow:
| 2011 | 2012 | 2013 | 2014 | 2015 | ||||||||||||||||
AmeriGas Propane |
$ | 20.1 | $ | 2.2 | $ | 1.8 | $ | 1.4 | $ | 415.9 | ||||||||||
UGI Utilities |
— | 40.0 | 133.0 | — | 20.0 | |||||||||||||||
International Propane |
553.7 | 2.8 | 2.4 | 2.1 | 0.1 | |||||||||||||||
Other |
0.5 | 0.5 | 0.5 | 0.5 | 0.5 | |||||||||||||||
Total |
$ | 574.3 | $ | 45.5 | $ | 137.7 | $ | 4.0 | $ | 436.5 | ||||||||||
AmeriGas Propane
AmeriGas Partners Senior Notes. The 8.875% and 7.25% Senior Notes may be redeemed at our option.
The 7.125% Senior Notes generally cannot be redeemed at our option prior to May 20, 2011. AmeriGas
Partners may, under certain circumstances involving excess sales proceeds from the disposition of
assets not reinvested in the business or a change of control, be required to offer to prepay its
7.25% and 7.125% Senior Notes.
AmeriGas OLP Credit Agreements. AmeriGas OLP has an unsecured credit agreement (“AmeriGas Credit
Agreement”) consisting of (1) a Revolving Credit Facility and (2) an Acquisition Facility. AmeriGas
OLP also has a $75 unsecured revolving credit facility (“2009 AmeriGas Supplemental Credit
Agreement”). The General Partner and Petrolane Incorporated, a wholly owned subsidiary of the
General Partner, are guarantors of amounts outstanding under the AmeriGas Credit Agreement and the
2009 AmeriGas Supplemental Credit Agreement.
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 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. The AmeriGas Credit Agreement 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 AmeriGas
Credit Agreement Acquisition Facility operates as a revolving facility through October 15, 2011, at
which time amounts then outstanding will be immediately due and payable. At September 30, 2010,
there was $56 of borrowings outstanding under the Revolving Credit Facility and $35 outstanding
under the Acquisition Facility which amounts are reflected as “Bank loans” on the Consolidated
Balance Sheet. The weighted-average interest rate on AmeriGas Credit Agreement borrowings at
September 30, 2010 was 1.31%. There were no AmeriGas Credit Agreement borrowings at September 30,
2009. Issued and outstanding letters of credit, which reduce available borrowings under the Credit
Agreement Revolving Credit Facility, totaled $35.7 and $37.0 at September 30, 2010 and 2009,
respectively.
The AmeriGas Credit Agreement permits 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 (3.25% at September 30, 2010), 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.
The 2009 AmeriGas Supplemental Credit Agreement expires on June 30, 2011 and permits AmeriGas
OLP to borrow up to $75 for working capital and general purposes subject to restrictive covenants
in the Senior Notes indentures. The 2009 AmeriGas Supplemental Credit Agreement permits AmeriGas
OLP to borrow at prevailing interest rates, including the base rate equal to the higher of the
Federal Funds rate plus 0.50%, the agent bank’s prime rate (3.25% at September 30, 2010), or a
libor market index rate (0.26% at September 30, 2010) plus 1%, or at a one-week, two-week or
one-month Eurodollar rate, as defined in the 2009 AmeriGas Supplemental Credit Agreement, plus a
margin. The margin on base rate loans is 2.00% and the margin on Eurodollar loans is 3.00%. There
were no amounts outstanding under the 2009 AmeriGas Supplemental Credit Agreement at September 30,
2010 and 2009.
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 7.25% and 7.125% 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. Under the 7.25% and 7.125% Senior Note Indentures,
AmeriGas Partners is generally permitted to make cash distributions equal to available cash, as
defined, as of the end of the immediately preceding quarter, if certain conditions are met. At
September 30, 2010, these restrictions did not limit the amount of Available Cash AmeriGas Partners
could distribute pursuant to the Fourth Amended and Restated Agreement of Limited Partnership of
AmeriGas Partners, L.P. (“Partnership Agreement”) (see Note 14).
The AmeriGas OLP credit agreements 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 OLP credit agreements require that AmeriGas OLP not exceed a ratio
of total indebtedness, as defined, to EBITDA, as defined; maintain a minimum ratio of EBITDA to
interest expense, as defined; and maintain a minimum EBITDA. 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
Antargaz has a Senior Facilities Agreement with a bank group that expires on March 31, 2011.
The Senior Facilities Agreement consists of (1) a €380 variable-rate term loan and a €50
revolving credit facility. The Senior Facilities Agreement also provides Antargaz a €50 letter
of credit guarantee facility. Antargaz’ term loan and revolving credit facility bear interest at
one-, two-, three- or six-month euribor or libor, plus a margin, as defined by the Senior
Facilities Agreement. Antargaz has executed interest rate swap agreements with a member of the same
bank group 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 17). The effective interest rates on
Antargaz’ term loan at September 30, 2010 and 2009 was 3.94%. Antargaz’ revolving credit facility
permits Antargaz to borrow up to €50 for working capital or general corporate purposes. In order
to minimize the interest margin it pays on its Senior Facilities Agreement borrowings, in September
2010 Antargaz borrowed €50 ($68.2), the total amount available under its revolving credit
facility, which amount remained outstanding at September 30, 2010. This amount was repaid in
October 2010. There were no amounts outstanding under the revolving credit facility at September
30, 2009. The margin on the term loan and revolving credit facility borrowings (which ranges from
0.70% to 1.15%) is dependent upon Antargaz’ ratio of total net debt (excluding bank loans) to
EBITDA, each as defined by the Senior Facilities Agreement. The Senior Facilities Agreement debt is
collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially
all of its accounts receivable.
At September 30, 2010, Flaga had two euro-based variable-rate term loans. The principal
outstanding on the first term loan was €24 ($32.7) and €30 ($43.9) at September 30, 2010 and
2009, respectively. This first 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 ranges from 0.52%
to 1.45% and is based upon certain equity, return on assets and debt to EBITDA ratios as determined
on a UGI consolidated basis. Principal payments totaling €3.0, €6.4 and €14.6 are due in
March, August and September 2011, respectively. Flaga has effectively fixed the euribor component
of its interest rate on this term loan through September 2011 at 3.91% by entering into an interest
rate swap agreement. The effective interest rates on this term loan at September 30, 2010 and 2009
were 4.21% and 4.28%, respectively. Flaga may prepay this term loan, in whole or in part, without
incurring any penalty.
Flaga’s second euro-based variable-rate term loan had an outstanding principal balance of
€5.6 ($7.6) and €7.0 ($10.2) on September 30, 2010 and 2009, respectively. This term loan
matures in June 2014 and bears interest at three-month euribor rates plus a margin. The margin on
such borrowings ranges from 2.625% to 3.50% and is based upon certain equity, return on assets and
debt to EBITDA ratios as determined on a UGI consolidated basis. Semi-annual principal payments of
€0.7 are due on December 31 and June 30 each year through June 2014. Flaga has effectively fixed
the euribor component of the interest rate on this term loan at 2.16% by entering into an interest
rate swap agreement. The effective interest rate on this term loan at September 30, 2010 and 2009
was 5.03%.
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)
Flaga has two working capital facilities totaling €24. Flaga has a multi-currency working
capital facility currently scheduled to expire in June 2011 that provides for borrowings and
issuances of guarantees totaling €16 of which €9.8 ($13.4) and €2.1 ($3.0) was outstanding
at September 30, 2010 and 2009, respectively. Flaga also has an €8 euro-denominated working
capital facility currently scheduled to expire in June 2011 of which €7.9 ($10.8) and €4.1
($6.1) was outstanding at September 30, 2010 and 2009, respectively. Issued and outstanding
guarantees, which reduce available borrowings under the working capital facilities, totaled €5.4
($7.4) at September 30, 2010 and €2.7 ($3.9) at September 30, 2009. Amounts outstanding under
the working capital facilities are classified as bank loans. Borrowings under the working capital
facilities generally bear interest at market rates (a daily euro-based rate or three-month euribor
rates) plus a margin. The weighted-average interest rates on Flaga’s working capital loans were
2.91% at September 30, 2010 and 4.94% at September 30, 2009. In order to provide for additional
borrowing capacity, in November 2010 Flaga entered into an additional €8 multi-currency working
capital facility and an additional €4 euro-denominated working capital facility both of which
expire in June 2011.
Restrictive Covenants and Guarantees. The Senior Facilities Agreement restricts the ability of
Antargaz, to, among other things, incur additional indebtedness, make investments, incur liens, and
effect mergers, consolidations and sales of assets. Under this agreement, Antargaz 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 loans and working capital facilities are guaranteed by UGI. In addition, under
certain conditions regarding changes in certain financial ratios of UGI, the lending banks may
accelerate repayment of the debt.
UGI Utilities
Revolving Credit Agreement. UGI Utilities has a revolving credit agreement (“UGI Utilities
Revolving Credit Agreement”) with a group of banks providing for borrowings of up to $350 which
expires in August 2011. Under the UGI Utilities Revolving Credit Agreement, UGI Utilities may
borrow at various prevailing interest rates, including LIBOR and the banks’ prime rate. UGI
Utilities had borrowings outstanding under the UGI Utilities Revolving Credit Agreement, which we
classify as bank loans, totaling $17 at September 30, 2010 and $154 at September 30, 2009. The
weighted-average interest rates on UGI Utilities’ Revolving Credit Agreement borrowings at
September 30, 2010 and 2009 were 3.25% and 0.59%, respectively. The higher rate at September 30,
2010 is the result of a prime rate borrowing compared to LIBOR borrowings at September 30, 2009.
Restrictive Covenants. UGI Utilities Revolving Credit Agreement requires UGI Utilities not to
exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
Energy Services
Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a
group of lenders providing for borrowings up to $170 (including a $50 sublimit for letters of
credit) which expires in August 2013. The Energy Services Credit Agreement can be used for general
corporate purposes of Energy Services and its subsidiaries. In addition, Energy Services may not
pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated
Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement, does not
exceed 2.00 to 1.00.
Borrowings under the Energy Services Credit Agreement bear interest at either (i) a rate
derived from LIBOR (the “LIBO Rate”) plus 3.0% for each Eurodollar Revolving Loan (as defined in
the Energy Services Credit Agreement) or (ii) the Alternate Base Rate plus 2.0%. The Alternate Base
Rate (as defined in the Energy Services Credit Agreement) is generally the greater of (a) the Agent
Bank’s prime rate, (b) the federal funds rate plus 0.50% and (c) the one-month LIBO Rate plus 1.0%.
The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services.
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)
Restrictive Covenants. The Energy Services Credit Agreement restricts the ability of Energy
Services to dispose of assets, effect certain consolidations or mergers, incur indebtedness and
guaranty obligations, create liens, make acquisitions or investments, make certain dividend or
other distributions and make any material changes to the nature of its businesses. In addition, the
Energy Services Credit Agreement requires Energy Services to not exceed a ratio of Consolidated
Total Indebtedness, as defined, to Consolidated EBITDA, as defined; a minimum ratio of Consolidated
EBITDA to Consolidated Interest Expense, as defined; a maximum ratio of Consolidated Total
Indebtedness to Consolidated Total Capitalization, as defined, at any time when Consolidated Total
Indebtedness is greater than $250; and a minimum Consolidated Net Worth, as defined, of $150.
Energy Services also has a $200 receivables securitization facility (see Note 18).
Restricted Net Assets
At September 30, 2010, the amount of net assets of UGI’s consolidated subsidiaries that was
restricted from transfer to UGI under debt agreements, subsidiary partnership agreements and
regulatory requirements under foreign laws totaled approximately $1,500.
Note 6 — Income Taxes
Income before income taxes comprises the following:
| 2010 | 2009 | 2008 | ||||||||||
Domestic |
$ | 448.8 | $ | 431.7 | $ | 380.5 | ||||||
Foreign |
74.5 | 109.4 | 59.3 | |||||||||
Total income before income taxes |
$ | 523.3 | $ | 541.1 | $ | 439.8 | ||||||
The provisions for income taxes consist of the following:
| 2010 | 2009 | 2008 | ||||||||||
Current expense: |
||||||||||||
Federal |
$ | 60.5 | $ | 69.6 | $ | 92.4 | ||||||
State |
20.4 | 21.6 | 26.1 | |||||||||
Foreign |
25.8 | 41.1 | 16.9 | |||||||||
Investment tax credit |
(1.7 | ) | — | — | ||||||||
Total current expense |
105.0 | 132.3 | 135.4 | |||||||||
Deferred expense (benefit): |
||||||||||||
Federal |
54.5 | 27.6 | (1.6 | ) | ||||||||
State |
6.4 | (1.1 | ) | (3.0 | ) | |||||||
Foreign |
2.1 | 0.7 | 4.1 | |||||||||
Investment tax credit amortization |
(0.4 | ) | (0.4 | ) | (0.4 | ) | ||||||
Total deferred expense (benefit) |
62.6 | 26.8 | (0.9 | ) | ||||||||
Total income tax expense |
$ | 167.6 | $ | 159.1 | $ | 134.5 | ||||||
Federal income taxes for Fiscal 2010, Fiscal 2009 and Fiscal 2008 are net of foreign tax
credits of $2.1, $34.9 and $4.3, respectively.
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)
A
reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:
| 2010 | 2009 | 2008 | ||||||||||
U.S. federal statutory tax rate |
35.0 | % | 35.0 | % | 35.0 | % | ||||||
Difference in tax rate due to: |
||||||||||||
Noncontrolling interests not subject to tax |
(6.4 | ) | (8.0 | ) | (7.1 | ) | ||||||
State income taxes, net of federal benefit |
3.5 | 2.5 | 3.4 | |||||||||
Effects of international operations |
(0.6 | ) | (0.3 | ) | (1.1 | ) | ||||||
Other, net |
0.5 | 0.2 | 0.4 | |||||||||
Effective tax rate |
32.0 | % | 29.4 | % | 30.6 | % | ||||||
Deferred tax liabilities (assets) comprise the following at September 30:
| 2010 | 2009 | |||||||
Excess book basis over tax basis of property, plant and equipment |
$ | 414.9 | $ | 366.2 | ||||
Investment in AmeriGas Partners |
170.9 | 172.5 | ||||||
Intangible assets and goodwill |
51.0 | 51.0 | ||||||
Utility regulatory assets |
127.4 | 51.6 | ||||||
Foreign currency translation adjustment |
12.9 | 21.4 | ||||||
Other |
8.6 | 9.5 | ||||||
Gross deferred tax liabilities |
785.7 | 672.2 | ||||||
Pension plan liabilities |
(76.1 | ) | (60.4 | ) | ||||
Employee-related benefits |
(42.4 | ) | (37.6 | ) | ||||
Operating loss carryforwards |
(25.5 | ) | (25.5 | ) | ||||
Foreign tax credit carryforwards |
(61.3 | ) | (69.6 | ) | ||||
Utility regulatory liabilities |
(13.5 | ) | (16.6 | ) | ||||
Derivative financial instruments |
(34.8 | ) | (30.9 | ) | ||||
Other |
(41.7 | ) | (49.0 | ) | ||||
Gross deferred tax assets |
(295.3 | ) | (289.6 | ) | ||||
Deferred tax assets valuation allowance |
78.4 | 87.8 | ||||||
Net deferred tax liabilities |
$ | 568.8 | $ | 470.4 | ||||
At September 30, 2010, foreign net operating loss carryforwards principally relating to Flaga
and certain operations of Antargaz totaled $32.9 and $5.5, respectively, with no expiration dates.
We have state net operating loss carryforwards primarily relating to certain subsidiaries which
approximate $150.2 and expire through 2030. We also have operating loss carryforwards of $5.1 for
certain operations of AmeriGas Propane that expire through 2029. At September 30, 2010, deferred
tax assets relating to operating loss carryforwards include $7.4 for Flaga, $1.9 for Antargaz, $1.0
for UGI International Holdings (BV), $1.8 for AmeriGas Propane and $13.4 for certain other
subsidiaries. A valuation allowance of $14.2 has been provided for 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
unused. A valuation allowance of $2.9 was also provided for deferred tax assets related to certain
operations of Antargaz and UGI International Holdings, B.V. Operating activities and tax deductions
related to the exercise of non-qualified stock options contributed to the state net operating
losses disclosed above. 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, if realized, relate to
non-qualified stock option deductions, the resulting benefits will be credited to UGI Corporation
stockholders’ equity.
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)
We have foreign tax credit carryforwards of approximately $61.3 expiring through 2021
resulting from the actual and planned repatriation of Antargaz’ accumulated earnings since
acquisition which are includable in U.S. taxable income. 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 all deferred tax assets decreased by $8.3 in
Fiscal 2010 due primarily to a decrease in the foreign tax credit carryforwards of $8.3.
We conduct business and file tax returns in the U.S., numerous states, local jurisdictions and
in France and certain central and eastern European countries. Our U.S. federal income tax returns
are settled through the 2007 tax year and our French tax returns are settled through the 2005 tax
year. Our Austrian tax returns are settled through 2007 and our other central and eastern European
tax returns are effectively settled for various years from 2004 to 2009. UGI Corporation’s federal
income tax return for Fiscal 2008 is currently under audit. Although it is not possible to predict
with certainty the timing of the conclusion of the pending U.S. federal tax audit in progress, we
anticipate that the Internal Revenue Service’s (“IRS’s”) audit of our Fiscal 2008 U.S. federal income tax
return will likely be completed during Fiscal 2011. State and other income tax returns in the U.S.
are generally subject to examination for a period of three to five years after the filing of the
respective returns.
As of September 30, 2010, we have unrecognized income tax benefits totaling $5.4 including
related accrued interest of $0.1. If these unrecognized tax benefits were subsequently recognized,
$1.5 would be recorded as a benefit to income taxes on the consolidated statement of income and,
therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized
tax benefits could occur because of the expiration of the statute of limitations in certain
jurisdictions or as a result of settlements with tax authorities. The amount of reasonably possible
changes in unrecognized tax benefits and related interest in the next twelve months is a net
reduction of approximately $0.5.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as
follows:
Balance at October 1, 2007 |
$ | 4.3 | ||
Additions for tax positions of the current year |
0.7 | |||
Additions for tax positions of prior years |
0.7 | |||
Settlements with tax authorities |
(0.8 | ) | ||
Balance at September 30, 2008 |
4.9 | |||
Additions for tax positions of the current year |
0.5 | |||
Additions for tax positions of prior years |
0.3 | |||
Reductions as a result of tax positions taken in prior years |
(1.2 | ) | ||
Settlements with tax authorities |
(2.2 | ) | ||
Balance at September 30, 2009 |
2.3 | |||
Additions for tax positions of the current year |
4.3 | |||
Reductions as a result of tax positions taken in prior years |
(0.2 | ) | ||
Settlements with tax authorities |
(1.0 | ) | ||
Balance at September 30, 2010 |
$ | 5.4 | ||
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)
The Company received IRS consent to change its tax method of
accounting for capitalizing certain repair and maintenance costs associated with its Gas Utility
and Electric Utility assets beginning with the tax year ended September 30, 2009. The filing of the
Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax
benefits totaling approximately $30.2 which was used to offset Fiscal 2010 federal and state income
tax liabilities. The filing of UGI Utilities’ Fiscal 2009 Pennsylvania income tax return also
produced a $43.4 state net operating loss (“NOL”) carryforward. Under current Pennsylvania state
income tax law, the NOL can be carried forward by UGI Utilities for 20 years and used to reduce
future Pennsylvania taxable income. Because the Company believes that it is more likely than not
that it will fully utilize this state NOL prior to
its expiration, no valuation allowance has been recorded. The Company’s determination of what
constitutes a capital cost versus ordinary expense as it relates to the new tax method will likely
be reviewed upon audit by the IRS and may be subject to subsequent adjustment. Accordingly, the
status of this tax return position is uncertain at this time. In accordance with accounting
guidance regarding uncertain tax positions, the Company has added $3.9 to its liability for
unrecognized tax benefits related to this tax method. However, because this tax matter relates
only to the timing of tax deductibility, we have recorded an offsetting deferred tax asset of an
equal amount. For further information on the regulatory impact of this change, see Note 8.
Note 7 — Employee Retirement Plans
Defined Benefit Pension and Other Postretirement Plans. In the U.S., we sponsor two defined benefit
pension plans for employees hired prior to January 1, 2009 of UGI, UGI Utilities, PNG, CPG and
certain of UGI’s other domestic wholly owned subsidiaries (“Pension Plans”). We also provide
postretirement health care benefits to certain retirees and active employees and postretirement
life insurance benefits to nearly all domestic active and retired employees. 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.
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)
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, 2010 and 2009. 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 | Other Postretirement | |||||||||||||||
| Benefits | Benefits | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
Change in benefit obligations: |
||||||||||||||||
Benefit obligations — beginning of year |
$ | 428.9 | $ | 310.9 | $ | 21.4 | $ | 15.6 | ||||||||
Service cost |
8.7 | 7.1 | 0.4 | 0.3 | ||||||||||||
Interest cost |
23.5 | 23.3 | 1.1 | 1.2 | ||||||||||||
Actuarial loss |
32.2 | 67.0 | 1.6 | 2.2 | ||||||||||||
Acquisitions |
— | 44.5 | — | 3.4 | ||||||||||||
Plan amendments |
— | 0.1 | — | — | ||||||||||||
Plan settlements |
(2.7 | ) | (5.7 | ) | — | — | ||||||||||
Foreign currency |
(0.5 | ) | 0.1 | (0.2 | ) | 0.1 | ||||||||||
Benefits paid |
(18.3 | ) | (18.4 | ) | (1.4 | ) | (1.4 | ) | ||||||||
Benefit obligations — end of year |
$ | 471.8 | $ | 428.9 | $ | 22.9 | $ | 21.4 | ||||||||
Change in plan assets: |
||||||||||||||||
Fair value of plan assets — beginning of year |
$ | 279.8 | $ | 244.7 | $ | 9.7 | $ | 10.0 | ||||||||
Actual gain on plan assets |
25.9 | 15.0 | 0.7 | — | ||||||||||||
Acquisitions |
— | 38.4 | — | — | ||||||||||||
Foreign currency |
(0.2 | ) | 0.1 | — | — | |||||||||||
Employer contributions |
3.4 | 5.7 | 1.0 | 1.1 | ||||||||||||
Settlement payments |
(2.7 | ) | (5.7 | ) | — | — | ||||||||||
Benefits paid |
(18.3 | ) | (18.4 | ) | (1.4 | ) | (1.4 | ) | ||||||||
Fair value of plan assets — end of year |
$ | 287.9 | $ | 279.8 | $ | 10.0 | $ | 9.7 | ||||||||
Funded status of the plans — end of year |
$ | (183.9 | ) | $ | (149.1 | ) | $ | (12.9 | ) | $ | (11.7 | ) | ||||
Assets (liabilities) recorded in the balance sheet: |
||||||||||||||||
Unfunded liabilities — included in other current liabilities |
$ | (20.3 | ) | $ | — | $ | — | $ | — | |||||||
Unfunded liabilities — included in other noncurrent liabilities |
(163.6 | ) | (149.1 | ) | (12.9 | ) | (11.7 | ) | ||||||||
Net amount recognized |
$ | (183.9 | ) | $ | (149.1 | ) | $ | (12.9 | ) | $ | (11.7 | ) | ||||
Amounts recorded in UGI Corporation stockholders’
equity (pre-tax): |
||||||||||||||||
Prior service (credit) cost |
$ | (0.4 | ) | $ | (0.2 | ) | $ | 0.1 | $ | 0.1 | ||||||
Net actuarial loss (gain) |
13.8 | 133.2 | 0.1 | (0.6 | ) | |||||||||||
Total |
$ | 13.4 | $ | 133.0 | $ | 0.2 | $ | (0.5 | ) | |||||||
Amounts recorded in regulatory assets and liabilities (pre-tax): |
||||||||||||||||
Prior service cost (credit) |
$ | 0.3 | $ | — | $ | (3.4 | ) | $ | (3.8 | ) | ||||||
Net actuarial loss |
155.6 | 11.1 | 5.9 | 6.4 | ||||||||||||
Total |
$ | 155.9 | $ | 11.1 | $ | 2.5 | $ | 2.6 | ||||||||
In Fiscal 2011, we estimate that we will amortize $9.2 of net actuarial losses and $0.4 of
prior service credits from UGI stockholders’ equity and regulatory assets into retiree benefit
cost.
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)
Actuarial assumptions for our domestic plans are described 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 earnings effects for the subsequent year. The
discount rate is based upon market-observed yields for high-quality fixed income securities with
maturities that correlate to the anticipated payment of benefits. The expected rate of return on
assets assumption is based on the current and expected asset allocations as well as historical and
expected returns on various categories of plan assets (as further described below).
| Pension Plans | Other Postretirement Benefits | |||||||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2007 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||||||||||||
Weighted-average assumptions: |
||||||||||||||||||||||||||||||||
Discount rate |
5.0 | % | 5.5 | % | 6.8 | % | 6.4 | % | 5.0 | % | 5.5 | % | 6.8 | % | 6.4 | % | ||||||||||||||||
Expected return on plan assets |
8.5 | % | 8.5 | % | 8.5 | % | 8.5 | % | 5.5 | % | 5.5 | % | 5.5 | % | 5.5 | % | ||||||||||||||||
Rate of increase in salary levels |
3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | 3.8 | % | ||||||||||||||||
The ABO for the Pension Plans was $417.8 and $377.7 as of September 30, 2010 and 2009,
respectively.
Net periodic pension expense and other postretirement benefit costs include the following
components:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||
Service cost |
$ | 8.7 | $ | 7.1 | $ | 6.1 | $ | 0.4 | $ | 0.3 | $ | 0.5 | ||||||||||||
Interest cost |
23.5 | 23.3 | 19.6 | 1.1 | 1.2 | 1.2 | ||||||||||||||||||
Expected return on assets |
(25.8 | ) | (25.7 | ) | (24.5 | ) | (0.5 | ) | (0.6 | ) | (0.7 | ) | ||||||||||||
Curtailment gain |
— | — | — | — | — | (2.2 | ) | |||||||||||||||||
Settlement loss |
1.0 | 1.8 | — | — | — | — | ||||||||||||||||||
Amortization of: |
||||||||||||||||||||||||
Transition obligation |
— | — | — | — | 0.2 | 0.2 | ||||||||||||||||||
Prior service benefit |
— | — | — | (0.4 | ) | (0.4 | ) | (0.4 | ) | |||||||||||||||
Actuarial loss (gain) |
5.9 | 3.8 | 0.1 | 0.1 | (0.1 | ) | (0.1 | ) | ||||||||||||||||
Net benefit cost (income) |
13.3 | 10.3 | 1.3 | 0.7 | 0.6 | (1.5 | ) | |||||||||||||||||
Change in associated regulatory
liabilities |
— | — | — | 3.1 | 3.3 | 3.4 | ||||||||||||||||||
Net benefit cost after change in
regulatory liabilities |
$ | 13.3 | $ | 10.3 | $ | 1.3 | $ | 3.8 | $ | 3.9 | $ | 1.9 | ||||||||||||
Pension Plans’ assets are held in trust. It is our general policy to fund amounts for pension
benefits equal to at least the minimum required contribution set forth in applicable employee
benefit laws. From time to time we may, at our discretion, contribute additional amounts. During
Fiscal 2010, we made cash contributions of $3.4 to the Pension Plans. We did not make any
contributions to the Pension Plans in Fiscal 2009 or Fiscal 2008. In conjunction with the
settlement of obligations under a subsidiary retirement benefit plan, Antargaz made a settlement
payment of €4.1 ($5.7) during Fiscal 2009. We believe that we will be required to make
contributions to the Pension Plans in Fiscal 2011 of approximately $20.
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 GAAP. 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. The required contributions to the VEBA during Fiscal 2011 are not expected
to be material.
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)
Expected payments for pension benefits and for other postretirement welfare benefits are as
follows:
| Other | ||||||||
| Pension | Postretirement | |||||||
| Benefits | Benefits | |||||||
Fiscal 2011 |
$ | 19.5 | $ | 2.0 | ||||
Fiscal 2012 |
20.4 | 2.0 | ||||||
Fiscal 2013 |
21.6 | 1.9 | ||||||
Fiscal 2014 |
23.0 | 1.9 | ||||||
Fiscal 2015 |
24.3 | 1.9 | ||||||
Fiscal 2016 – 2020 |
144.2 | 9.6 | ||||||
The assumed domestic health care cost trend rates are 7.5% for Fiscal 2011, decreasing to 5.0%
in Fiscal 2016. A one percentage point change in the assumed health care cost trend rate would
increase (decrease) the Fiscal 2010 postretirement benefit cost and obligation as follows:
| 1% Increase | 1% Decrease | |||||||
Service and interest costs in Fiscal 2010 |
$ | 0.1 | $ | (0.1 | ) | |||
ABO at September 30, 2010 |
$ | 1.2 | $ | (0.9 | ) | |||
We also sponsor unfunded and non-qualified supplemental executive retirement plans. At
September 30, 2010 and 2009, the PBOs of these plans were $23.9 and $20.7, respectively. We
recorded net costs for these plans of $2.6 in Fiscal 2010, $3.1 in Fiscal 2009 and $3.0 in Fiscal
2008. These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’
equity for these plans include pre-tax losses of $4.7 and $4.2 at September 30, 2010 and 2009,
respectively, principally representing unrecognized actuarial losses. We expect to amortize
approximately $0.5 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2011.
Pension Plans and Postretirement Plans Assets. The assets of the Pension Plans and the VEBA are
held in trust. The investment policies and asset allocation strategies for the assets in these
trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The
overall investment objective of the Pension Plans and the VEBA is to achieve the best long-term
rates of return within prudent and reasonable levels of risk. To achieve the stated objective,
investments are made principally in publicly-traded diversified equity and fixed income mutual
funds and UGI Common Stock.
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)
The targets, target ranges and actual allocations for the Pension Plans’ and VEBA trust assets
at September 30 are as follows:
Pension Plans
| Target | ||||||||||||||||
| Actual | Asset | Permitted | ||||||||||||||
| 2010 | 2009 | Allocation | Range | |||||||||||||
Equity investments: |
||||||||||||||||
Domestic |
56.1 | % | 54.9 | % | 52.5 | % | 40.0% - 65.0 | % | ||||||||
International |
12.2 | % | 12.8 | % | 12.5 | % | 7.5% - 17.5 | % | ||||||||
Total |
68.3 | % | 67.7 | % | 65.0 | % | 60.0% - 70.0 | % | ||||||||
Fixed income funds &
cash equivalents |
31.7 | % | 32.3 | % | 35.0 | % | 30.0% - 40.0 | % | ||||||||
Total |
100.0 | % | 100.0 | % | 100.0 | % | ||||||||||
VEBA
| Target | ||||||||||||||||
| Actual | Asset | Permitted | ||||||||||||||
| 2010 | 2009 | Allocation | Range | |||||||||||||
Domestic equity investments |
65.0 | % | 64.9 | % | 65.0 | % | 60.0% - 70.0 | % | ||||||||
Fixed income funds &
cash equivalents |
35.0 | % | 35.1 | % | 35.0 | % | 30.0% - 40.0 | % | ||||||||
Total |
100.0 | % | 100.0 | % | 100.0 | % | ||||||||||
Domestic equity investments include investments in large-cap mutual funds indexed to the S&P
500 and actively managed mid- and small-cap mutual funds. Investments in international equity
mutual funds are indexed to various Morgan Stanley Composite indices. The fixed income investments
comprise investments designed to match the duration of the Barclays Capital Aggregate Bond Index.
According to statute, the aggregate holdings of all qualifying employer securities may not exceed
10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 8.3%
and 7.5% of Pension Plans assets at September 30, 2010 and 2009, respectively. At September 30,
2010, there were no significant concentrations of risk (defined as
greater than 10% of the
fair value of total assets) associated with any individual company, industry sector or
international geographic region.
GAAP establishes a hierarchy that prioritizes fair value measurements based upon the inputs
and valuation techniques used to measure fair value. This fair value hierarchy groups assets into
three levels, as described in Note 2. We maximize the use of observable inputs and minimize the use
of unobservable inputs when determining fair value. The fair values of Pension Plans and VEBA
trust assets are derived from quoted market prices as substantially all of these instruments have
active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the
trustee.
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)
The fair values of the Pension Plans’ assets at September 30, 2010 and 2009 by asset class are
as follows:
| Pension Plans | ||||||||||||||||
| Quoted Prices | ||||||||||||||||
| in Active | Significant | |||||||||||||||
| Markets for | Other | |||||||||||||||
| Identical Assets | Observable | Unobservable | ||||||||||||||
| and Liabilities | Inputs | Inputs | ||||||||||||||
| (Level 1) | (Level 2) | (Level 3) | Total | |||||||||||||
September 30, 2010: |
||||||||||||||||
Equity investments: |
||||||||||||||||
Domestic |
$ | 161.5 | $ | — | $ | — | $ | 161.5 | ||||||||
International |
35.2 | — | — | 35.2 | ||||||||||||
Fixed income |
88.9 | — | — | 88.9 | ||||||||||||
Cash equivalents |
— | 2.3 | — | 2.3 | ||||||||||||
Total |
$ | 285.6 | $ | 2.3 | $ | — | $ | 287.9 | ||||||||
September 30, 2009: |
||||||||||||||||
Equity investments: |
||||||||||||||||
Domestic |
$ | 151.6 | $ | — | $ | — | $ | 151.6 | ||||||||
International |
35.5 | — | — | 35.5 | ||||||||||||
Fixed income |
87.1 | — | — | 87.1 | ||||||||||||
Cash equivalents |
— | 2.2 | — | 2.2 | ||||||||||||
Total |
$ | 274.2 | $ | 2.2 | $ | — | $ | 276.4 | ||||||||
The fair values of the VEBA trust assets at September 30, 2010 and 2009 by asset class are as
follows:
| Postretirement Plans | ||||||||||||||||
| Quoted Prices | ||||||||||||||||
| in Active | Significant | |||||||||||||||
| Markets for | Other | |||||||||||||||
| Identical Assets | Observable | Unobservable | ||||||||||||||
| and Liabilities | Inputs | Inputs | ||||||||||||||
| (Level 1) | (Level 2) | (Level 3) | Total | |||||||||||||
September 30, 2010: |
||||||||||||||||
Domestic equity |
$ | 6.5 | $ | — | $ | — | $ | 6.5 | ||||||||
Fixed income |
3.0 | — | — | 3.0 | ||||||||||||
Cash equivalents |
— | 0.5 | — | 0.5 | ||||||||||||
Total |
$ | 9.5 | $ | 0.5 | $ | — | $ | 10.0 | ||||||||
September 30, 2009: |
||||||||||||||||
Domestic equity |
$ | 6.3 | $ | — | $ | — | $ | 6.3 | ||||||||
Fixed income |
2.9 | — | — | 2.9 | ||||||||||||
Cash equivalents |
— | 0.5 | — | 0.5 | ||||||||||||
Total |
$ | 9.2 | $ | 0.5 | $ | — | $ | 9.7 | ||||||||
The expected long-term rates of return on Pension Plans and VEBA trust assets have been
developed using a best estimate of expected returns, volatilities and correlations for each asset
class. The estimates are based on
historical capital market performance data and future expectations provided by independent
consultants. Future expectations are determined by using simulations that provide a wide range of
scenarios of future market performance. The market conditions in these simulations consider the
long-term relationships between equities and fixed income as well as current market conditions at
the start of the simulation. The expected rate begins with a risk-free rate of return with other
factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates
of return derived from this process are applied to our target asset allocation to develop a
reasonable return assumption.
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)
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 $9.8 in Fiscal 2010, $10.1 in Fiscal 2009 and $9.4 in
Fiscal 2008.
Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters
The following regulatory assets and liabilities associated with Utilities are included in our
accompanying balance sheets at September 30:
| 2010 | 2009 | |||||||
Regulatory assets: |
||||||||
Income taxes recoverable |
$ | 82.5 | $ | 79.5 | ||||
Underfunded pension and postretirement plans |
159.2 | 8.5 | ||||||
Environmental costs |
22.6 | 26.9 | ||||||
Deferred fuel and power costs |
36.6 | 19.6 | ||||||
Other |
5.8 | 7.0 | ||||||
Total regulatory assets |
$ | 306.7 | $ | 141.5 | ||||
Regulatory liabilities: |
||||||||
Postretirement benefits |
$ | 10.5 | $ | 9.3 | ||||
Environmental overcollections |
7.2 | 8.7 | ||||||
Deferred fuel and power refunds |
8.3 | 30.8 | ||||||
State tax benefits — distribution system repairs |
6.7 | — | ||||||
Total regulatory liabilities |
$ | 32.7 | $ | 48.8 | ||||
Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities
pertaining to temporary tax differences principally as a result of the pass through to ratepayers
of accelerated tax depreciation for state income tax purposes, and the flow through of accelerated
tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred
taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax
credits. Utilities has recorded regulatory income tax assets related to these deferred tax
liabilities representing future revenues recoverable through the ratemaking process over the
average remaining depreciable lives of the associated property ranging from 1 to approximately 50
years.
Underfunded
pension and other postretirement plans. This regulatory asset represents the portion of
prior service cost and net actuarial losses associated with pension
and other postretirement benefits
which is probable of being recovered through future rates based upon established regulatory
practices. These regulatory assets are adjusted annually or more frequently under certain
circumstances when the funded status of the plans is recorded in accordance with GAAP relating to
pension and postretirement plans. These costs are amortized over the
average remaining future service lives of plan participants.
Based upon the FASB’s guidance related to rate-regulated entities and an August 2010 PUC order
issued in response to UGI Utilities’ and PNG’s April 2010 joint petition regarding the regulatory
treatment of their combined pension plan (see “Other Regulatory Matters” below), effective
September 30, 2010, UGI Utilities recorded a regulatory asset for the amounts associated with
regulated operations that would otherwise be recorded in AOCI under ASC 715, “Compensation — Retirement Benefits.” Based upon established rate
treatment, CPG historically has recorded regulatory assets associated with its underfunded pension
and other postretirement plans.
F-33
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)
Environmental costs. Environmental costs represents amounts actually spent by UGI Gas to clean up
sites in Pennsylvania as well as the portion of estimated probable future environmental remediation
and investigation costs principally at manufactured gas plant (“MGP”) sites that CPG Gas and PNG
Gas expect to incur in conjunction with remediation consent orders and agreements with the
Pennsylvania Department of Environmental Protection (see Note 15). UGI Gas is currently permitted
to include in rates, through future base rate proceedings, a five-year average of prudently
incurred remediation costs at Pennsylvania sites. PNG Gas and CPG Gas are currently recovering and
expect to continue to recover environmental remediation and investigation costs in base rate
revenues. At September 30, 2010, the period over which PNG Gas and CPG Gas expect to recover these
costs will depend upon future remediation activity.
Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and, commencing January 1,
2010, Electric Utility’s default service (“DS”) tariffs, contain clauses which permit recovery of
all prudently incurred purchased gas and power costs through the application of purchased gas cost
(“PGC”) rates in the case of Gas Utility and DS rates in the case of Electric Utility. The clauses
provide for periodic adjustments to PGC and DS rates for differences between the total amount of
purchased gas and electric generation supply costs collected from customers and recoverable costs
incurred. Net undercollected costs are classified as a regulatory asset and net overcollections
are classified as a regulatory liability.
Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it
purchases for firm- residential, commercial and industrial (“retail core-market”) customers.
Realized and unrealized gains or losses on natural gas derivative financial instruments are
included in deferred fuel costs or refunds. Net unrealized losses on such contracts at September
30, 2010 were $1.4. There were no such unrealized gains or losses at September 30, 2009.
Electric Utility enters into forward electricity purchase contracts to meet a substantial
portion of its electricity supply needs. As more fully described in Note 17 to Consolidated
Financial Statements, during Fiscal 2010, Electric Utility determined that it could no longer
assert that it would take physical delivery of substantially all of the electricity it had
contracted for under its forward power purchase agreements and, as a result, such contracts no
longer qualified for the normal purchases and normal sales exception under GAAP related to
derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are
required to be recorded on the balance sheet at fair value, with an associated adjustment to
regulatory assets or liabilities in accordance with ASC 980 and Electric Utility’s DS procurement,
implementation and contingency plans (as further described below). At September 30, 2010, the fair
values of Electric Utility’s electricity supply contracts was a loss of $19.7 which amount is
reflected in current derivative financial instruments and other noncurrent liabilities on the
September 30, 2010 Consolidated Balance Sheet with an equal and offsetting amount reflected in
deferred fuel and power costs in the table above.
In order to reduce volatility associated with a substantial portion of its electric
transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”).
FTRs are derivative financial instruments that entitle the holder to receive compensation for
electricity transmission congestion charges when there is insufficient electricity transmission
capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover
its DS costs commencing January 1, 2010 through DS rates, realized and unrealized gains or losses
on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power
costs or deferred fuel and power refunds. Unrealized gains on FTRs at September 30, 2010 were not
material.
Postretirement benefits. Gas Utility and Electric Utility are recovering ongoing postretirement
benefit costs at amounts permitted by the PUC in prior base rate proceedings. With respect to UGI
Gas and Electric Utility, the difference between the amounts recovered through rates and the actual
costs incurred in accordance with accounting for postretirement benefits are being deferred for
future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities
in the table above.
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)
Environmental overcollections. This regulatory liability represents the difference between amounts
recovered in rates and actual costs incurred (net of insurance proceeds) associated with the terms
of a consent order agreement between CPG and the Pennsylvania Department of Environmental
Protection to remediate certain gas plant sites.
State income tax benefits — distribution system repairs. As previously described in Note 6, the
Company received IRS consent to change its tax method of accounting for capitalizing certain
repair and maintenance costs associated with its Gas Utility and Electric Utility assets beginning
with the tax year ended September 30, 2009. This regulatory liability represents Pennsylvania
state income tax benefits, net of federal income tax expense, resulting from the deduction for
income tax purposes of these repair and maintenance expenses which are capitalized for regulatory
and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will
be reflected as a reduction to income tax expense over the remaining tax lives of the related book
assets.
Other. Other regulatory assets comprise a number of items including, among others, deferred
postretirement costs, deferred asset retirement costs, deferred rate case expenses, customer choice
implementation costs and deferred software development costs. At September 30, 2010, UGI Utilities
expects to recover these costs over periods of approximately 1 to 5 years.
UGI Utilities’ regulatory liabilities relating to postretirement benefits, environmental
overcollections and state tax benefits — distribution system repairs are included in “Other
noncurrent liabilities” on the Consolidated Balance Sheets. UGI Utilities does not recover a rate
of return on its regulatory assets.
Other Regulatory Matters
PNG and CPG Base Rate Filings. On January 28, 2009, PNG and CPG filed separate requests with the
PUC to increase base operating revenues by $38.1 annually for PNG and $19.6 annually for CPG to
fund system improvements and operations necessary to maintain safe and reliable natural gas service
and energy assistance for low income customers as well as energy conservation programs for all
customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on
agreements with the opposing parties regarding the requested base operating revenue increases. On
August 27, 2009, the PUC approved the settlement agreements which resulted in a $19.8 base
operating revenue increase for PNG Gas and a $10.0 base operating revenue increase for CPG Gas. The
increases became effective August 28, 2009 and did not have a material effect on Fiscal 2009
results.
Electric Utility. 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. Electric Utility
remains the DS provider for its customers that are not served by an alternate electric generation
provider.
F-35
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)
On July 17, 2008, the PUC approved Electric Utility’s DS procurement, implementation and
contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with
the PUC’s DS regulations. These plans did not affect Electric Utility’s existing POLR settlement
effective through December 31, 2009. The approved plans specify how Electric Utility will solicit
and acquire DS supplies for residential customers for the period January 1, 2010 through May 31,
2014, and for commercial and industrial customers for the period January 1, 2010 through May 31,
2011 (collectively, the “Settlement Term”). UGI Utilities filed a rate plan on August 29, 2008 for
the Settlement Term. On January 22, 2009, the PUC approved a settlement of the rate filing that
provides for Electric Utility to fully recover its DS costs. On October 1, 2009, UGI Utilities
filed a DS plan to establish procurement rules
applicable to the period after May 31, 2011 for its commercial and industrial customers. On
May 6, 2010, the PUC approved the plan, as modified by the terms of a March 2010 settlement.
Prior to January 1, 2010, the terms and conditions under which Electric Utility provided
provider of last resort (“POLR”) service, and rules governing the rates that may be charged for
such service through December 31, 2009, were established in a series of PUC approved settlements
(collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006. In
accordance with the POLR Settlement, Electric Utility could increase its POLR rates up to certain
limits through December 31, 2009. Consistent with the terms of the POLR Settlement, Electric
Utility increased its POLR rates effective January 1, 2009, which increased the average cost to a
residential heating customer by approximately 1.5% over such costs in effect during calendar year
2008. Effective January 1, 2008, Electric Utility increased its POLR rates which increased the
average cost to a residential heating customer by approximately 5.5% over such costs in effect
during calendar year 2007.
Regulatory Asset — UGI Utilities Pension Plan. On April 14, 2010, UGI Utilities, Inc. and PNG filed
a petition with the PUC requesting permission to record a regulatory asset or liability for amounts
relating to their combined pension plan that otherwise would be recorded to AOCI under ASC 715,
“Compensation — Retirement Benefits.” On August 23, 2010, the PUC issued an order permitting UGI
Utilities and PNG to establish regulatory assets for such amounts relating to their regulated
operations. Effective September 30, 2010, UGI Utilities recorded a regulatory asset totaling
$142.4 associated with the underfunded position of the combined pension plan.
Subsequent Event — Approval of Transfer of CPG Storage Assets. On October 21, 2010, the Federal
Energy Regulatory Commission (“FERC”) approved CPG’s application to abandon a storage service and
approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with
related assets, to a special purpose entity, UGI Storage Company, a subsidiary of Energy Services.
CPG will transfer the natural gas storage facilities on or before April 1, 2011. The net book value
of the storage facility assets was approximately $11.0 as of September 30, 2010.
Note 9 — Inventories
Inventories comprise the following at September 30:
| 2010 | 2009 | |||||||
Non-utility LPG and natural gas |
$ | 148.0 | $ | 118.0 | ||||
Gas Utility natural gas |
111.5 | 189.7 | ||||||
Materials, supplies and other |
54.5 | 55.5 | ||||||
Total inventories |
$ | 314.0 | $ | 363.2 | ||||
At September 30, 2010, UGI Utilities is a party to three storage contract administrative
agreements (“SCAAs”) two of which expire in October 2012 and one of which expires in October 2010.
Pursuant to these and predecessor SCAAs, UGI Utilities has, among other things, released certain
storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred
certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of
storage inventories at the end of the SCAAs, and makes payments associated with refilling storage
inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories
released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage
inventories, and any exchange receivable (representing amounts of natural gas inventories used by
the other parties to the agreement but not yet replenished), are included in the caption “Gas
Utility natural gas” in the table above. The carrying value of gas storage inventories released
under the SCAAs to non-affiliates at September 30, 2010 and 2009 comprising 8.0 billion cubic feet
(“bcf”) and 1.3 bcf of natural gas was $41.9 and $10.5, respectively. Effective November 1, 2010,
UGI Utilities entered into a new SCAA having a term of three years.
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)
Note 10 — Property, Plant and Equipment
Property, plant and equipment comprise the following at September 30:
| 2010 | 2009 | |||||||
Utilities: |
||||||||
Distribution |
$ | 1,866.0 | $ | 1,813.2 | ||||
Transmission |
78.2 | 76.8 | ||||||
General and other, including work in process |
185.1 | 166.9 | ||||||
Total Utilities |
2,129.3 | 2,056.9 | ||||||
Non-utility: |
||||||||
Land |
94.1 | 96.0 | ||||||
Buildings and improvements |
206.4 | 192.0 | ||||||
Transportation equipment |
111.3 | 110.6 | ||||||
Equipment, primarily cylinders and tanks |
2,020.3 | 1,970.6 | ||||||
Electric generation |
97.9 | 88.1 | ||||||
Other, including work in process |
310.4 | 178.2 | ||||||
Total non-utility |
2,840.4 | 2,635.5 | ||||||
Total property, plant and equipment |
$ | 4,969.7 | $ | 4,692.4 | ||||
Note 11 — Goodwill and Intangible Assets
Goodwill and other intangible assets comprise the following at September 30:
| 2010 | 2009 | |||||||
Goodwill (not subject to amortization) |
$ | 1,562.7 | $ | 1,582.3 | ||||
Other intangible assets: |
||||||||
Customer relationships, noncompete agreements and other |
$ | 215.4 | $ | 219.1 | ||||
Trademark (not subject to amortization) |
46.3 | 49.7 | ||||||
Gross carrying amount |
261.7 | 268.8 | ||||||
Accumulated amortization |
(111.6 | ) | (103.3 | ) | ||||
Net carrying amount |
$ | 150.1 | $ | 165.5 | ||||
Changes in the carrying amount of goodwill are as follows:
| AmeriGas | Gas | Midstream & | International Propane | Corporate & | ||||||||||||||||||||||||
| Propane | Utility | Marketing | Antargaz | Other | Other & Elims. | Total | ||||||||||||||||||||||
Balance September 30, 2008 |
$ | 645.2 | $ | 161.7 | $ | 11.8 | $ | 622.2 | $ | 45.7 | $ | 3.1 | $ | 1,489.7 | ||||||||||||||
Goodwill acquired |
24.7 | 18.4 | — | — | 20.4 | — | 63.5 | |||||||||||||||||||||
Purchase
accounting adjustments |
0.2 | — | — | — | — | (0.1 | ) | 0.1 | ||||||||||||||||||||
Foreign currency translation |
— | — | — | 24.7 | 4.3 | — | 29.0 | |||||||||||||||||||||
Balance September 30, 2009 |
670.1 | 180.1 | 11.8 | 646.9 | 70.4 | 3.0 | 1,582.3 | |||||||||||||||||||||
Goodwill acquired |
12.9 | — | — | — | 20.6 | — | 33.5 | |||||||||||||||||||||
Purchase
accounting adjustments |
0.1 | — | — | — | — | — | 0.1 | |||||||||||||||||||||
Dispositions |
— | — | (9.0 | ) | — | — | 4.0 | (5.0 | ) | |||||||||||||||||||
Foreign currency translation |
— | — | — | (44.2 | ) | (4.0 | ) | — | (48.2 | ) | ||||||||||||||||||
Balance September 30, 2010 |
$ | 683.1 | $ | 180.1 | $ | 2.8 | $ | 602.7 | $ | 87.0 | $ | 7.0 | $ | 1,562.7 | ||||||||||||||
F-37
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 amortize customer relationships and noncompete agreement intangibles over their estimated
periods of benefit which do not exceed 15 years. Amortization expense of intangible assets was
$19.9 in Fiscal 2010, $18.4 in Fiscal 2009 and $18.8 in Fiscal 2008. Estimated amortization expense
of intangible assets during the next five fiscal years is as follows: Fiscal 2011 — $20.0; Fiscal
2012 — $20.5; Fiscal 2013 — $20.3; Fiscal 2014 — $19.3; Fiscal 2015 — $14.5. There were no
accumulated impairment losses at September 30, 2010.
Note 12 — Series Preferred Stock
UGI has 10,000,000 shares of UGI Series Preferred Stock authorized for issuance, including
both series subject to and series not subject to mandatory redemption. We had no shares of UGI
Series Preferred Stock outstanding at September 30, 2010 or 2009.
UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock authorized for
issuance, including both series subject to and series not subject to mandatory redemption. At
September 30, 2010 and 2009, there were no shares of UGI Utilities Series Preferred Stock
outstanding.
Note 13 — Common Stock and Equity-Based Compensation
UGI Common Stock share activity for Fiscal 2008, Fiscal 2009 and Fiscal 2010 follows:
| Issued | Treasury | Outstanding | ||||||||||
Balance, September 30, 2007 |
115,152,994 | (8,506,108 | ) | 106,646,886 | ||||||||
Issued: |
||||||||||||
Employee and director plans |
94,700 | 1,028,843 | 1,123,543 | |||||||||
Dividend reinvestment plan |
— | 90,533 | 90,533 | |||||||||
Balance, September 30, 2008 |
115,247,694 | (7,386,732 | ) | 107,860,962 | ||||||||
Issued: |
||||||||||||
Employee and director plans |
13,600 | 776,074 | 789,674 | |||||||||
Dividend reinvestment plan |
— | 96,071 | 96,071 | |||||||||
Balance, September 30, 2009 |
115,261,294 | (6,514,587 | ) | 108,746,707 | ||||||||
Issued: |
||||||||||||
Employee and director plans |
139,000 | 1,390,207 | 1,529,207 | |||||||||
Dividend reinvestment plan |
— | 97,673 | 97,673 | |||||||||
Balance, September 30, 2010 |
115,400,294 | (5,026,707 | ) | 110,373,587 | ||||||||
Equity-Based Compensation
The Company grants equity-based awards to employees and non-employee directors comprising UGI
stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners Common
Unit-based equity instruments as further described below. We recognized total pre-tax equity-based
compensation expense of $13.2 ($8.7 after-tax), $17.6 ($11.4 after-tax) and $11.8 ($7.7 after-tax)
in Fiscal 2010, Fiscal 2009 and Fiscal 2008, respectively.
UGI Equity-Based Compensation Plans and Awards. Under the UGI Corporation 2004 Omnibus Equity
Compensation Plan Amended and Restated as of 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 awards 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. Except in the event of retirement, death or disability, 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.
F-38
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 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 accumulated in additional Stock
Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of
Common Stock and cash. 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
our practice to issue treasury shares to satisfy substantially all option exercises and UGI Unit
awards. We do not expect to repurchase shares for such purposes during Fiscal 2011.
In June 2008, the Company cancelled and regranted UGI Unit awards and UGI stock option awards
previously granted to certain key employees of Antargaz. The cancellation and regrants did not
affect the number of UGI Units or stock options awarded and we did not record any incremental
expense as a result of these cancellations and regrants.
UGI Stock Option Awards. Stock option transactions under the OECP and predecessor plans for
Fiscal 2008, Fiscal 2009 and Fiscal 2010 follow:
| Weighted | ||||||||||||||||
| Weighted | Total | Average | ||||||||||||||
| Average | Intrinsic | Contract Term | ||||||||||||||
| Shares | Option Price | Value | (Years) | |||||||||||||
Shares under option — September 30, 2007 |
6,358,079 | $ | 19.65 | |||||||||||||
Granted |
1,423,800 | $ | 27.25 | |||||||||||||
Cancelled |
(147,300 | ) | $ | 27.03 | ||||||||||||
Exercised |
(982,334 | ) | $ | 15.64 | $ | 11.2 | ||||||||||
Shares under option — September 30, 2008 |
6,652,245 | $ | 21.71 | $ | 30.9 | 6.6 | ||||||||||
Granted |
1,411,200 | $ | 24.65 | |||||||||||||
Cancelled |
(87,334 | ) | $ | 25.81 | ||||||||||||
Exercised |
(474,618 | ) | $ | 13.30 | $ | 6.0 | ||||||||||
Shares under option — September 30, 2009 |
7,501,493 | $ | 22.74 | $ | 23.2 | 6.4 | ||||||||||
Granted |
1,394,300 | $ | 24.37 | |||||||||||||
Cancelled |
(62,501 | ) | $ | 25.12 | ||||||||||||
Exercised |
(1,276,247 | ) | $ | 18.09 | $ | 11.7 | ||||||||||
Shares under option — September 30, 2010 |
7,557,045 | $ | 23.81 | $ | 36.2 | 6.5 | ||||||||||
Options exercisable — September 30, 2008 |
3,960,778 | $ | 18.93 | |||||||||||||
Options exercisable — September 30, 2009 |
4,744,054 | $ | 21.00 | |||||||||||||
Options exercisable — September 30, 2010 |
4,706,376 | $ | 22.99 | $ | 26.4 | 5.4 | ||||||||||
Non-vested options — September 30, 2010 |
2,850,669 | $ | 25.16 | $ | 9.8 | 8.3 | ||||||||||
Cash
received from stock option exercises and associated tax benefits were
$23.1 and $4.3, $6.3
and $2.2, and $15.4 and $3.7 in Fiscal 2010, Fiscal 2009 and Fiscal 2008, respectively. As of
September 30, 2010, there was $3.6 of unrecognized compensation cost associated with unvested stock
options that is expected to be recognized over a weighted-average period of 1.8 years.
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)
The following table presents additional information relating to stock options outstanding and
exercisable at September 30, 2010:
| Range of exercise prices | ||||||||||||
| $10.20 - | $16.99 - | $22.92 - | ||||||||||
| $16.25 | $22.47 | $28.54 | ||||||||||
Options outstanding at September 30, 2010: |
||||||||||||
Number of options |
308,959 | 1,727,468 | 5,520,618 | |||||||||
Weighted average remaining contractual life (in years) |
2.1 | 4.3 | 7.4 | |||||||||
Weighted average exercise price |
$ | 12.34 | $ | 19.92 | $ | 25.67 | ||||||
Options exercisable at September 30, 2010: |
||||||||||||
Number of options |
308,959 | 1,727,468 | 2,669,949 | |||||||||
Weighted average exercise price |
$ | 12.34 | $ | 19.92 | $ | 26.22 | ||||||
UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options
granted under our option plans was $4.49 in Fiscal 2010, $4.13 in Fiscal 2009 and $5.06 in Fiscal
2008. 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 2010, Fiscal 2009 and Fiscal
2008 are as follows:
| 2010 | 2009 | 2008 | ||||||||||
Expected life of option |
5.75 years | 5.75 years | 5.75 - 6.75 years | |||||||||
Weighted average volatility |
24.0 | % | 23.7 | % | 20.9 | % | ||||||
Weighted average dividend yield |
3.3 | % | 3.0 | % | 2.8 | % | ||||||
Expected volatility |
24.0 | % | 20.3% - 23.7 | % | 20.3% - 20.9 | % | ||||||
Expected dividend yield |
3.3% - 3.4 | % | 2.9% - 3.2 | % | 2.8% - 2.9 | % | ||||||
Risk free rate |
1.7% - 3.1 | % | 1.7% - 3.0 | % | 3.4% - 3.6 | % | ||||||
UGI Unit Awards. UGI Stock Unit 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-years) 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 be paid. 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 GAAP, 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 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, is accounted for as a liability. The
expected term of the UGI Performance Unit awards is three years based on the performance period.
Expected volatility is based on the
historical volatility of UGI Common Stock over a three-year period. The risk-free interest
rate is based on the yields on U.S. Treasury bonds at the time of grant. Volatility for all
companies in the UGI comparator group is based on historical volatility.
F-40
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 | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Risk free rate |
1.7 | % | 1.0 | % | 2.7 | % | ||||||
Expected life |
3 years | 3 years | 3 years | |||||||||
Expected volatility |
28.0 | % | 27.1 | % | 20.5 | % | ||||||
Dividend yield |
3.3 | % | 3.2 | % | 3.1 | % | ||||||
The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be
$22.51 for Units granted in Fiscal 2010, $27.91 for Units granted in Fiscal 2009 and $29.70 for
Units granted in Fiscal 2008.
The following table summarizes UGI Unit award activity for Fiscal 2010:
| Total | Vested | Non-Vested | ||||||||||||||||||||||
| Weighted | Weighted | Weighted | ||||||||||||||||||||||
| Average | Average | Average | ||||||||||||||||||||||
| Number of | Grant Date | Number of | Grant Date | Number of | Grant Date | |||||||||||||||||||
| UGI | Fair Value | UGI | Fair Value | UGI | Fair Value | |||||||||||||||||||
| Units | (per Unit) | Units | (per Unit) | Units | (per Unit) | |||||||||||||||||||
September 30, 2009 |
878,427 | $ | 23.89 | 535,582 | $ | 21.20 | 342,845 | $ | 28.09 | |||||||||||||||
UGI Performance Units: |
||||||||||||||||||||||||
Granted |
204,650 | $ | 22.51 | — | $ | — | 204,650 | $ | 22.51 | |||||||||||||||
Forfeited |
(5,227 | ) | $ | 25.85 | — | $ | — | (5,227 | ) | $ | 25.85 | |||||||||||||
Vested |
— | $ | — | 178,410 | $ | 26.60 | (178,410 | ) | $ | 26.60 | ||||||||||||||
Unit awards paid |
(174,417 | ) | $ | 27.04 | (174,417 | ) | $ | 27.04 | — | $ | — | |||||||||||||
Performance criteria not met |
— | $ | — | — | $ | — | — | $ | — | |||||||||||||||
UGI Stock Units: |
||||||||||||||||||||||||
Granted(a) |
27,060 | $ | 24.07 | — | $ | — | 27,060 | $ | 24.07 | |||||||||||||||
Vested |
— | $ | — | 31,260 | $ | 24.27 | (31,260 | ) | $ | 24.27 | ||||||||||||||
Unit awards paid |
— | $ | — | — | $ | — | — | $ | — | |||||||||||||||
September 30, 2010 |
930,493 | $ | 22.99 | 570,835 | $ | 21.27 | 359,658 | $ | 25.71 | |||||||||||||||
| (a) | Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in
shares. UGI Stock Unit awards granted in Fiscal 2009 and Fiscal 2008 were 52,767 and 37,732,
respectively. |
F-41
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 2010, Fiscal 2009 and Fiscal 2008, the Company paid UGI Performance Unit and UGI
Stock Unit awards in shares and cash as follows:
| 2010 | 2009 | 2008 | ||||||||||
UGI Performance Unit awards: |
||||||||||||
Number of original awards granted |
193,983 | 163,450 | 185,300 | |||||||||
Fiscal year granted |
2007 | 2006 | 2005 | |||||||||
Payment of awards: |
||||||||||||
Shares of UGI Common Stock issued |
123,169 | 117,847 | 0 | |||||||||
Cash paid |
$ | 2.6 | $ | 3.1 | $ | — | ||||||
UGI Stock Unit awards: |
||||||||||||
Number of original awards granted |
0 | 88,449 | 40,000 | |||||||||
Payment of awards: |
||||||||||||
Shares of UGI Common Stock issued |
0 | 58,376 | 20,000 | |||||||||
Cash paid |
$ | — | $ | 0.8 | $ | 0.6 | ||||||
During Fiscal 2010, Fiscal 2009 and Fiscal 2008, we granted UGI Unit awards representing
231,710, 269,017 and 253,325 shares, respectively, having weighted-average grant date fair values
per Unit of $22.69, $27.26 and $29.34, respectively.
As of September 30, 2010, there was a total of approximately $5.1 of unrecognized compensation
cost associated with 930,493 UGI Unit awards outstanding that is expected to be recognized over a
weighted-average period of 1.8 years. The total fair values of UGI Units that vested during Fiscal
2010, Fiscal 2009, and Fiscal 2008 were $5.0, $7.6 and $7.1, respectively. As of September 30, 2010
and 2009, total liabilities of $8.7 and $8.9, respectively, associated with UGI Unit awards are
reflected in “Other current liabilities” and “Other noncurrent liabilities” in the Consolidated
Balance Sheets.
At September 30, 2010, 4,076,522 shares of Common Stock were available for future grants under
the OECP, of which up to 1,687,347 may be issued pursuant to future grants other than stock options
or SARs.
AmeriGas Partners Equity-Based Compensation Plans and Awards. On July 30, 2010, holders of
AmeriGas Partners Common Units approved the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on
Behalf of AmeriGas Partners, L.P. (“2010 Propane Plan”). Under the 2010 Propane Plan, the General
Partner may award to employees and non-employee directors grants of Common Units, performance
units, options, phantom units, unit appreciation rights and other Common Unit-based awards. The
total aggregate number of Common Units that may be issued under the Plan is 2,800,000. The exercise
price for options may not be less than the fair market value on the date of grant. Awards granted
under the 2010 Propane Plan may vest immediately or ratably over a period of years, and options can
be exercised no later than ten years from the grant date. In addition, the 2010 Propane Plan
provides that Common Unit-based awards may also provide for the crediting of Common Unit
distribution equivalents to participants’ accounts.
The 2010 Propane Plan succeeds the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan (“2000
Propane Plan”) which expired on December 31, 2009, and replaces the AmeriGas Propane, Inc.
Discretionary Long-Term Incentive Plan for Non-Executive Key Employees (“Nonexecutive Propane
Plan”). Under the 2000 Propane Plan, the General Partner could award to key employees the right to
receive Common Units (comprising 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. Under the Nonexecutive Propane Plan, the
General Partner could grant awards to key employees who did not participate in the 2000 Propane
Plan. Generally, awards under the Nonexecutive Propane Plan vest at the end of a three-year period
and are paid in Common Units and cash. Effective January 1, 2010, no additional grants will be made
under the 2000 Propane Plan. Effective July 30, 2010, no additional grants will be made under the
Nonexecutive Propane Plan.
F-42
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)
Recipients of performance unit awards under the 2010 Propane Plan and, prior to its expiration
date, the 2000 Propane Plan (“AmeriGas Performance Units”) 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
AmeriGas Partners’ Total Unitholder Return (“TUR”) percentile rank relative to entities in a peer
group. Percentile rankings and payout percentages are generally the same as those used for the UGI
Performance Unit awards. Any Common Unit distribution equivalents earned are paid in cash.
Generally, except in the event of retirement, death or disability, 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.
Under GAAP, 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
values of AmeriGas Performance Units are estimated using a Monte Carlo valuation model. The fair
value associated with the target award and the award above the target, if any, which will be paid
in Common Units, is accounted for as equity and the fair value of all Common Unit distribution
equivalents, which will be paid in cash, 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 on the historical volatility of Common Units over a three-year period. The
risk-free interest rate is based on the rates on U.S. Treasury bonds at the time of grant.
Volatility for all 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 | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Risk-free rate |
1.7 | % | 1.0 | % | 3.1 | % | ||||||
Expected life |
3 years | 3 years | 3 years | |||||||||
Expected volatility |
35.0 | % | 32.0 | % | 17.7 | % | ||||||
Dividend yield |
6.8 | % | 9.1 | % | 6.8 | % | ||||||
The General Partner granted awards under the 2010 Propane Plan, the 2000 Propane Plan and the
Nonexecutive Propane Plan (collectively, “Awards”) representing 57,750, 60,200 and 40,050 Common
Units in Fiscal 2010, Fiscal 2009 and Fiscal 2008, respectively, having weighted-average grant date
fair values per Common Unit subject to award of $41.39, $31.94 and $37.91, respectively. At
September 30, 2010, 2,796,550 Common Units were available for future award grants under the 2010
Propane Plan.
The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2010:
| Total | Vested | Non-Vested | ||||||||||||||||||||||
| Number of | Number of | Number of | ||||||||||||||||||||||
| AmeriGas | AmeriGas | AmeriGas | ||||||||||||||||||||||
| Partners | Weighted | Partners | Weighted | Partners | Weighted | |||||||||||||||||||
| Common | Average | Common | Average | Common | Average | |||||||||||||||||||
| Units | Grant Date | Units | Grant Date | Units | Grant Date | |||||||||||||||||||
| Subject | Fair Value | Subject | Fair Value | Subject | Fair Value | |||||||||||||||||||
| to Award | (per Unit) | to Award | (per Unit) | to Award | (per Unit) | |||||||||||||||||||
September 30, 2009 |
147,600 | $ | 33.83 | 51,584 | $ | 33.49 | 96,016 | $ | 34.02 | |||||||||||||||
Granted |
57,750 | $ | 41.39 | — | $ | — | 57,750 | $ | 41.39 | |||||||||||||||
Forfeited |
(11,400 | ) | $ | 37.39 | — | $ | — | (11,400 | ) | $ | 37.39 | |||||||||||||
Vested |
— | $ | — | 49,617 | $ | 36.24 | (49,617 | ) | $ | 36.24 | ||||||||||||||
Awards paid |
(47,350 | ) | $ | 32.23 | (47,350 | ) | $ | 32.23 | — | $ | — | |||||||||||||
September 30, 2010 |
146,600 | $ | 37.05 | 53,851 | $ | 37.14 | 92,749 | $ | 37.00 | |||||||||||||||
F-43
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 2010, Fiscal 2009 and Fiscal 2008, the Partnership paid AmeriGas Common
Unit-based awards in Common Units and cash as follows:
| 2010 | 2009 | 2008 | ||||||||||
Number of Common Units subject to original Awards granted |
49,650 | 38,350 | 39,767 | |||||||||
Fiscal year granted |
2007 | 2006 | 2005 | |||||||||
Payment of Awards: |
||||||||||||
AmeriGas Partners Common Units issued |
42,121 | 36,437 | 21,249 | |||||||||
Cash paid |
$ | 1.2 | $ | 0.9 | $ | 0.8 | ||||||
As of September 30, 2010, there was a total of approximately $2.3 of unrecognized compensation
cost associated with 146,600 Common Units subject to award that is expected to be recognized over a
weighted-average period of 1.7 years. The total fair value of Common Unit-based awards that vested
during Fiscal 2010, Fiscal 2009 and Fiscal 2008 was $2.0, $1.6 and $2.1, respectively. As of
September 30, 2010 and 2009, total liabilities of $1.3 and $1.4 associated with Common Unit-based
awards are reflected in “Employee compensation and benefits accrued” and “Other noncurrent
liabilities” in the Consolidated Balance Sheets.
Note 14 — 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). When 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.
The Partnership has made quarterly distributions to Common Unitholders in excess of $0.605 per
limited partner unit beginning with the quarterly distribution paid May 18, 2007. As a result,
beginning with the quarterly distribution paid May 18, 2007 the General Partner has 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 aggregate 2% general partner ownership
interests totaled $6.9 in Fiscal 2010, $8.5 in Fiscal 2009 and $4.3 in Fiscal 2008. Included in
these amounts are incentive distributions received by the General Partner during Fiscal 2010,
Fiscal 2009 and Fiscal 2008 of $3.0, $4.5 and $0.7, respectively.
On July 27, 2009, the General Partner’s Board of Directors approved a distribution of $0.84
per Common Unit payable on August 18, 2009 to unitholders of record on August 10, 2009. This
distribution included the regular quarterly distribution of $0.67 per Common Unit and $0.17 per
Common Unit reflecting a distribution of a portion of the proceeds from the Partnership’s November
2008 sale of its California storage facility.
F-44
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 — Commitments and Contingencies
Commitments
We lease various buildings and other facilities and vehicles, 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 $70.6 in Fiscal 2010, $70.1
in Fiscal 2009 and $71.2 in Fiscal 2008.
Minimum future payments under operating leases that have initial or remaining noncancelable
terms in excess of one year are as follows:
| After | ||||||||||||||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2015 | 2015 | |||||||||||||||||||
AmeriGas Propane |
$ | 44.5 | $ | 34.9 | $ | 28.2 | $ | 20.9 | $ | 13.6 | $ | 15.0 | ||||||||||||
UGI Utilities |
4.7 | 4.2 | 3.6 | 2.5 | 1.7 | 3.6 | ||||||||||||||||||
International Propane |
6.3 | 2.8 | 1.9 | 0.3 | — | — | ||||||||||||||||||
Other |
1.9 | 1.8 | 1.5 | 1.2 | 0.9 | 1.1 | ||||||||||||||||||
Total |
$ | 57.4 | $ | 43.7 | $ | 35.2 | $ | 24.9 | $ | 16.2 | $ | 19.7 | ||||||||||||
Our 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 Fiscal 2022. Gas Utility’s costs associated with transportation and storage
capacity agreements are included in its annual PGC filings 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 electricity needs under contracts with various suppliers and on the
spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2014.
Midstream & Marketing enters into fixed-price contracts with suppliers to purchase natural gas and
electricity to meet its sales commitments. Generally, these contracts have terms of less than two
years. The Partnership enters into fixed-price and 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.
The following table presents contractual obligations under Gas Utility, Electric Utility,
Midstream & Marketing, AmeriGas Propane and International Propane supply, storage and service
contracts existing at September 30, 2010:
| After | ||||||||||||||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2015 | 2016 | |||||||||||||||||||
Gas Utility and Electric Utility supply,
storage and transportation contracts |
$ | 225.2 | $ | 104.9 | $ | 85.3 | $ | 60.4 | $ | 32.4 | $ | 90.2 | ||||||||||||
Midstream & Marketing supply contracts |
277.7 | 100.5 | 13.4 | — | — | — | ||||||||||||||||||
AmeriGas Propane supply contracts |
50.5 | — | — | — | — | — | ||||||||||||||||||
International Propane supply contracts |
5.4 | — | — | — | — | — | ||||||||||||||||||
Total |
$ | 558.8 | $ | 205.4 | $ | 98.7 | $ | 60.4 | $ | 32.4 | $ | 90.2 | ||||||||||||
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 price and quantity adjustments.
In addition, we have committed to invest upon request a total of up to an additional $9.6 in a
limited partnership that focuses on investments in the alternative energy sector.
F-45
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)
Contingencies
Environmental Matters
CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of
Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities
associated with environmental investigation and remediation work at certain properties in
Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP
Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition,
PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP.
The PNG-COA requires PNG to perform annually a specified level of activities associated with
environmental investigation and remediation work at certain properties on which MGP-related
facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures
relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1,
respectively, in any calendar year. The CPG-COA terminates at the end of 2011 for the MGP
Properties and at the end of 2013 for well plugging activities. The PNG-COA 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 in March 2004. At September 30, 2010 and 2009, our accrued liabilities for
environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled
$21.4 and $25.0, respectively. In accordance with GAAP related to rate-regulated entities, we have
recorded associated regulatory assets in equal amounts.
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, by the early 1950s
UGI Utilities divested all of its utility operations other than certain Pennsylvania operations,
including those which now constitute UGI Gas and Electric Utility.
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. At September 30, 2010, neither the undiscounted nor
the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.
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 three claims against it relating
to out-of-state sites.
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 through control
of a subsidiary that owned the plant UGI Utilities controlled operations of the plant from 1910 to
1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserts that
it has spent approximately $22 in remediation costs and paid $26 in third-party claims relating to
the site and estimates that future response costs, including a claim by the United States Justice
Department for natural resource damages, could be as high as $14. Trial took place in March 2009
and the court’s decision is pending.
F-46
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)
Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens
Communications Company, now known as Frontier Communications Company (“Frontier”), 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 City of Bangor, Maine (“City”)
sued Frontier to recover environmental response costs associated with MGP wastes generated at a
plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River. Frontier
subsequently joined UGI Utilities and ten other third-party defendants alleging that the
third-party defendants are responsible for an equitable share of any costs Frontier would be
required to pay to the City for cleaning up tar deposits in the Penobscot River. Frontier alleged
that through ownership and control of a subsidiary, Bangor Gas Light Company, UGI Utilities and its
predecessors owned and operated the plant from 1901 to 1928. Frontier made similar allegations of
control against another third-party defendant, CenterPoint Energy Resources Corporation
(“CenterPoint”), whose predecessor owned the Bangor subsidiary from 1928 to 1944. Frontier’s
third-party claims were stayed pending a resolution of the City’s suit against Frontier, which was
tried in September 2005. On June 27, 2006, the court issued an order finding Frontier responsible
for 60% of the cleanup costs, which were estimated at $18. On February 14, 2007, Frontier and the
City entered into a settlement agreement pursuant to which Frontier agreed to pay $7.6. Frontier
subsequently filed the current action against the original third-party defendants, repeating its
claims for contribution. On September 22, 2009, the court granted summary judgment in favor of
co-defendant CenterPoint. UGI Utilities believes that it also has good defenses and has filed a
motion for summary judgment with respect to Frontier’s claims. The court referred the motion to a
magistrate judge for findings and a recommendation. On October 19, 2010, the magistrate judge
entered an order recommending that the court grant UGI Utilities’ motion.
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 through control of former subsidiaries that owned the MGPs. The
Northeast Companies estimated that remediation costs for all of the sites could total approximately
$215 and asserted that UGI Utilities is responsible for approximately $103 of this amount. The
Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI
Utilities acknowledged that it had operated one of the sites, Waterbury North, pursuant to a lease.
In April 2009, the court conducted a trial to determine whether UGI Utilities operated any of the
nine remaining sites that were owned and operated by former subsidiaries. On May 22, 2009, the
court granted judgment in favor of UGI Utilities with respect to all nine sites. The Northeast
Companies have appealed the decision. With respect to Waterbury North, the Northeast Companies are
expected to complete additional environmental investigations by the end of 2010, after which there
will be a second phase of the trial to determine what, if any, contamination at Waterbury North is
related to UGI Utilities’ period of operation. The Northeast Companies previously estimated that
remediation costs at Waterbury North could total $25.
AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of
Environmental Conservation (“DEC”) notified AmeriGas OLP that DEC had placed property owned by the
Partnership in Saranac Lake, New York on its Registry of Inactive Hazardous Waste Disposal Sites. A
site characterization study performed by DEC disclosed contamination related to former MGP
operations on the site. DEC has classified the site as a significant threat to public health or
environment with further action required. The Partnership has researched the history of the site
and its ownership interest in the site. The Partnership has reviewed the preliminary site
characterization study prepared by the DEC, the extent of contamination and the possible existence
of other potentially responsible parties. The Partnership has communicated the results of its
research to DEC and is awaiting a response before doing any additional investigation. Because of
the preliminary nature of available environmental information, the ultimate amount of expected
clean up costs cannot be reasonably estimated.
F-47
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)
Other Matters
Purported AmeriGas Class Action Lawsuits. On May 27, 2009, the General Partner was named as a
defendant in a purported class action lawsuit in the Superior Court of the State of California in
which plaintiffs are challenging AmeriGas OLP’s weight disclosure with regard to its portable
propane grill cylinders. The complaint purports to be brought on behalf of a class of all consumers
in the state of California during the four years prior to the date of the California complaint, who
exchanged an empty cylinder and were provided with what is alleged to be only a partially filled
cylinder. The plaintiffs seek restitution, injunctive relief, interest, costs, attorneys’ fees and
other appropriate relief.
Since that initial suit, various AmeriGas entities have been named in more than a dozen
similar suits that have been filed in various courts throughout the United States. These complaints
purport to be brought on behalf of nationwide classes, which are loosely defined as including all
purchasers of liquefied propane gas cylinders marketed or sold by AmeriGas OLP and another
unaffiliated entity nationwide. The complaints claim that defendants’ conduct constituted unfair
and deceptive practices that injured consumers and violated the consumer protection statutes of at
least thirty-seven states and the District of Columbia, thereby entitling the class to damages,
restitution, disgorgement, injunctive relief, costs and attorneys’ fees. Some of the complaints
also allege violation of state “slack filling” laws. Additionally, the complaints allege that
defendants were unjustly enriched by their conduct and they seek restitution of any unjust benefits
received, punitive or treble damages, and pre-judgment and post-judgment interest. A motion to
consolidate the purported class action lawsuits was heard by the Multidistrict Litigation Panel
(“MDL Panel”) on September 24, 2009 in the United States District Court for the District of Kansas.
By Order, dated October 6, 2009, the MDL Panel transferred the pending cases to the United States
District Court for the Western District of Missouri. The AmeriGas entities named in the
consolidated class action lawsuits have entered into a settlement agreement with the class. On
May 19, 2010, the United States District Court for the District of Kansas granted the classes’
motion seeking preliminary approval of the settlement. On October 4, 2010, the District Court ruled
that the settlement was fair, reasonable and adequate to the class and granted final approval of
the settlement.
AmeriGas Cylinder Investigations. On or about October 21, 2009, the General Partner received a
notice that the Offices of the District Attorneys of Santa Clara, Sonoma, Ventura, San Joaquin and
Fresno Counties and the City Attorney of San Diego have commenced an investigation into AmeriGas
OLP’s cylinder labeling and filling
practices in California and issued an administrative subpoena seeking documents and information
relating to these practices. We are cooperating with these California governmental investigations.
Swiger, et al. v. UGI/AmeriGas, Inc. et al. 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 Corporation in August 2001 as
additional potential class member and the plaintiffs amended their
complaint to name additional parties pursuant to such ruling.
Subsequently, in March 2005 AmeriGas OLP filed a crossclaim against
Columbia Energy Group, former owner of Columbia Propane Corporation,
seeking indemnification for conduct undertaken by Columbia Propane
Corporation prior to AmeriGas OLP’s acquisition. In June 2010,
Columbia Energy Group filed a complaint in the Delaware Court of
Chancery seeking to enjoin AmeriGas OLP from pursuing its
cross-claims in the West Virginia litigation and asking the court to
find that AmeriGas OLP’s cross-claims are without merit and barred.
Class counsel has indicated that the class is seeking compensatory
damages in excess of $12 plus punitive damages, civil penalties
and attorneys’ fees. The Circuit Court of Monongalia County has
tentatively scheduled a trial for the class action for
the Spring of 2011.
In 2005, the Swigers also filed what purports to be a class action in the Circuit Court of
Harrison County, West Virginia against UGI, an insurance subsidiary of UGI, certain officers of UGI
and the General Partner, and their insurance carriers and insurance adjusters. In the Harrison
County lawsuit, the Swigers are seeking compensatory and punitive damages on behalf of the putative
class for violations of the West Virginia Insurance Unfair Trade Practice Act, negligence,
intentional misconduct and civil conspiracy. The Swigers have also requested that the Court rule
that insurance coverage exists under the policies issued by the defendant insurance companies for
damages sustained by the members of the class in the Monongalia County lawsuit. The Circuit Court
of Harrison County has not certified the class in the Harrison County lawsuit at this time and, in
October 2008, stayed that lawsuit pending resolution of the class action lawsuit in Monongalia
County. We believe we have good defenses to the claims in their actions.
F-48
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)
French Business Tax. 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. Antargaz has recorded liabilities for business taxes related to
various classes of equipment. 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.
Antargaz Competition Authority Matter. On July 21, 2009, Antargaz received a Statement of
Objections from France’s Autorité de la concurrence (“Competition Authority”) with respect to the
investigation of Antargaz by the General Division of Competition, Consumption and Fraud Punishment
(“DGCCRF”). A Statement of Objections (“Statement”) is part of French competition proceedings and
generally follows an investigation under French competition laws. The Statement sets forth the
Competition Authority’s findings; it is not a judgment or final decision. The Statement alleges
that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through
2004. The alleged violations occurred principally during periods prior to March 31, 2004, when UGI
first obtained a controlling interest in Antargaz. Based on an assessment of the information
contained in the Statement, during the quarter ended June 30, 2009 we recorded a provision of $10.0
(€7.1) related to this matter which amount is reflected in “Other income, net” on the Fiscal
2009 Consolidated Statement of Income.
We filed our written response to the Statement of Objections with the Competition Authority on
October 21, 2009. The Competition Authority completed its review of Antargaz’ response and issued
its report on April 26, 2010. Antargaz filed its response to this report on June 28, 2010. A
hearing before the Competition Authority was held on September 21, 2010 and a decision is not
expected before the end of 2010. Based on our assessment of the information contained in the report
and the hearing, we believe that we have good defenses to the objections and that the reserve
established by management for this matter is adequate. However, the final resolution could result
in payment of an amount significantly different from the amount we have recorded.
We cannot predict with certainty the final results of any of the environmental or other
pending claims or legal actions described above. 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. In addition to the matters described above, there are
other pending claims and legal actions arising in the normal course of our businesses. While the
results of these other pending claims and legal actions cannot be predicted with certainty, we
believe, after consultation with counsel, the final outcome of such other matters will not have a
significant effect on our consolidated financial position, results of operations or cash flows.
F-49
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 16 — Fair Value Measurements
Derivative Financial Instruments
The following table presents our financial assets and financial liabilities that are measured
at fair value on a recurring basis for each of the fair value hierarchy levels, including both
current and noncurrent portions, as of September 30, 2010 and 2009:
| Asset (Liability) | ||||||||||||||||
| Quoted Prices | ||||||||||||||||
| in Active | Significant | |||||||||||||||
| Markets for | Other | |||||||||||||||
| Identical Assets | Observable | Unobservable | ||||||||||||||
| and Liabilities | Inputs | Inputs | ||||||||||||||
| (Level 1) | (Level 2) | (Level 3) | Total | |||||||||||||
September 30, 2010: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | 1.1 | $ | 10.7 | $ | — | $ | 11.8 | ||||||||
Foreign currency contracts |
$ | — | $ | 0.8 | $ | — | $ | 0.8 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | (49.4 | ) | $ | (20.3 | ) | $ | — | $ | (69.7 | ) | |||||
Foreign currency contracts |
$ | — | $ | (2.9 | ) | $ | — | $ | (2.9 | ) | ||||||
Interest rate contracts |
$ | — | $ | (18.5 | ) | $ | — | $ | (18.5 | ) | ||||||
September 30, 2009: |
||||||||||||||||
Assets: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | 2.0 | $ | 16.6 | $ | — | $ | 18.6 | ||||||||
Interest rate contracts |
$ | — | $ | 2.2 | $ | — | $ | 2.2 | ||||||||
Liabilities: |
||||||||||||||||
Derivative financial instruments: |
||||||||||||||||
Commodity contracts |
$ | (5.8 | ) | $ | (1.4 | ) | $ | — | $ | (7.2 | ) | |||||
Foreign currency contracts |
$ | — | $ | (5.7 | ) | $ | — | $ | (5.7 | ) | ||||||
Interest rate contracts |
$ | — | $ | (36.6 | ) | $ | — | $ | (36.6 | ) | ||||||
The fair values of our Level 1 exchange-traded commodity futures and option contracts and non
exchange-traded commodity futures and forward contracts are based upon actively-quoted market
prices for identical assets and liabilities. The remainder of our derivative financial instruments
are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives are
based upon indicative price quotations available through brokers, industry price publications or
recent market transactions and related market indicators. For commodity option contracts not
traded on an exchange, we use a Black Scholes option pricing model that considers time value and
volatility of the underlying commodity. The fair values of interest rate contracts and foreign
currency contracts are based upon third-party quotes or indicative values based on recent market
transactions.
Other Financial Instruments
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 amount and
estimated fair value of our long-term debt at September 30, 2010 were $2,005.8 and $2,144.7,
respectively. The carrying amount and estimated fair value of our long-term debt at September 30,
2009 were $2,133.1 and $2,170.3, respectively. We estimate the fair value of long-term debt by
using current market rates and by discounting future cash flows using rates available for similar
type debt.
Financial instruments
other than derivative financial instruments, such as our short-term
investments and trade accounts receivable, 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, securities guaranteed by the U.S. Government or its agencies and
FDIC insured bank deposits. 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.
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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 17 — Disclosures About Derivative Instruments and Hedging Activities
We are exposed to certain market risks related to our ongoing business operations. Management
uses derivative financial and commodity instruments, among other things, to manage these risks. The
primary risks managed by derivative instruments are (1) commodity price risk, (2) interest rate
risk and (3) foreign currency exchange rate risk. Although we use derivative financial and
commodity instruments to reduce market risk associated with forecasted transactions, we do not use
derivative financial and commodity instruments for speculative or trading purposes. The use of
derivative instruments is controlled by our risk management and credit policies which govern, among
other things, the derivative instruments we can use, counterparty credit limits and contract
authorization limits. Because our derivative instruments, other than FTRs and gasoline futures and
swap contracts (as further described below), generally qualify as hedges under GAAP or are subject
to regulatory rate recovery mechanisms, we expect that changes in the fair value of derivative
instruments used to manage commodity, interest rate or currency exchange rate risk would be
substantially offset by gains or losses on the associated anticipated transactions.
Commodity Price Risk
In order to manage market price risk associated with the Partnership’s fixed-price programs
which permit customers to lock in the prices they pay for propane principally during the months of
October through March, the Partnership uses over-the-counter derivative commodity instruments,
principally price swap contracts. Certain other domestic business units and our International
Propane operations also use over-the-counter price swap and option contracts to reduce commodity
price volatility associated with a portion of their forecasted LPG purchases. In addition, the
Partnership enters into price swap agreements to provide market price risk support to a limited
number of its wholesale customers. These agreements are not designated as hedges for accounting
purposes. The volume of propane subject to these wholesale customer agreements at September 30,
2010 and 2009 were not material.
Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred
costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the
PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile
Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility
associated with a portion of the natural gas it purchases for its retail core-market customers. At
September 30, 2010 the volumes of natural gas associated with Gas Utility’s unsettled NYMEX
natural gas futures and option contracts totaled 19.5 million dekatherms and the maximum period
over which Gas Utility is hedging natural gas market price risk is 12 months. At September 30, 2009,
there were no unsettled NYMEX natural gas futures or option contracts outstanding. Gains and
losses on natural gas futures contracts and any gains on natural gas option contracts are recorded
in regulatory assets or liabilities on the Consolidated Balance Sheets in accordance with FASB’s
guidance in ASC 980 related to rate-regulated entities and reflected in cost of sales through the
PGC mechanism (see Note 8).
Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently
incurred costs of electricity it sells to DS customers. Electric Utility enters into forward
electricity purchase contracts to meet a substantial portion of its electricity supply needs.
During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take
physical delivery of substantially all of the electricity it had contracted for under its forward
power purchase agreements and, as a result, such contracts no longer qualified for the normal
purchases and normal sales exception under GAAP related to derivative financial instruments. The
inability of Electric Utility to continue to assert that it would take physical delivery of such
power resulted principally from a greater than anticipated number of customers, primarily certain
commercial and industrial customers, choosing an alternative electricity supplier. Because these
contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the
fair value of these contracts are required to be recognized on the balance sheet and measured at
fair value. At September 30, 2010, the fair values of Electric Utility’s forward purchase power
agreements comprising a loss of $19.7 are reflected in current derivative financial instrument
liabilities and other noncurrent liabilities in the accompanying September 30, 2010 Consolidated
Balance Sheet. In accordance with ASC 980 related to rate regulated entities, Electric Utility has
recorded equal and offsetting amounts in regulatory assets. At September 30,
2010, the volumes of Electric Utility’s forward electricity purchase contracts was 990.7
million kilowatt hours and the maximum period over which these contracts extend is 43 months.
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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 order to reduce volatility associated with a substantial portion of its electricity
transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection
(“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Midstream & Marketing
purchases FTRs to economically hedge electricity transmission congestion costs associated with its
fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the
holder to receive compensation for electricity transmission congestion charges that result when
there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a
regional transmission organization that coordinates the movement of wholesale electricity in all or
parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover
its DS costs commencing January 1, 2010 pursuant to the January 22, 2009 settlement of its DS
filing with the PUC, gains and losses on Electric Utility FTRs associated with periods beginning on
or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC
980 and reflected in cost of sales through the DS recovery mechanism (see Note 8). Gains and losses
associated with periods prior to January 2010 are reflected in cost of sales. At September 30, 2010
and 2009, the volumes associated with Electric Utility FTRs totaled 546.8 million kilowatt hours
and 1,009.0 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair
value with changes in fair value reflected in cost of sales. At September 30, 2010 and 2009, the
volumes associated with Midstream & Marketing’s FTRs totaled 1,026.4 million kilowatt hours and
729.0 million kilowatt hours, respectively.
In order to manage market price risk relating to fixed-price sales contracts for natural gas
and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas and
electricity futures contracts.
In order to reduce operating expense volatility, UGI Utilities from time to time enters into
NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in
the operation of its vehicles and equipment. Associated volumes, fair values and effects on net
income were not material for all periods presented.
At September 30, 2010 and 2009, we had the following outstanding derivative commodity
instruments volumes that qualify for hedge accounting treatment:
| Volumes | ||||||||
| Commodity | 2010 | 2009 | ||||||
LPG (millions of gallons) |
160.0 | 152.8 | ||||||
Natural gas (millions of dekatherms) |
36.3 | 21.8 | ||||||
Electricity
(millions of kilowatt hours) |
1,203.8 | 372.0 | ||||||
At September 30, 2010, the maximum period over which we are hedging our exposure to the
variability in cash flows associated with LPG commodity price risk is 24 months with a weighted
average of 5 months; the maximum period over which we are hedging our exposure to the variability
in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 36 months
with a weighted average of 7 months; and the maximum period over which we are hedging our exposure
to the variability in cash flows associated with electricity price risk (excluding Electric
Utility) is 28 months with a weighted average of 10 months. At September 30, 2010, the maximum
period over which we are economically hedging electricity congestion
with FTRs (excluding Electric
Utility) is 8 months with a weighted average of 4 months.
We account for commodity price risk contracts (other than our Gas Utility natural gas futures
and option contracts, Electric Utility electricity forward contracts, gasoline futures and swap
contracts, and FTRs) as cash flow hedges. Changes in the fair values of contracts qualifying for
cash flow hedge accounting are recorded in AOCI and, with respect to the Partnership,
noncontrolling interests, to the extent effective in offsetting changes in the underlying
commodity price risk. When earnings are affected by the hedged commodity, gains or losses are
recorded in cost of sales on the Consolidated Statements of Income. At September 30, 2010, the
amount of net losses associated with commodity price risk hedges expected to be reclassified into
earnings during the next twelve months based upon current fair values is $46.1.
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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)
Interest Rate Risk
Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally
indexed to short-term market interest rates. Antargaz has effectively fixed the underlying euribor
interest rate on its €380 variable-rate debt through its March 2011 maturity date through the
use of pay-fixed, receive-variable interest rate swap agreements. Antargaz intends to refinance
its €380 variable-rate term loan on a long-term basis by March 2011. In anticipation of such
refinancing, during Fiscal 2010 Antargaz entered into forward-starting interest rate swap
agreements to hedge the underlying euribor rate of interest relating to 4 1/2 years of quarterly
interest payments on €300 notional amount of long-term debt commencing March 31, 2011. Flaga
has also fixed the underlying euribor interest rate on a substantial portion of its two term loans
through their scheduled maturity dates ending in 2014 through the use of pay-fixed,
receive-variable interest rate swap agreements. As of September 30, 2010 and 2009, the total
notional amounts of our existing and anticipated variable-rate debt subject to interest rate swap
agreements were €703.2 and €410.6, respectively.
Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As
these long-term debt issues mature, we typically refinance such debt with new debt having interest
rates reflecting then-current market conditions. In order to reduce market rate risk on the
underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of
fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”).
There were no unsettled IRPAs outstanding at September 30, 2010. At September 30, 2009, the total
notional amount of unsettled IRPAs was $150.
We account for interest rate swaps and IRPAs as cash flow hedges. Changes in the fair values
of interest rate swaps and IRPAs are recorded in AOCI and, with respect to the Partnership,
noncontrolling interests, to the extent effective in offsetting changes in the underlying interest
rate risk, until earnings are affected by the hedged interest expense. At such time, gains and
losses are recorded in interest expense. At September 30, 2010, the amount of net losses
associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps)
expected to be reclassified into earnings during the next twelve months is $1.7.
Foreign Currency Exchange Rate Risk
In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S.
dollar-denominated LPG product purchases through the use of forward foreign currency exchange
contracts. The amount of dollar-denominated purchases of LPG associated with such contracts
generally represents approximately 20% to 30% of estimated dollar-denominated purchases of LPG to occur
during the heating-season months of October through March. At September 30, 2010 and 2009, we were
hedging a total of $108.6 and $131.5 of U.S. dollar-denominated LPG purchases, respectively. At
September 30, 2010, the maximum period over which we are hedging our exposure to the variability
in cash flows associated with dollar-denominated purchases of LPG is 29 months with a weighted
average of 12 months. We also enter into forward foreign currency exchange contracts to reduce
the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated
net investments. At September 30, 2010 and 2009, we were hedging a total of €10.0 and €30.8,
respectively, of our euro-denominated net investments. As of September 30, 2010, such foreign
currency contracts extend through March 2013.
We account for foreign currency exchange contracts associated with anticipated purchases of
U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign
currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in
the underlying currency exchange rate risk, until earnings are affected by the hedged LPG
purchase, at which time gains and losses are recorded in cost of sales. At September 30, 2010, the
amount of net losses associated with currency rate risk (other than net investment hedges)
expected to be reclassified into earnings during the next twelve months based upon current fair
values is $1.0. Gains and losses on net investment hedges are included in AOCI until such foreign
operations are liquidated.
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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)
Derivative Financial Instrument Credit Risk
We are exposed to risk of loss in the event of nonperformance by our derivative financial
instrument counterparties. Our derivative financial instrument counterparties principally comprise
major energy companies and major U.S. and international financial institutions. We maintain credit
policies with regard to our counterparties that we believe reduce overall credit risk. These
policies include evaluating and monitoring our counterparties’ financial condition, including
their credit ratings, and entering into agreements with counterparties that govern credit limits.
Certain of these agreements call for the posting of collateral by the counterparty or by the
Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural
gas and electricity exchange-traded futures contracts which are guaranteed by the NYMEX generally
require cash deposits in margin accounts. At September 30, 2010 and 2009, restricted cash in
brokerage accounts totaled $34.8 and $7.0, respectively. Although we have concentrations of credit
risk associated with derivative financial instruments, the maximum amount of loss, based upon the
gross fair values of the derivative financial instruments, we would incur if these counterparties
failed to perform according to the terms of their contracts was not material at September 30,
2010. We generally do not have credit-risk-related contingent features in our derivative
contracts.
The following table provides information regarding the balance sheet location and fair value
of derivative assets and liabilities existing as of September 30, 2010 and 2009:
| Derivative Assets | Derivative Liabilities | |||||||||||||||||||
| Fair Value | Fair Value | |||||||||||||||||||
| Balance Sheet | September 30, | Balance Sheet | September 30, | |||||||||||||||||
| Location | 2010 | 2009 | Location | 2010 | 2009 | |||||||||||||||
Derivatives
Designated as
Hedging Instruments: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments and Other assets | $ | 9.2 | $ | 15.6 | Derivative financial instruments and Other noncurrent liabilities | $ | (48.6 | ) | $ | (7.2 | ) | ||||||||
Foreign currency
contracts |
Other assets | 0.8 | — | Derivative financial instruments and Other noncurrent liabilities | (2.9 | ) | (5.7 | ) | ||||||||||||
Interest rate contracts |
Derivative financial instruments | — | 2.2 | Derivative financial instruments and Other noncurrent liabilities | (18.5 | ) | (36.6 | ) | ||||||||||||
Total Derivatives
Designated
as Hedging Instruments |
$ | 10.0 | $ | 17.8 | $ | (70.0 | ) | $ | (49.5 | ) | ||||||||||
Derivatives Accounted for
Under ASC 980: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments | $ | 0.4 | $ | 3.0 | Derivative financial instruments and Other noncurrent liabilities | $ | (21.1 | ) | $ | — | |||||||||
Derivatives Not Designated
as Hedging Instruments: |
||||||||||||||||||||
Commodity contracts |
Derivative financial instruments and Other assets | $ | 2.2 | $ | — | |||||||||||||||
Total Derivatives |
$ | 12.6 | $ | 20.8 | $ | (91.1 | ) | $ | (49.5 | ) | ||||||||||
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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 tables provide information on the effects of derivative instruments on the
Consolidated Statement of Income and changes in AOCI and noncontrolling interest for Fiscal 2010
and 2009:
| Gain or (Loss) | Gain or (Loss) | Location of | ||||||||||||||||||
| Recognized in | Reclassified from | Gain or (Loss) | ||||||||||||||||||
| AOCI and | AOCI and Noncontrolling | Reclassified from | ||||||||||||||||||
| Noncontrolling Interests | Interests into Income | AOCI and Noncontrolling | ||||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | Interests into Income | ||||||||||||||||
Cash Flow Hedges: |
||||||||||||||||||||
Commodity contracts |
$ | (41.7 | ) | $ | (241.1 | ) | $ | (21.0 | ) | $ | (305.8 | ) | Cost of sales | |||||||
Foreign currency contracts |
3.2 | (2.1 | ) | 0.7 | 5.0 | Cost of sales | ||||||||||||||
Interest rate contracts |
(12.6 | ) | (46.7 | ) | (28.2 | ) | (7.0 | ) | Interest expense /other income | |||||||||||
Total |
$ | (51.1 | ) | $ | (289.9 | ) | $ | (48.5 | ) | $ | (307.8 | ) | ||||||||
Net Investment Hedges: |
||||||||||||||||||||
Foreign currency contracts |
$ | 5.0 | $ | (2.0 | ) | |||||||||||||||
| Gain or (Loss) | ||||||||||||
| Recognized in Income | Location of Gain or (Loss) | |||||||||||
| 2010 | 2009 | Recognized in Income | ||||||||||
Derivatives Not Designated
as Hedging Instruments: |
||||||||||||
Commodity contracts |
$ | 1.3 | $ | (0.6 | ) | Cost of sales | ||||||
Commodity contracts |
0.2 | 0.7 | Operating expenses / other income | |||||||||
Total |
$ | 1.5 | $ | 0.1 | ||||||||
The amounts of derivative gains or losses representing ineffectiveness, and the amounts of
gains or losses recognized in income as a result of excluding derivatives from ineffectiveness
testing, were not material for Fiscal 2010, Fiscal 2009 and Fiscal 2008. During the three months
ended March 31, 2010, the Partnership’s management determined that it was likely that the
Partnership would not issue $150 of long-term debt during the summer of 2010 due to the
Partnership’s strong cash flow and anticipated extension of all or a portion of the 2009 AmeriGas
Supplemental Credit Agreement. As a result, the Partnership discontinued cash flow hedge accounting
treatment for IRPAs associated with this previously anticipated Fiscal 2010 $150 long-term debt
issuance and recorded a $12.2 loss which is reflected in other income, net on the Fiscal 2010
Consolidated Statement of Income. During Fiscal 2009, the Partnership recorded a loss of $1.7 as a
result of the discontinuance of cash flow hedge accounting associated with IRPAs which amount was
also reflected in other income, net.
We are also a party to a number of other contracts that have elements of a derivative
instrument. These contracts include, among others, binding purchase orders, contracts which
provide for the purchase and delivery, or sale, of natural gas, LPG 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 qualify for normal purchases and normal sales
exception accounting under GAAP 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 and the price in the
contract is based on an underlying that is directly associated with the price of the product or
service being purchased or sold.
Note 18 — Energy Services Accounts Receivable Securitization Facility
Energy Services has a $200 receivables purchase facility (“Receivables Facility”) with an
issuer of receivables-backed commercial paper currently scheduled to expire in April 2011, although
the Receivables Facility may terminate prior to such date due to the termination of commitments of
the Receivables Facility’s back-up purchasers.
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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, Energy Services 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 Energy Services and its
affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables
following the FASB’s guidance for accounting for transfers of financial assets and extinguishments
of liabilities. Energy Services continues to service, administer and collect trade receivables on
behalf of the commercial paper issuer and ESFC.
During Fiscal 2010, Fiscal 2009 and Fiscal 2008, Energy Services sold trade receivables
totaling $1,147.3, $1,247.1 and $1,496.2, respectively, to ESFC. During Fiscal 2010, Fiscal 2009
and Fiscal 2008, ESFC sold an aggregate $254.6, $596.9 and $251.5, respectively, of undivided
interests in its trade receivables to the commercial paper conduit. At September 30, 2010, the
outstanding balance of ESFC trade receivables was $44.0 which is net of $12.1 that was sold to the
commercial paper conduit and removed from the balance sheet. At September 30, 2009, the outstanding
balance of ESFC trade receivables was $38.2 which is net of $31.3 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 2010, Fiscal 2009 and Fiscal 2008, which are included in
“Other income, net,” were $1.5, $2.3 and $0.9, respectively.
Effective October 1, 2010, the Company adopted a new accounting standard that changes the
accounting for the Receivables Facility. For information on the effects of the change, see Note 3.
Note 19 — Other Income, Net
Other income, net, comprises the following:
| 2010 | 2009 | 2008 | ||||||||||
Interest and interest-related income |
$ | 2.9 | $ | 5.0 | $ | 11.6 | ||||||
Antargaz Competition Authority Matter |
— | (10.0 | ) | — | ||||||||
Utility non-tariff service income |
2.4 | 3.2 | 6.2 | |||||||||
Gain on sale of Partnership LPG storage facility |
— | 39.9 | — | |||||||||
Gain on sale of Atlantic Energy, LLC |
36.5 | — | — | |||||||||
Finance charges |
11.3 | 11.7 | 11.8 | |||||||||
Partnership interest rate protection agreement losses |
(12.2 | ) | (1.7 | ) | — | |||||||
Other, net |
17.1 | 7.8 | 12.0 | |||||||||
Total other income, net |
$ | 58.0 | $ | 55.9 | $ | 41.6 | ||||||
Note 20 — Quarterly Data (unaudited)
The following unaudited quarterly data includes adjustments (consisting only of normal
recurring adjustments with the exception of those indicated below) which we consider necessary for
a fair presentation unless otherwise indicated. Our quarterly results fluctuate because of the
seasonal nature of our businesses.
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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)
| December 31, | March 31, | June 30, | September 30, | |||||||||||||||||||||||||||||
| 2009 | 2008 (a) | 2010 (b) | 2009 | 2010 | 2009 (c) | 2010 (d) | 2009 | |||||||||||||||||||||||||
Revenues |
$ | 1,618.8 | $ | 1,778.5 | $ | 2,120.3 | $ | 2,137.8 | $ | 961.9 | $ | 962.2 | $ | 890.4 | $ | 859.3 | ||||||||||||||||
Operating income (loss) |
$ | 243.2 | $ | 289.4 | $ | 366.0 | $ | 374.8 | $ | 31.2 | $ | 28.8 | $ | 18.8 | $ | (7.7 | ) | |||||||||||||||
Loss from equity investees |
$ | — | $ | (0.2 | ) | $ | — | $ | (0.6 | ) | $ | (1.9 | ) | $ | — | $ | (0.2 | ) | $ | (2.3 | ) | |||||||||||
Net income (loss) |
$ | 145.5 | $ | 183.9 | $ | 232.8 | $ | 241.8 | $ | (4.2 | ) | $ | (12.2 | ) | $ | (18.4 | ) | $ | (31.5 | ) | ||||||||||||
Net income (loss)
attributable to UGI Corporation |
$ | 98.4 | $ | 114.9 | $ | 157.1 | $ | 158.2 | $ | 3.4 | $ | (3.6 | ) | $ | 2.1 | $ | (11.0 | ) | ||||||||||||||
Earnings (loss) per share
attributable to UGI
stockholders: |
||||||||||||||||||||||||||||||||
Basic |
$ | 0.90 | $ | 1.06 | $ | 1.44 | $ | 1.46 | $ | 0.03 | $ | (0.03 | ) | $ | 0.02 | $ | (0.10 | ) | ||||||||||||||
Diluted |
$ | 0.90 | $ | 1.05 | $ | 1.43 | $ | 1.45 | $ | 0.03 | $ | (0.03 | ) | $ | 0.02 | $ | (0.10 | ) | ||||||||||||||
| (a) | Includes a gain from the sale of the Partnership’s California storage facility which
increased operating income by $39.9 and net income attributable to UGI Corporation by $10.4 or
$0.10 per diluted share (see Note 4). |
|
| (b) | Includes loss from discontinuance of cash flow hedge accounting treatment for Partnership
IRPAs which decreased operating income by $12.2 and net income attributable to UGI Corporation
by $3.3 or $0.03 per diluted share (see Note 17). |
|
| (c) | Includes a provision for the Antargaz Competition Authority Matter which decreased operating
income by $10.0 and increased net loss attributable to UGI Corporation by $10.0 or $0.10 per
share (see Note 15). |
|
| (d) | Includes a gain from the sale of Atlantic Energy, LLC which increased operating income by
$36.5 and net income attributable to UGI Corporation by $17.2 or $0.16 per diluted share (see
Note 4). |
Note 21 — 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 other international propane
businesses other than Antargaz (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Midstream
& Marketing. 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 in all 50 states. Our International Propane segments’
revenues are derived principally from the distribution of LPG to retail customers in France and, to
a much lesser extent, northern, central and eastern Europe including Austria and Denmark. Gas
Utility’s revenues are derived principally from the sale and distribution of natural gas to
customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues
principally from the distribution of electricity in two northeastern Pennsylvania counties.
Midstream & Marketing 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 Mid-Atlantic region of the
United States.
The accounting policies of our reportable segments are the same as those described in Note 2.
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. Our 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 Midstream & Marketing segments principally based upon their income 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-57
Table of Contents
UGI Corporation
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)
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| Elim- | AmeriGas | Gas | Electric | Midstream | International Propane | Corporate | ||||||||||||||||||||||||||||||
| Total | inations | Propane | Utility | Utility | & Marketing | Antargaz | Other (b) | & Other (c) | ||||||||||||||||||||||||||||
2010 |
||||||||||||||||||||||||||||||||||||
Revenues |
$ | 5,591.4 | $ | (186.0) | (d) | $ | 2,320.3 | $ | 1,047.5 | $ | 120.2 | $ | 1,145.9 | $ | 887.1 | $ | 172.4 | $ | 84.0 | |||||||||||||||||
Cost of sales |
$ | 3,584.0 | $ | (179.2) | (d) | $ | 1,395.1 | $ | 653.4 | $ | 77.1 | $ | 1,010.7 | $ | 465.9 | $ | 116.2 | $ | 44.8 | |||||||||||||||||
Operating income (loss) |
$ | 659.2 | $ | — | $ | 235.8 | $ | 175.3 | $ | 13.7 | $ | 120.0 | $ | 115.1 | $ | 1.9 | $ | (2.6 | ) | |||||||||||||||||
Loss from equity investees |
(2.1 | ) | — | — | — | — | — | (2.0 | ) | (0.1 | ) | — | ||||||||||||||||||||||||
Interest expense |
(133.8 | ) | — | (65.1 | ) | (40.5 | ) | (1.8 | ) | (0.2 | ) | (22.4 | ) | (3.0 | ) | (0.8 | ) | |||||||||||||||||||
Income (loss) before income taxes |
$ | 523.3 | $ | — | $ | 170.7 | $ | 134.8 | $ | 11.9 | $ | 119.8 | $ | 90.7 | $ | (1.2 | ) | $ | (3.4 | ) | ||||||||||||||||
Net income (loss) attributable to UGI |
$ | 261.0 | $ | — | $ | 47.3 | $ | 83.1 | $ | 6.8 | $ | 68.2 | $ | 60.0 | $ | (1.2 | ) | $ | (3.2 | ) | ||||||||||||||||
Depreciation and amortization |
$ | 210.2 | $ | — | $ | 87.4 | $ | 49.5 | $ | 4.0 | $ | 7.7 | $ | 48.9 | $ | 11.5 | $ | 1.2 | ||||||||||||||||||
Noncontrolling interests’ net income |
$ | 94.7 | $ | — | $ | 91.1 | $ | — | $ | — | $ | 3.3 | $ | 0.3 | $ | — | $ | — | ||||||||||||||||||
Partnership EBITDA (a) |
$ | 321.0 | ||||||||||||||||||||||||||||||||||
Total assets |
$ | 6,374.3 | $ | (81.1 | ) | $ | 1,690.9 | $ | 1,996.3 | $ | 143.3 | $ | 450.8 | $ | 1,678.3 | $ | 320.2 | $ | 175.6 | |||||||||||||||||
Bank loans |
$ | 200.4 | $ | — | $ | 91.0 | $ | 17.0 | $ | — | $ | — | $ | 68.2 | $ | 24.2 | $ | — | ||||||||||||||||||
Capital expenditures |
$ | 352.9 | $ | — | $ | 83.2 | $ | 73.5 | $ | 8.1 | $ | 116.4 | $ | 51.4 | $ | 7.6 | $ | 12.7 | ||||||||||||||||||
Investments in equity investees |
$ | 0.4 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 0.4 | $ | — | ||||||||||||||||||
Goodwill |
$ | 1,562.7 | $ | — | $ | 683.1 | $ | 180.1 | $ | — | $ | 2.8 | $ | 602.7 | $ | 87.0 | $ | 7.0 | ||||||||||||||||||
2009 |
||||||||||||||||||||||||||||||||||||
Revenues |
$ | 5,737.8 | $ | (172.5) | (d) | $ | 2,260.1 | $ | 1,241.0 | $ | 138.5 | $ | 1,224.7 | $ | 837.7 | $ | 117.6 | $ | 90.7 | |||||||||||||||||
Cost of sales |
$ | 3,670.6 | $ | (167.7) | (d) | $ | 1,316.5 | $ | 853.2 | $ | 91.6 | $ | 1,098.5 | $ | 362.4 | $ | 67.1 | $ | 49.0 | |||||||||||||||||
Operating income (loss) |
$ | 685.3 | $ | — | $ | 300.5 | $ | 153.5 | $ | 15.4 | $ | 64.8 | $ | 142.8 | $ | 8.6 | $ | (0.3 | ) | |||||||||||||||||
Loss from equity investees |
(3.1 | ) | — | — | — | — | — | (2.9 | ) | (0.2 | ) | — | ||||||||||||||||||||||||
Interest expense |
(141.1 | ) | — | (70.3 | ) | (42.2 | ) | (1.7 | ) | — | (24.0 | ) | (2.6 | ) | (0.3 | ) | ||||||||||||||||||||
Income (loss) before income taxes |
$ | 541.1 | $ | — | $ | 230.2 | $ | 111.3 | $ | 13.7 | $ | 64.8 | $ | 115.9 | $ | 5.8 | $ | (0.6 | ) | |||||||||||||||||
Net income attributable to UGI |
$ | 258.5 | $ | — | $ | 65.0 | $ | 70.3 | $ | 8.0 | $ | 38.1 | $ | 74.0 | $ | 4.3 | $ | (1.2 | ) | |||||||||||||||||
Depreciation and amortization |
$ | 200.9 | $ | — | $ | 83.9 | $ | 47.2 | $ | 3.9 | $ | 8.5 | $ | 47.7 | $ | 8.8 | $ | 0.9 | ||||||||||||||||||
Noncontrolling interests’ net income (loss) |
$ | 123.5 | $ | 0.2 | $ | 123.6 | $ | — | $ | — | $ | — | $ | (0.4 | ) | $ | 0.1 | $ | — | |||||||||||||||||
Partnership EBITDA (a) |
$ | 381.4 | ||||||||||||||||||||||||||||||||||
Total assets |
$ | 6,042.6 | $ | (115.5 | ) | $ | 1,647.7 | $ | 1,917.1 | $ | 113.2 | $ | 344.1 | $ | 1,705.6 | $ | 260.1 | $ | 170.3 | |||||||||||||||||
Bank loans |
$ | 163.1 | $ | — | $ | — | $ | 145.9 | $ | 8.1 | $ | — | $ | — | $ | 9.1 | $ | — | ||||||||||||||||||
Capital expenditures |
$ | 301.7 | $ | — | $ | 78.7 | $ | 73.8 | $ | 5.3 | $ | 66.2 | $ | 70.5 | $ | 5.8 | $ | 1.4 | ||||||||||||||||||
Investments in equity investees |
$ | 3.0 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 3.0 | $ | — | ||||||||||||||||||
Goodwill |
$ | 1,582.3 | $ | (4.1 | ) | $ | 670.1 | $ | 180.1 | $ | — | $ | 11.8 | $ | 646.9 | $ | 70.4 | $ | 7.1 | |||||||||||||||||
2008 |
||||||||||||||||||||||||||||||||||||
Revenues |
$ | 6,648.2 | $ | (283.7) | (d) | $ | 2,815.2 | $ | 1,138.3 | $ | 139.2 | $ | 1,619.5 | $ | 1,062.6 | $ | 62.2 | $ | 94.9 | |||||||||||||||||
Cost of sales |
$ | 4,744.6 | $ | (277.1) | (d) | $ | 1,908.3 | $ | 831.1 | $ | 84.3 | $ | 1,495.4 | $ | 615.9 | $ | 36.0 | $ | 50.7 | |||||||||||||||||
Operating income |
$ | 585.2 | $ | — | $ | 235.0 | $ | 137.6 | $ | 24.4 | $ | 77.3 | $ | 102.2 | $ | 4.6 | $ | 4.1 | ||||||||||||||||||
Loss from equity investees |
(2.9 | ) | — | — | — | — | — | (1.3 | ) | (1.6 | ) | — | ||||||||||||||||||||||||
Interest expense |
(142.5 | ) | — | (72.9 | ) | (37.1 | ) | (2.0 | ) | — | (27.4 | ) | (2.3 | ) | (0.8 | ) | ||||||||||||||||||||
Income before income taxes |
$ | 439.8 | $ | — | $ | 162.1 | $ | 100.5 | $ | 22.4 | $ | 77.3 | $ | 73.5 | $ | 0.7 | $ | 3.3 | ||||||||||||||||||
Net income attributable to UGI |
$ | 215.5 | $ | — | $ | 43.9 | $ | 60.3 | $ | 13.1 | $ | 45.3 | $ | 52.2 | $ | 0.1 | $ | 0.6 | ||||||||||||||||||
Depreciation and amortization |
$ | 184.4 | $ | — | $ | 80.4 | $ | 37.7 | $ | 3.6 | $ | 7.0 | $ | 50.5 | $ | 4.2 | $ | 1.0 | ||||||||||||||||||
Noncontrolling interests’ net income |
$ | 89.8 | $ | 0.2 | $ | 88.4 | $ | — | $ | — | $ | — | $ | 1.2 | $ | — | $ | — | ||||||||||||||||||
Partnership EBITDA (a) |
$ | 313.0 | ||||||||||||||||||||||||||||||||||
Total assets |
$ | 5,685.0 | $ | (86.3 | ) | $ | 1,722.8 | $ | 1,582.5 | $ | 112.1 | $ | 312.3 | $ | 1,673.2 | $ | 196.8 | $ | 171.6 | |||||||||||||||||
Bank loans |
$ | 136.4 | $ | — | $ | — | $ | 54.0 | $ | 3.0 | $ | — | $ | 70.4 | $ | 9.0 | $ | — | ||||||||||||||||||
Capital expenditures |
$ | 234.2 | $ | — | $ | 62.8 | $ | 58.3 | $ | 6.0 | $ | 30.7 | $ | 70.7 | $ | 4.3 | $ | 1.4 | ||||||||||||||||||
Investments in equity investees |
$ | 63.1 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 63.1 | $ | — | ||||||||||||||||||
Goodwill |
$ | 1,489.7 | $ | (4.0 | ) | $ | 645.2 | $ | 161.7 | $ | — | $ | 11.8 | $ | 622.2 | $ | 45.7 | $ | 7.1 | |||||||||||||||||
| (a) | The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane
operating income: |
| Year ended September 30, | 2010 | 2009 | 2008 | |||||||||
Partnership EBITDA |
$ | 321.0 | $ | 381.4 | (i) | $ | 313.0 | |||||
Depreciation and amortization |
(87.4 | ) | (83.9 | ) | (80.4 | ) | ||||||
Noncontrolling interests (ii) |
2.2 | 3.0 | 2.4 | |||||||||
Operating income |
$ | 235.8 | $ | 300.5 | $ | 235.0 | ||||||
| (i) | Includes $39.9 gain on the sale of California storage facility. See Note 4 to consolidated
financial statements. |
|
| (ii) | Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. |
|
| (b) | International Propane — Other principally comprises FLAGA, including, prior to the January 29,
2009 purchase of the 50% equity interest it did not already own, its central and eastern European
joint-venture ZLH, and our propane distribution businesses in China and Denmark. |
|
| (c) | Corporate & Other results principally comprise UGI Enterprises’ heating, ventilation,
air-conditioning, refrigeration and electrical contracting businesses (“HVAC/R”), net expenses of
UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and
general expenses and interest income. Corporate and Other assets principally comprise cash,
short-term investments, assets of HVAC/R and an intercompany loan. The intercompany loan and
associated interest is removed in the segment presentation. |
|
| (d) | Principally represents the elimination of intersegment transactions principally among Midstream
& Marketing, Gas Utility and AmeriGas Propane. |
F-58
Table of Contents
UGI
CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
BALANCE SHEETS
(Millions of dollars)
(Millions of dollars)
| September 30, | ||||||||
| 2010 | 2009 | |||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 1.0 | $ | 1.4 | ||||
Accounts and notes receivable |
18.8 | 3.9 | ||||||
Deferred income taxes |
0.4 | 0.3 | ||||||
Prepaid expenses and other current assets |
0.3 | 0.5 | ||||||
Total current assets |
20.5 | 6.1 | ||||||
Investments in subsidiaries |
1,830.1 | 1,608.8 | ||||||
Derivative financial instruments |
0.8 | — | ||||||
Deferred income taxes |
20.9 | 18.7 | ||||||
Total assets |
$ | 1,872.3 | $ | 1,633.6 | ||||
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts and notes payable |
$ | 15.8 | $ | 11.3 | ||||
Derivative financial instruments |
— | 0.2 | ||||||
Accrued liabilities |
5.0 | 6.1 | ||||||
Total current liabilities |
20.8 | 17.6 | ||||||
Noncurrent liabilities |
27.0 | 24.6 | ||||||
Commitments and contingencies (Note 1) |
||||||||
Common stockholders’ equity: |
||||||||
Common Stock, without par value (authorized - 300,000,000
shares;
issued — 115,400,294 and 115,261,294 shares, respectively) |
906.1 | 875.6 | ||||||
Retained earnings |
966.7 | 804.3 | ||||||
Accumulated other comprehensive loss |
(10.1 | ) | (38.9 | ) | ||||
| 1,862.7 | 1,641.0 | |||||||
Less treasury stock, at cost |
(38.2 | ) | (49.6 | ) | ||||
Total common stockholders’ equity |
1,824.5 | 1,591.4 | ||||||
Total liabilities and common stockholders’ equity |
$ | 1,872.3 | $ | 1,633.6 | ||||
Note 1 — Commitments and Contingencies:
In addition to the guarantees of Flaga’s debt as described in Note 5 to Consolidated Financial Statements, at September
30, 2010, UGI Corporation had agreed to indemnify the issuers of $32.1 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.
and subsidiaries of which $346.5 of such obligations were outstanding as of September 30, 2010.
S-1
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
(Millions of dollars, except per share amounts)
| Year Ended | ||||||||||||
| September 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
Revenues |
$ | — | $ | — | $ | — | ||||||
Costs and expenses: |
||||||||||||
Operating and administrative expenses |
31.8 | 33.7 | 29.3 | |||||||||
Other income, net (1) |
(31.7 | ) | (33.7 | ) | (29.6 | ) | ||||||
| 0.1 | — | (0.3 | ) | |||||||||
Operating (loss) income |
(0.1 | ) | — | 0.3 | ||||||||
Intercompany interest income |
— | 0.1 | 0.1 | |||||||||
(Loss) income before income taxes |
(0.1 | ) | 0.1 | 0.4 | ||||||||
Income tax expense |
0.7 | 0.8 | 1.3 | |||||||||
Loss before equity in income
of unconsolidated subsidiaries |
(0.8 | ) | (0.7 | ) | (0.9 | ) | ||||||
Equity in income of unconsolidated
subsidiaries |
261.8 | 259.2 | 216.4 | |||||||||
Net income |
$ | 261.0 | $ | 258.5 | $ | 215.5 | ||||||
Earnings per common share: |
||||||||||||
Basic |
$ | 2.38 | $ | 2.38 | $ | 2.01 | ||||||
Diluted |
$ | 2.36 | $ | 2.36 | $ | 1.99 | ||||||
Average common shares outstanding
(thousands): |
||||||||||||
Basic |
109,588 | 108,523 | 107,396 | |||||||||
Diluted |
110,511 | 109,339 | 108,521 | |||||||||
| (1) | UGI provides certain financial and administrative services to certain
of its subsidiaries. UGI bills these subsidiaries monthly for all
direct expenses incurred by UGI on behalf of its subsidiaries as well
as allocated shares of indirect corporate expense incurred or paid
with respect to services provided by UGI. The allocation of indirect
UGI corporate expenses to certain of its subsidiaries utilizes a
weighted, three-component formula comprising revenues, operating
expenses, and net assets employed and considers the relative
percentage of each subsidiary’s such items to the total of such items
for all UGI operating subsidiaries for which general and
administrative services are provided. Management believes that this
allocation method is reasonable and equitable to its subsidiaries.
These billed expenses are classified as “Other income, net” in the
Statements of Income above. |
S-2
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
(Millions of dollars)
(Millions of dollars)
| Year Ended | ||||||||||||
| September 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
NET CASH PROVIDED BY OPERATING
ACTIVITIES (a) |
$ | 173.0 | $ | 124.7 | $ | 155.1 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||
Net investments in unconsolidated subsidiaries |
(106.6 | ) | (50.4 | ) | (94.4 | ) | ||||||
Net cash used by investing activities |
(106.6 | ) | (50.4 | ) | (94.4 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||
Payment of dividends on Common Stock |
(98.6 | ) | (85.1 | ) | (80.9 | ) | ||||||
Issuance of Common Stock |
31.8 | 10.8 | 20.9 | |||||||||
Net cash used by financing activities |
(66.8 | ) | (74.3 | ) | (60.0 | ) | ||||||
Cash and cash equivalents (decrease) increase |
$ | (0.4 | ) | $ | — | $ | 0.7 | |||||
Cash and cash equivalents: |
||||||||||||
End of year |
$ | 1.0 | $ | 1.4 | $ | 1.4 | ||||||
Beginning of year |
1.4 | 1.4 | 0.7 | |||||||||
(Decrease) increase |
$ | (0.4 | ) | $ | — | $ | 0.7 | |||||
| (a) | Includes dividends received from unconsolidated subsidiaries of $172.8, $110.7, and $144.0 for the years
ended September 30, 2010, 2009 and 2008, respectively. |
S-3
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
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, 2010 |
||||||||||||||||
Reserves deducted from assets in
the consolidated balance sheet: |
||||||||||||||||
Allowance for doubtful accounts |
$ | 38.3 | $ | 27.1 | $ | (30.8) | (1) | $ | 34.6 | |||||||
Other reserves: |
||||||||||||||||
Property and casualty liability |
$ | 72.3 | $ | 15.2 | $ | (27.4) | (3) | $ | 65.7 | (5) | ||||||
| 5.6 | (2) | |||||||||||||||
Environmental, litigation and other |
$ | 66.3 | $ | 5.4 | $ | (4.9) | (3) | $ | 65.8 | |||||||
| (1.0) | (2) | |||||||||||||||
Deferred tax assets valuation allowance |
$ | 87.8 | $ | (9.4 | ) | $ | 78.4 | |||||||||
Year Ended September 30, 2009 |
||||||||||||||||
Reserves deducted from assets in
the consolidated balance sheet: |
||||||||||||||||
Allowance for doubtful accounts |
$ | 40.8 | $ | 34.1 | $ | (42.3) | (1) | $ | 38.3 | |||||||
| 5.7 | (4) | |||||||||||||||
Other reserves: |
||||||||||||||||
Property and casualty liability |
$ | 77.4 | $ | 22.7 | $ | (32.6) | (3) | $ | 72.3 | (5) | ||||||
| 4.6 | (4) | |||||||||||||||
| 0.2 | (2) | |||||||||||||||
Environmental, litigation and other |
$ | 31.4 | $ | 20.5 | $ | (5.5) | (3) | $ | 66.3 | |||||||
| 13.9 | (4) | |||||||||||||||
| 6.0 | (2) | |||||||||||||||
Deferred tax assets valuation allowance |
$ | 56.5 | $ | 31.3 | $ | 87.8 | ||||||||||
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)
| Charged | ||||||||||||||||
| Balance at | (credited) | Balance at | ||||||||||||||
| beginning | to costs and | end of | ||||||||||||||
| of year | expenses | Other | year | |||||||||||||
Year Ended September 30, 2008 |
||||||||||||||||
Reserves deducted from assets in
the consolidated balance sheet: |
||||||||||||||||
Allowance for doubtful accounts |
$ | 37.7 | $ | 37.1 | $ | (34.0 | )(1) | $ | 40.8 | |||||||
Other reserves: |
||||||||||||||||
Property and casualty liability |
$ | 65.0 | $ | 34.4 | $ | (22.3 | )(3) | $ | 77.4 | (5) | ||||||
| 0.3 | (2) | |||||||||||||||
Environmental, litigation and other |
$ | 37.1 | $ | 5.7 | $ | (13.0 | )(3) | $ | 31.4 | |||||||
| 1.6 | (2) | |||||||||||||||
Deferred tax assets valuation allowance |
$ | 62.2 | $ | 0.8 | $ | (6.5 | )(3) | $ | 56.5 | |||||||
| (1) | Uncollectible accounts written off, net of recoveries. |
|
| (2) | Other adjustments. |
|
| (3) | Payments, net. |
|
| (4) | Acquisition. |
|
| (5) | At September 30, 2010, 2009 and 2008, the Company had insurance indemnification receivables associated with its
property and casualty liabilities totaling $7.2, $1.0 and $18.5, respectively. |
S-5
Table of Contents
EXHIBIT INDEX
| Exhibit No. | Description | |||
| 10.5 | UGI Corporation Amended and Restated Directors’ Deferred
Compensation Plan as of January 1, 2005 |
|||
| 10.7 | UGI Corporation 1997 Stock Option and Dividend Equivalent
Plan Amended and Restated as of May 24, 2005 |
|||
| 10.31 | a | Amended and Restated UGI Corporation 2004 Omnibus Equity
Compensation Plan Sub-Plan for French Employees and Corporate
Officers Stock Option Grant Letter effective January 1, 2010 |
||
| 10.31 | b | Amended and Restated UGI Corporation 2004 Omnibus Equity
Compensation Plan Sub-Plan for French Employees and Corporate
Officers Performance Unit Grant Letter effective January 1,
2010 |
||
| 10.32 | a | Description of oral compensation arrangements for Messrs.
Greenberg, Kelly, Varagne and Walsh |
||
| 10.33 | Summary of Director Compensation as of October 1, 2010 |
|||
| 10.37 | Trademark License Agreement dated April 19, 1995 among UGI
Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas
Partners, L.P. and AmeriGas Propane, L.P. |
|||
| 10.39 | Credit Agreement, dated as of April 17, 2009, among AmeriGas
Propane, L.P., as Borrower, AmeriGas Propane, Inc., as
Guarantor, Petrolane Incorporated, as Guarantor, Citizens
Bank of Pennsylvania, as Syndication Agent, JPMorgan Chase,
N.A., as Documentation Agent and Wachovia Bank, National
Association, as Administrative Agent |
|||
| 10.42 | 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 |
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| 10.46 | Receivables Purchase Agreement, dated as of November 30,
2001, as amended through and including Amendment No. 8
thereto dated April 22, 2010 and Amendment No. 9 thereto
dated August 26, 2010, by and among UGI Energy Services,
Inc., as servicer, Energy Services Funding Corporation, as
seller, Market Street Funding, LLC, as issuer, and PNC Bank,
National Association, as administrator |
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| 10.47 | Purchase and Sale Agreement, dated as of November 30, 2001,
as amended through and including Amendment No. 3 thereto
dated August 26, 2010, by and between UGI Energy Services,
Inc. and Energy Services Funding Corporation |
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| 10.48 | Credit Agreement, dated as of August 26, 2010, among UGI
Energy Services, Inc., as borrower, and JPMorgan Chase Bank,
N.A., as administrative agent, PNC Bank, National
Association, as syndication agent, and Wells Fargo Bank,
National Association and Credit Suisse AG, Cayman Islands
Branch, as co-documentation agents |
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| 10.51 | 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 |
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Table of Contents
| Exhibit No. | Description | |||
| 10.52 | 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 |
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| 10.60 | 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) |
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| 21 | Subsidiaries of the Registrant |
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| 23 | Consent of PricewaterhouseCoopers LLP |
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| 31.1 | Certification by the Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act |
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| 31.2 | Certification by the Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act |
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| 32 | Certification by the Chief Executive Officer and Chief
Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act |
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| 101 | The following materials from UGI Corporation’s Annual Report on Form 10-K for the year ended September 30,
2010, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets; (ii) the Consolidated Statements of Income; (iii)
the Consolidated Statements of Comprehensive Income; (iv) the
Consolidated Statements of Cash Flows; (v) the Consolidated Statements of Changes in Equity; and (vi) Notes to Consolidated
Financial Statements, tagged as blocks of text. This Exhibit 101 is deemed not filed for purposes of Section 11 or 12 of the Securities Act of 1933
and Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections. |
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