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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, 2008
Commission file number 1-11071
UGI CORPORATION
(Exact name of registrant as specified in its charter)
| Pennsylvania (State or Other Jurisdiction of Incorporation or Organization) | 23-2668356 (I.R.S. Employer Identification No.) |
460 North Gulph Road, King of Prussia, PA 19406
(Address of Principal Executive Offices) (Zip Code)
(Address of Principal Executive Offices) (Zip Code)
(610) 337-1000
(Registrant’s telephone number, including area code)
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of each Exchange 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. Yesþ Noo
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ
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. Yesþ Noo
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yesþ Noo
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 filerþ | Accelerated filero | Non-accelerated filero | Smaller reporting companyo |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yeso Noþ
The aggregate market value of UGI Corporation Common Stock held by non-affiliates of the registrant on March 31, 2008 was $2,663,499,789.
At November 1, 2008 there were 107,890,145 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 27, 2009 are incorporated by reference into Part III of this Form 10-K.
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PART I:
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
CORPORATE OVERVIEW
UGI Corporation is a holding company that, through subsidiaries and joint venture affiliates, distributes and markets energy products and related services. We are a domestic and international retail distributor of propane and butane (which are liquefied petroleum gases (“LPG”)); a provider of natural gas and electric service through regulated local distribution utilities; a generator of electricity; a regional marketer of energy commodities; and a regional provider of heating, ventilation, air conditioning, refrigeration and electrical contracting services. Our subsidiaries and joint venture affiliates operate principally in the following five business segments:
| • | AmeriGas Propane | ||
| • | International Propane | ||
| • | Gas Utility | ||
| • | Electric Utility | ||
| • | Energy Services |
The AmeriGas Propane segment consists of the propane distribution business of AmeriGas Partners, L.P. (“AmeriGas Partners” or the “Partnership”) which is the nation’s largest retail propane distributor. The Partnership’s sole general partner is our subsidiary, AmeriGas Propane, Inc. (“AmeriGas Propane” or the “General Partner”). The common units of AmeriGas Partners represent limited partner interests in a Delaware limited partnership; they trade on the New York Stock Exchange under the symbol “APU.” We have an effective 44% ownership interest in the Partnership; the remaining interest is publicly held. See Note 1 to the Company’s Consolidated Financial Statements.
The International Propane segment consists of the LPG distribution businesses of our wholly owned subsidiaries Antargaz, a French société anonyme (“Antargaz”), Flaga GmbH, an Austrian limited liability company (“Flaga”), and our joint venture in China. Antargaz is one of the largest retail distributors of LPG in France. Flaga is the largest retail LPG distributor in Austria and through its joint venture company is the largest retail LPG distributor in the Czech Republic and one of the largest retail LPG distributors in Slovakia. In China, we participate in an LPG joint venture business in the Nantong region.
The Gas Utility segment (“Gas Utility”) consists of the regulated natural gas distribution businesses of our subsidiary, UGI Utilities, Inc. (“UGI Gas”) and UGI Utilities’ subsidiary, UGI Penn Natural Gas, Inc. (“UGIPNG”). Gas Utility serves approximately 484,000 customers in eastern and northeastern Pennsylvania. The Electric Utility segment (“Electric Utility”) consists of the regulated electric distribution business of UGI Utilities, serving approximately 62,000 customers in northeastern Pennsylvania. Gas Utility and Electric Utility are regulated by the Pennsylvania Public Utility Commission (“PUC”).
On October 1, 2008, UGI Utilities completed the acquisition of all of the issued and outstanding stock of PPL Gas Utilities Corporation (“PPL Gas”), the natural gas distribution utility of PPL Corporation (“PPL”), and its wholly owned subsidiary, Penn Fuel Propane, LLC (“Penn Fuel Propane”). Immediately following the closing of the acquisition, Penn Fuel Propane sold its retail propane distribution assets to AmeriGas Propane, L.P., an affiliate of UGI. PPL Gas, now known as UGI Central Penn Gas, Inc., distributes natural gas to approximately 76,000 customers in 34 counties in eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in portions of one Maryland county. Beginning in the 2009 fiscal year, UGI Central Penn Gas, Inc. will be included in the Company’s Gas Utility segment and Penn Fuel Propane will be included in the Company’s AmeriGas Propane segment. See Note 15 to the Company’s Consolidated Financial Statements.
The Energy Services segment consists of energy-related businesses conducted by a number of subsidiaries. These businesses include (i) energy marketing in the eastern region of the United States under the trade names GASMARK® and POWERMARK®, (ii) operating or owning interests in electric generation assets in Pennsylvania, (iii) operating and owning a natural gas liquefaction, storage and vaporization facility and propane-air mixing assets, (iv) operating and owning a propane import and storage facility in Chesapeake, Virginia, and (v) managing natural gas pipeline and storage contracts.
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.
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Business Strategy
Our business strategy is to grow the Company by focusing on our core competencies as a marketer and distributor of energy products and services. We are employing our core competencies from our existing businesses and using our national scope, international experience, extensive asset base and access to customers to accelerate both internal growth and growth through acquisitions in our existing businesses, as well as in related and complementary businesses. During fiscal year 2008, we completed a number of transactions in pursuit of this strategy.
Global Climate Change
There is a growing concern, both nationally and internationally, about climate change and the contribution of greenhouse gas emissions, most notably carbon dioxide, to global warming. While some states have adopted laws regulating the emission of greenhouse gases for some industry sectors, there is currently no federal regulation of greenhouse gas emissions in the United States. It is anticipated that federal legislation, likely consisting of a cap and trade system, governing the emission of greenhouse gases will be enacted in the United States in the near future. 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, when new climate change regulations become effective. In addition, we are developing a strategy to identify both our greenhouse gas 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.
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 2008” and “Fiscal 2007” refer to the fiscal years ended September 30, 2008 and September 30, 2007, 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 Robert W. Krick, Vice President and Treasurer, UGI Corporation, P.O. Box 858, Valley Forge, PA 19482.
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AMERIGAS PROPANE
Our domestic propane distribution business is conducted through AmeriGas Partners. As of September 30, 2008, the Partnership operated from approximately 600 district locations in 46 states. AmeriGas Propane is responsible for managing the Partnership. Although our consolidated financial statements include 100% of the Partnership’s revenues, assets and liabilities, our net income reflects only our 44% effective interest in the income or loss of the Partnership, due to the outstanding publicly-owned limited partnership interests. See Note 1 to the Company’s Consolidated Financial Statements.
General Industry Information
Propane is separated from crude oil during the refining process and also extracted from natural gas or oil wellhead gas at processing plants. Propane is normally transported and stored in a liquid state under moderate pressure or refrigeration for economy and ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable gas. Propane is colorless and odorless; an odorant is added to allow its detection. Propane is clean burning, producing negligible amounts of pollutants when properly consumed.
The primary customers for propane are residential, commercial, industrial, motor fuel and agricultural users to whom natural gas is not readily available. Propane is typically more expensive than natural gas and fuel oil and, in most areas, cheaper than electricity on an equivalent energy basis.
In Fiscal 2008, the Partnership’s retail propane sales totaled approximately 993 million gallons. Based on the most recent annual survey by the American Petroleum Institute, total 2006 domestic retail propane sales (annual sales for other than chemical uses) in the United States totaled approximately 9.5 billion gallons. Based on LP-GAS magazine rankings, 2007 sales volume of the ten largest propane companies (including AmeriGas Partners) represented approximately 43% of domestic retail sales.
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Products, Services and Marketing
As of September 30, 2008, the Partnership served approximately 1.3 million customers from district locations in 46 states. In addition to distributing propane, the Partnership also sells, installs and services propane appliances, including heating systems. In certain markets, the Partnership also installs and services propane fuel systems for motor vehicles. Typically, district locations are found in suburban and rural areas where natural gas is not readily available. Districts generally consist of an office, appliance showroom, warehouse, and service facilities, with one or more 18,000 to 30,000 gallon storage tanks on the premises. As part of its overall transportation and distribution infrastructure, the Partnership operates as an interstate carrier in 48 states throughout the continental United States. It is also licensed as a carrier in the Canadian Provinces of British Columbia and Quebec.
The Partnership sells propane primarily to five markets: residential, commercial/industrial, motor fuel, agricultural and wholesale. The Partnership distributed over one billion gallons of propane in Fiscal 2008. Approximately 90% of the Partnership’s Fiscal 2008 sales (based on gallons sold) were to retail accounts and approximately 10% were to wholesale customers. Sales to residential customers in Fiscal 2008 represented approximately 40% of retail gallons sold; commercial/industrial customers 36%; motor fuel customers 14%; and agricultural customers 5%. Transport gallons, which are large-scale deliveries to retail customers other than residential, accounted for 5% of Fiscal 2008 retail gallons. No single customer represents, or is anticipated to represent, more than 5% of the Partnership’s consolidated revenues.
The Partnership continues to expand its AmeriGas Cylinder Exchange (“ACE”) program. At September 30, 2008, ACE cylinders were available at approximately 25,000 retail locations throughout the United States. Sales of our ACE grill cylinders to retailers are included in the commercial/industrial market. The ACE program enables consumers to exchange their empty propane grill cylinders for filled cylinders or to purchase filled cylinders at various retail locations such as home centers, gas stations, mass merchandisers and grocery and convenience stores. The Partnership also supplies retailers with large propane tanks to enable retailers to fill customers’ propane grill cylinders directly at the retailer’s location.
In the residential market, which includes both conventional and manufactured housing, propane is used primarily for home heating, water heating and cooking purposes. Commercial users, which include motels, hotels, restaurants and retail stores, generally use propane for the same purposes as residential customers. Industrial customers use propane to fire furnaces, as a cutting gas and in other process applications. Other industrial customers are large-scale heating accounts and local gas utility customers who use propane as a supplemental fuel to meet peak load deliverability requirements. As a motor fuel, propane is burned in internal combustion engines that power over-the-road vehicles, forklifts and stationary engines. Agricultural uses include tobacco curing, chicken brooding and crop drying. In its wholesale operations, the Partnership principally sells propane to large industrial end-users and other propane distributors.
Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from the bobtail truck, which generally holds 2,400 to 3,000 gallons of propane, into a stationary storage tank on the customer’s premises. The Partnership owns most of these storage tanks and leases them to its customers. The capacity of these tanks ranges from approximately 120 gallons to approximately 1,200 gallons. The Partnership also delivers propane to retail customers in portable cylinders (including ACE propane grill cylinders) which are filled with 3.5 to 24 gallons of propane. Some of these deliveries are made to the customer’s location, where empty cylinders are either picked up for replenishment or filled in place.
Propane Supply and Storage
The Partnership has over 250 domestic and international sources of supply, including the spot market. Supplies of propane from the Partnership’s sources historically have been readily available. During the year ended September 30, 2008, over 90% of the Partnership’s propane supply was purchased under supply agreements with terms of 1 to 3 years. The availability of propane supply is dependent upon, among other things, the severity of winter weather, the price and availability of competing fuels such as natural gas and crude oil, and the amount and availability of imported supply. Although no assurance can be given that supplies of propane will be readily available in the future, management currently expects to be able to secure adequate supplies during fiscal year 2009. 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 48% of the Partnership’s Fiscal 2008 propane supply. No other single supplier provided more than 10% of the Partnership’s total propane supply in Fiscal 2008. In certain market areas, however, some suppliers provide more than 50% of the Partnership’s requirements. Disruptions in supply in these areas could also have an adverse impact on the Partnership’s margins.
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The Partnership’s supply contracts typically provide for pricing based upon (i) index formulas using the current prices established at a major storage point such as Mont Belvieu, Texas, or Conway, Kansas, or (ii) posted prices at the time of delivery. In addition, some agreements provide maximum and minimum seasonal purchase volume guidelines. The percentage of contract purchases, and the amount of supply contracted for at fixed prices, will vary from year to year as determined by the General Partner. The Partnership uses a number of interstate pipelines, as well as railroad tank cars, delivery trucks and barges, to transport propane from suppliers to storage and distribution facilities. The Partnership stores propane at large storage facilities in Arizona and Pennsylvania, as well as at smaller facilities in several other states.
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. In Fiscal 2008, the Partnership experienced significant product cost increases over Fiscal 2007 due to crude oil price increases. The General Partner has adopted supply acquisition and product cost risk management practices to reduce the effect of volatility on selling prices. These practices currently include the use of summer storage, forward purchases and derivative commodity instruments, such as options and propane price swaps. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures.”
The following graph shows the average prices of propane on the propane spot market during the last 5 fiscal years at Mont Belvieu, Texas, a major storage area.
Average Propane Spot Market Prices
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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.
In the motor fuel market, propane competes with gasoline and diesel fuel as well as electric batteries and fuel cells. Wholesale propane distribution is a highly competitive, low margin business. Propane sales to other retail distributors and large-volume, direct-shipment industrial end-users are price sensitive and frequently involve a competitive bidding process.
The retail propane industry is mature, with only modest growth in total demand for the product foreseen. Therefore, the Partnership’s ability to grow within the industry is dependent on its ability to acquire other retail distributors and to achieve internal growth, which includes expansion of the ACE program and the Strategic Accounts program (through which the Partnership encourages large, multi-location propane users to enter into a supply agreement with it rather than with many small suppliers), as well as the success of its sales and marketing programs designed to attract and retain customers. The failure of the Partnership to retain and grow its customer base would have an adverse effect on its 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.
Properties
As of September 30, 2008, the Partnership owned approximately 82% of its district locations. On November 13, 2008, the Partnership sold its 600,000 barrel refrigerated, above-ground storage facility located on leased property in California for approximately $43 million in cash. See Note 15 to the Company’s Consolidated Financial Statements.
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, 2008, the Partnership operated a transportation fleet with the following assets:
| Approximate Quantity & Equipment Type | % Owned | % Leased | ||||||||||
| 540 | Trailers | 89 | 11 | |||||||||
| 290 | Tractors | 29 | 71 | |||||||||
| 180 | Railroad tank cars | 0 | 100 | |||||||||
| 2,640 | Bobtail trucks | 13 | 87 | |||||||||
| 350 | Rack trucks | 9 | 91 | |||||||||
| 2,200 | Service and delivery trucks | 16 | 84 | |||||||||
Other assets owned at September 30, 2008 included approximately 875,000 stationary storage tanks with typical capacities ranging from 121 to 2,000 gallons and approximately 2.7 million portable propane cylinders with typical capacities of 1 to 120 gallons. The Partnership also owned approximately 5,600 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. UGI and the General Partner each have the option to terminate its respective license agreement (on 12 months prior notice in the case of UGI), without penalty, if the General Partner is removed as general partner of the Partnership other than for cause. If the General Partner ceases to serve as the general partner of the Partnership for cause, the General Partner has the option to terminate its license agreement upon payment of a fee to UGI equal to the fair market value of the licensed trade names. UGI has a similar termination option; however, UGI must provide 12 months prior notice in addition to paying the fee to the General Partner.
Seasonality
Because many customers use propane for heating purposes, the Partnership’s retail sales volume is seasonal. Approximately 55% to 60% of the Partnership’s retail sales volume occurs, and substantially all of the Partnership’s operating income is earned, during the five-month peak heating season from November through March. As a result of this seasonality, sales are higher in the Partnership’s first and second fiscal quarters (October 1 through March 31). Cash receipts are generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the winter heating season.
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. The most recent editions of NFPA Pamphlet No. 58, adopted by a majority of states, requires certain stationary cylinders that are filled in place to be re-qualified periodically, depending on the date of manufacture and previous schedule of re-qualification of the cylinders. Management believes that the policies and procedures currently in effect at all of its facilities for the handling, storage and distribution of propane are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safety laws.
With respect to the transportation of propane by truck, the Partnership is subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the United States Department of Transportation (“DOT”). The Natural Gas Safety Act of 1968 required the DOT to develop and enforce minimum safety regulations for the transportation of gases by pipeline. The DOT’s pipeline safety regulations apply to, among other things, a propane gas system which supplies 10 or more residential customers or 2 or more commercial customers from a single source and a propane gas system any portion of which is located in a public place. The code requires operators of all gas systems to provide training and written instructions for employees, establish written procedures to minimize the hazards resulting from gas pipeline emergencies, and to conduct and keep records of inspections and testing. Operators are subject to the Pipeline Safety Improvement Act of 2002, which, among other things, protects from adverse employment actions employees who provide information to their employers or to the federal government as to pipeline safety.
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Employees
The Partnership does not directly employ any persons responsible for managing or operating the Partnership. The General Partner provides these services and is reimbursed for its direct and indirect costs and expenses, including all compensation and benefit costs. At September 30, 2008, the General Partner had approximately 5,900 employees, including approximately 380 part-time, seasonal and temporary employees, working on behalf of the Partnership. UGI also performs certain financial and administrative services for the General Partner on behalf of the Partnership and is reimbursed by the Partnership.
INTERNATIONAL BUSINESSES
We conduct our international LPG distribution business principally in Europe through our wholly owned subsidiaries, Antargaz and Flaga. On February 15, 2006, Flaga entered into a joint venture with a subsidiary of Progas GmbH & Co KG (“Progas”) to combine our respective central European LPG operations. The joint venture company, Zentraleuropa LPG Holding GmbH (“ZLH”), is owned and controlled equally by Flaga and Progas. Flaga contributed the shares of its operating subsidiaries in the Czech Republic and Slovakia to ZLH and Progas contributed the shares of its operating subsidiaries in the Czech Republic, Slovakia, Poland, Hungary and Romania to ZLH. In a related transaction during fiscal year 2006, Flaga expanded its LPG distribution business in Austria by acquiring Progas Flüssiggas Handelsgesellschaft GmbH. In Fiscal 2007, ZLH expanded its Polish operations by acquiring, through a subsidiary, an LPG distribution business and storage and filling plant in Poland.
Antargaz operates in France; Flaga operates in Austria and Switzerland; and ZLH operates through subsidiaries in the Czech Republic, Slovakia, Poland, Hungary and Romania. During Fiscal 2008, Antargaz sold approximately 293 million gallons of LPG, Flaga sold approximately 17 million gallons of LPG and ZLH, through its subsidiaries, sold approximately 56 million gallons of LPG. Our joint venture in China sold approximately 13 million gallons of LPG during Fiscal 2008.
ANTARGAZ
Products, Services and Marketing
Antargaz’ customer base consists of residential, commercial, agricultural and motor fuel customer accounts that use LPG for space heating, cooking, water heating, process heat and transportation. Antargaz sells LPG in cylinders, and in small, medium and large bulk volumes stored in tanks. Sales of LPG are also made to service stations to accommodate vehicles that run on LPG. Antargaz sells LPG in cylinders to approximately 22,000 retail outlets, such as supermarkets, individually owned stores and gas stations. At September 30, 2008, Antargaz had approximately 233,000 bulk customers and approximately 5 million cylinders in circulation. Approximately 64% of Antargaz’ Fiscal 2008 sales (based on volumes) were cylinder and small bulk, 15% medium bulk, 19% large bulk, and 2% to service stations for automobiles. Antargaz also engages in wholesale sales of LPG and provides logistic, storage and other services to third-party LPG distributors. No single customer represents, or is anticipated to represent, more than 5% of total revenues for Antargaz.
Sales to small bulk customers represent the largest segment of Antargaz’ business in terms of volume, revenue and 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-filled cylinders accounted for approximately 58% of all LPG cylinders sold in Fiscal 2008, with propane-filled cylinders accounting for the remainder. Propane-filled cylinders are also used to supply fuel for forklift trucks. The market demand for filled cylinders has been declining, due primarily to customers gradually changing to other household energy sources for heating and cooking, such as natural gas. Antargaz is seeking to increase demand for butane and propane-filled cylinders through marketing and product innovations.
Medium bulk customers use propane only, and consist mainly of large residential developments such as housing projects, hospitals, municipalities and medium-sized industrial and agricultural enterprises. Large bulk customers are primarily companies that use LPG in their industrial processes and large agricultural companies.
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LPG Supply and Storage
Antargaz has an agreement with Totalgaz for the supply of butane and propane, with pricing based on internationally quoted market prices. Under this agreement, 80% of Antargaz’ requirements for butane are guaranteed until June 2009 and 15% of its requirements for propane are guaranteed until September 2010. Requirements are fixed annually and Antargaz can develop other sources of supply. For Fiscal 2008, Antargaz purchased almost 100% of its butane needs and approximately 30% of its propane needs from Totalgaz. Antargaz also purchases propane on the international market and, to a lesser degree, purchases butane on the domestic market, under term agreements with international oil and gas trading companies such as SHV Gas Supply and Trading, and Total Trading SA. In addition, purchases are made on the spot market from international oil and gas companies such as STASCO and to a lesser extent from domestic refineries, including those operated by BP France and Esso SAF.
Antargaz has 4 primary storage facilities in operation, including 3 that are located at deep sea harbor facilities, and 25 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 limited future growth expected. Sales volumes are affected principally by the severity of the weather and customer migration to alternative energy forms, including natural gas and electricity. Like other businesses, it becomes more difficult for Antargaz to pass on product costs increases fully when product costs rise rapidly. Increased LPG prices may result in slower than expected growth due to customer conservation and customers seeking less expensive alternative energy sources. France 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. Competitive conditions in the French LPG market are undergoing change. Some supermarket chain stores and other new market entrants are competing in the cylinder market and Antargaz has partnered with one supermarket chain in this market. As a result of these changes, we have experienced an intensified level of competition in the French LPG market. Antargaz’ competitors are generally affiliates of its LPG suppliers. As a result, its competitors may obtain product at more competitive prices.
During fiscal year 2005, Antargaz received an inquiry from the French competition authority, the General Division of Competition, Consumption and Fraud Punishment. For more information on the inquiry, see “LEGAL PROCEEDINGS.”
Seasonality
Because a significant amount of LPG is used for heating, demand is typically higher during the colder months of the year. Approximately 65% to 70% of Antargaz’ retail sales volume occurs, and approximately 92% of Antargaz’ operating income is earned, during the 6 months from October through March.
Sales volume for Antargaz traditionally fluctuates from year-to-year in response to variations in weather, prices and other factors, such as conservation efforts and general economic conditions. For historical information on weather statistics for Antargaz, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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Government Regulation
Antargaz’ business is subject to various laws and regulations at the national and European levels with respect to matters such as protection of the environment, the storage and handling of hazardous materials and flammable substances, the discharge of contaminants into the environment and the safety of persons and property.
Properties
Antargaz has 4 primary storage facilities in operation. Two of these storage facilities are underground caverns, one is a refrigerated facility, and one is an aerial pressure facility. The table below sets forth details of each of these facilities.
| Antargaz | Antargaz | |||||||||||
| Storage Capacity - | Storage Capacity - | |||||||||||
| Propane | Butane | |||||||||||
| Ownership % | (m3) (1) | (m3) (1) | ||||||||||
| Norgal | 52.7 | 22,600 | 8,900 | |||||||||
| Geogaz Lavera | 16.7 | 17,400 | 32,500 | |||||||||
| Donges | 50.0 | (2) | 30,000 | 0 | ||||||||
| Cobogal | 15.0 | 1,300 | 450 | |||||||||
| (1) | Cubic meters. | |
| (2) | Pursuant to a long-term contractual arrangement with the owner. |
Antargaz is evaluating whether to close a fifth storage facility, Geovexin. Antargaz has 25 secondary storage facilities, 14 of which are wholly owned. The others are partially owned, through joint ventures.
Employees
At September 30, 2008, Antargaz had approximately 1,070 employees.
FLAGA
Products, Services and Marketing
Flaga distributes LPG in Austria and Switzerland. ZLH’s subsidiaries distribute LPG for residential, commercial, industrial, and auto gas applications in the following Central and Eastern European countries: Czech Republic, Slovakia, Poland, Hungary and Romania. During Fiscal 2008, Flaga sold approximately 17 million gallons of LPG. ZLH, through its subsidiaries, sold approximately 56 million gallons of LPG.
Flaga is the largest distributor of LPG in Austria, serving residential, commercial and industrial customers. The retail propane industry in Austria is mature, with slight declines in overall demand in recent years, due primarily to the expansion of natural gas and renewable energy sources. Competition for customers is based on contract terms as well as on product prices. Flaga has 6 sales offices in Austria and 1 sales office in Switzerland. Much of Flaga’s cylinder business is conducted through approximately 600 local resellers with whom Flaga has a long business relationship. Flaga utilizes approximately 18 storage facilities in Austria and 1 in Switzerland. Flaga competes with other propane marketers, including competitors located in other eastern European countries, and also competes with providers of other sources of energy, principally natural gas, electricity and wood.
ZLH utilizes approximately 26 storage facilities and has approximately 12 sales offices in the countries in which it operates. ZLH is one of the leading distributors of LPG in both the Czech Republic and Slovakia.
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Seasonality and Competition
Because many of Flaga’s and ZLH’s customers use LPG for heating, sales volumes in Flaga’s and ZLH’s markets are affected principally by the severity of the weather and traditionally fluctuate from year-to-year in response to variations in weather, prices and other factors, such as conservation efforts and general economic conditions. Because Flaga’s and ZLH’s profitability is sensitive to changes in wholesale LPG costs, Flaga and ZLH generally seek to pass on increases in the cost of LPG to customers. There is no assurance, however, that Flaga and ZLH will always be able to pass on product cost increases fully. It is particularly difficult for ZLH to pass on rapid increases in LPG due to the low per capita income of customers in ZLH’s markets. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude oil and natural gas, or other unforeseen events. High LPG prices may result in slower than expected growth due to customer conservation and customers seeking less expensive alternative energy sources. In many of Flaga’s and ZLH’s European markets, government policies and incentives that favor alternative energy sources may result in customers migrating to energy sources other than LPG.
Government Regulation
Flaga’s and ZLH’s businesses are subject to various laws and regulations at both the national and European levels with respect to matters such as protection of the environment and the storage and handling of hazardous materials and flammable substances.
Employees
At September 30, 2008, Flaga had approximately 140 full time employees and ZLH had approximately 490 full time employees.
GAS UTILITY
Service Area; Revenue Analysis
Gas Utility is authorized to distribute natural gas to approximately 484,000 customers in portions of 28 eastern and northeastern Pennsylvania counties through its distribution system of approximately 7,860 miles of gas mains. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre and Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas Utility’s service area are major production centers for basic industries such as specialty metals, aluminum, glass and paper product manufacturing.
System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal 2008 was approximately 133.7 billion cubic feet (“bcf”). System sales of gas accounted for approximately 42% of system throughput, while gas transported for residential, commercial and industrial customers (who bought their gas from others) accounted for approximately 58% of system throughput.
Sources of Supply and Pipeline Capacity
Gas Utility meets its service requirements by utilizing a diverse mix of natural gas purchase contracts with marketers and producers, along with storage and transportation service contracts. These arrangements enable Gas Utility to purchase gas from Gulf Coast, Mid-Continent, Appalachian and Canadian sources. For the transportation and storage function, Gas Utility has long-term agreements with a number of pipeline companies, including Texas Eastern Transmission Corporation, Columbia Gas Transmission Corporation, Transcontinental Gas Pipeline Corporation and Tennessee Gas Pipeline.
Gas Supply Contracts
During Fiscal 2008, Gas Utility purchased approximately 78 bcf of natural gas for sale to retail core market and off-system sales customers. Approximately 87% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 13% of gas purchased by Gas Utility was supplied by approximately 23 producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 1 year. Gas Utility also has long-term contracts with suppliers for natural gas peaking supply during the months of November through March.
Seasonality
Because many of its customers use gas for heating purposes, Gas Utility sales are seasonal. Approximately 55% to 60% of Gas Utility’s sales volume is supplied, and approximately 70% to 75% of Gas Utility’s operating income is earned, during the five-month peak heating season from November through March.
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Competition
Natural gas is a fuel that competes with electricity and oil, and to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of fuel utilization equipment. Electric utilities in Gas Utility’s service area are seeking new load, primarily in the new construction market. In parts of Gas Utility’s service area, electricity may have a competitive price advantage over natural gas due to government regulated rate caps on electricity. Rate caps for electric utilities serving a significant portion of Gas Utility’s service territory are currently scheduled to expire in 2009 and 2010. Additionally, high efficiency electric heat pumps have led to a decrease in the cost of electricity for heating. Fuel oil dealers compete for customers in all categories, including industrial customers. Gas Utility responds to this competition with marketing efforts designed to retain and grow its customer base.
In substantially all of its service territories, Gas Utility is the only regulated gas distribution utility having the right, granted by the PUC or by law, to provide gas distribution services. Since the 1980s, larger commercial and industrial customers have been able to purchase gas supplies from entities other than natural gas distribution utility companies. As a result of Pennsylvania’s Natural Gas Choice and Competition Act, effective July 1, 1999 all of Gas Utility’s customers, including residential and smaller commercial and industrial customers (“Core Market Customers”), have been afforded this opportunity. As of September 30, 2008, four marketers provide gas supplies to approximately 4,400 of Gas Utility’s Core Market Customers. Gas Utility provides transportation services for its customers who purchase natural gas from others.
A number of Gas Utility’s commercial and industrial customers have the ability to switch to an alternate fuel at any time and, therefore, are served on an interruptible basis under rates which are competitively priced with respect to the alternate fuel. Margin from these customers, therefore, is affected by the difference or “spread” between the customers’ delivered cost of gas and the customers’ delivered cost of the alternate fuel, as well as the frequency and duration of interruptions. See “Gas Utility and Electric Utility Regulation and Rates — Gas Utility Rates.” In accordance with the PUC’s June 29, 2000 Gas Restructuring Order applicable to UGI Gas, a substantial portion of the margin from certain of these customers (who use pipeline capacity contracted by UGI Gas to serve retail customers) is used to reduce purchased gas cost rates for retail customers. Approximately 27% of UGI Gas’ commercial and industrial customers, including certain customers served under interruptible rates, have locations which afford them the opportunity, although none have exercised it, of seeking transportation service directly from interstate pipelines, thereby bypassing UGI Gas. The majority of customers in this group are served under transportation contracts having 3 to 20 year terms. Included in these two customer groups are UGI Gas’ 10 largest customers in terms of annual volumes. All of these customers have contracts, 9 of which extend beyond the 2009 fiscal year. No single customer represents, or is anticipated to represent, more than 5% of Gas Utility’s total revenues.
Outlook for Gas Service and Supply
Gas Utility anticipates having adequate pipeline capacity and sources of supply available to it to meet the full requirements of all firm customers on its system through fiscal year 2009. 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 2008, Gas Utility supplied transportation service to 2 major co-generation installations and 5 electric generation facilities. Gas Utility continues to pursue opportunities to supply natural gas to electric generation projects located in its service area. Gas Utility also continues to seek new residential, commercial and industrial customers for both firm and interruptible service. In the residential market sector, Gas Utility connected approximately 11,000 residential heating customers during Fiscal 2008. Despite the nationwide slowdown in the real estate market, of those new customers, new home construction accounted for over 4,970 heating customers. If the slowdown in new home construction continues in fiscal year 2009 in Gas Utility’s service area, customer growth may be adversely affected. Customers converting from other energy sources, primarily oil and electricity, and existing non-heating gas customers who have added gas heating systems to replace other energy sources, accounted for the balance of the additions. The number of new commercial and industrial Gas Utility customers was approximately 1,500.
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.
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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 2,150 miles of transmission and distribution lines and 13 transmission substations. For Fiscal 2008, approximately 52% of sales volume came from residential customers, 35% from commercial customers and 13% from industrial and other customers. Sales of electricity for residential heating purposes accounted for approximately 19% of total sales of electricity during Fiscal 2008.
Sources of Supply
Electric Utility has no owned generation and, as a result, has third-party generation supply contracts in place for substantially all of its expected energy requirements through December 31, 2009. Electric Utility distributes electricity that it purchases from wholesale markets and electricity that customers purchase from other suppliers, if any.
As of September 30, 2008, none of Electric Utility’s customers have selected an alternative electricity generation supplier. Electric Utility expects to continue to provide energy to the great majority of its distribution customers for the foreseeable future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures” for a discussion of risks related to Electric Utility’s supply contracts and see “RISK FACTORS —Supplier defaults may have a negative effect on our operating results.”
Competition
As a result of the Electricity Generation Customer Choice and Competition Act (“ECC Act”), all Pennsylvania retail electric customers have the ability to choose their electric generation supplier. Electric Utility remains the provider of last resort (“POLR”) for its customers who do not choose an alternate electric generation supplier. Electric Utility serves 100% 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. Electricity competes with natural gas, oil, propane and other heating fuels for residential heating purposes.
The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service, have been established in a series of PUC-approved settlements (the “POLR Settlements”). Consistent with the terms of the POLR Settlements, Electric Utility’s total average residential heating customer POLR rates were increased in January 2008 by approximately 5.5% over rates in effect during calendar year 2007. Electric Utility has announced its intent to increase average residential heating customer rates in January 2009 by approximately 1.5% over rates in effect during calendar year 2008. For current rates 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.
Electric Transmission and Wholesale Power Sale Rates
FERC has jurisdiction over the rates and terms and conditions of service of electric transmission facilities used for wholesale or retail choice transactions. Electric Utility owns electric transmission facilities that are within the control area of the PJM Interconnection, LLC (“PJM”) and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM. Electric Utility receives certain revenues collected by PJM, determined under a formulary rate schedule that is adjusted in June of each year to reflect annual changes in Electric Utility’s electric transmission revenue requirements, when its transmission facilities are used by third parties.
FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy. Electric Utility has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates.
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Gas Utility Rates
The most recent general base rate increase for UGI Gas became effective in 1995. In accordance with a statutory mechanism, a rate increase for firm- residential, commercial and industrial customers (“retail core-market”) became effective October 1, 2000 along with a Purchased Gas Cost (“PGC”) variable credit equal to a portion of the margin received from customers served under interruptible rates to the extent such interruptible customers use capacity contracted for by UGI Gas for retail core-market customers.
In an order entered on November 30, 2006, the PUC approved a settlement of the UGIPNG base rate proceeding. The settlement authorized UGIPNG to increase natural gas annual base rates by $12.5 million, or approximately 4.0%, effective December 2, 2006. In addition, the settlement provides UGIPNG the ability to recover up to $1.0 million of additional corporate franchise tax through the state tax adjustment surcharge mechanism.
UGI Gas’ and UGIPNG’s gas service tariffs contain PGC rates applicable to firm retail rate schedules. These PGC rates permit recovery of substantially all of the prudently incurred costs of natural gas that UGI Gas and UGIPNG sell to their customers. PGC rates are reviewed and approved annually by the PUC. UGI Gas and UGIPNG may request quarterly, or, under certain conditions, monthly adjustments to reflect the actual cost of gas. Quarterly adjustments become effective on 1 day’s notice to the PUC and are subject to review during the next annual PGC filing. Each proposed annual PGC rate is required to be filed with the PUC 6 months prior to its effective date. During this period, the PUC holds hearings to determine whether the proposed rate reflects a least-cost fuel procurement policy consistent with the obligation to provide safe, adequate and reliable service. After completion of these hearings, the PUC issues an order permitting the collection of gas costs at levels which meet that standard. The PGC mechanism also provides for an annual reconciliation.
UGI Gas has two PGC rates. PGC (1) is applicable to small, firm, retail core-market customers consisting of the residential and small commercial and industrial classes; PGC (2) is applicable to firm, contractual, high-load factor customers served on three separate rates. In addition, residential customers maintaining a high load factor may qualify for the PGC (2) rate. As described above, UGI Gas’ PGC rates are adjusted to reflect margins, if any, from interruptible rate customers who do not obtain their own pipeline capacity. UGIPNG has one PGC rate applicable to all customers.
Electric Utility Rates
The most recent general base rate increase for Electric Utility became effective in 1996. Electric Utility’s rates were unbundled into distribution, transmission and generation (POLR or “default service”) components in 1998. In accordance with the POLR Settlements, Electric Utility increased POLR rates annually from 2005 through 2008 and may implement a further increase effective January 1, 2009. The increase implemented January 1, 2008 raised total average residential heating customer rates by approximately 5.5% over rates in effect during calendar year 2007. Electric Utility is also permitted to and has entered into multiple-year fixed-rate POLR contracts with certain of its customers.
PUC default service regulations are applicable to Electric Utility’s provision of default service effective January 1, 2010. Electric Utility, consistent with these regulations, acquired a portion of its default service supplies for certain customer groups for the period of January 1, 2010 through December 31, 2012. Electric Utility is waiting for 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 become effective 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 become effective January 1, 2010.
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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.
State Tax Surcharge Clauses
UGI Utilities’ gas and electric service tariffs contain state tax surcharge clauses. The surcharges are recomputed whenever any of the tax rates included in their calculation are changed. These clauses protect UGI Utilities from the effects of increases in most of the Pennsylvania taxes to which it is subject.
Utility Franchises
UGI Utilities and UGIPNG each hold certificates of public convenience issued by the PUC and certain “grandfather rights” predating the adoption of the Pennsylvania Public Utility Code and its predecessor statutes, which each of them believes are adequate to authorize them to carry on their business in substantially all of the territories to which they now render gas or electric service. Under applicable Pennsylvania law, UGI Utilities and UGIPNG also have certain rights of eminent domain as well as the right to maintain their facilities in streets and highways in their territories.
Other Government Regulation
In addition to regulation by the PUC and FERC, the gas and electric utility operations of UGI Utilities are subject to various federal, state and local laws governing environmental matters, occupational health and safety, pipeline safety and other matters. UGI Utilities is subject to the requirements of the federal Resource Conservation and Recovery Act, CERCLA and comparable state statutes with respect to the release of hazardous substances on property owned or operated by UGI Utilities. See Note 10 to the Company’s Consolidated Financial Statements.
Employees
At September 30, 2008, UGI Utilities had approximately 1,200 employees.
ENERGY SERVICES
UGI Energy Services, Inc. and its subsidiaries (collectively, “ESI”) operate the energy-related businesses described below.
Retail Energy Marketing
ESI conducts its energy marketing business under the trade names GASMARK® and POWERMARK®. ESI sells natural gas directly to approximately 13,000 commercial and industrial customers in Pennsylvania, New Jersey, Delaware, Maryland, Virginia, West Virginia, New York, Ohio, North Carolina and the District of Columbia through the use of the transportation systems of 33 utility systems. ESI sells fuel oil and LPG to commercial and industrial customers in Pennsylvania, New Jersey, Maryland, Delaware, New York and Virginia. ESI also sells electricity in New Jersey, Delaware and Maryland.
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The gas marketing business is a high-revenue, low-margin business. A majority of ESI’s commodity sales are made under fixed-price agreements. ESI manages supply cost volatility related to these agreements by (i) entering into exchange-traded natural gas futures contracts which are guaranteed by the New York Mercantile Exchange and have nominal credit risk, (ii) entering into fixed-price supply arrangements with a diverse group of natural gas producers and holders of interstate pipeline capacity, (iii) entering into over-the-counter natural gas derivative arrangements with major international banks and (iv) utilizing supply assets that it owns or manages. ESI also bears the risk for balancing and delivering natural gas to its customers under various pipelines and utility company tariffs. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures.”
Mid-Stream Assets
ESI operates a natural gas liquefaction, storage and vaporization facility in Temple, Pennsylvania, and propane storage and propane-air mixing stations in Bethlehem, Reading, Hunlock Creek, Steelton, and Williamsport, Pennsylvania. It also operates a propane storage and rail trans-shipment terminal in Steelton, Pennsylvania. These assets are used in ESI’s energy peaking business that provides supplemental energy, primarily liquefied natural gas and propane-air mixtures, to gas utilities at times of peak demand. In Fiscal 2008, ESI commenced operations of two new propane-air plants which expanded its overall peaking capacity. ESI also manages natural gas pipeline and storage contracts for UGI Gas.
ESI sells propane to large multi-state retailers, including AmeriGas Partners, and to smaller local dealers throughout Virginia and northeast North Carolina, from its propane import and trans-shipment facility located in Chesapeake, Virginia. ESI also stores butane for customers at its Chesapeake, Virginia facility.
Electric Generation
We have an approximate 6% (102 megawatts) ownership interest in the Conemaugh generating station (“Conemaugh”), a 1,711 megawatt, coal-fired generation station located near Johnstown, Pennsylvania. Conemaugh is owned by a consortium of energy companies and operated by a unit of Reliant Resources, Inc. ESI also owns the Hunlock Station located near Wilkes-Barre, Pennsylvania, which is a 48-megawatt coal-fired facility. The output from these generation assets is sold on the spot market and under fixed-term contracts. We plan to transition the Hunlock Station facility to a natural gas-fueled power plant in the future. ESI has FERC authority to sell power at market-based rates. In Fiscal 2008, ESI completed the design phase for a landfill gas-fueled electric generation plant. The landfill gas plant is scheduled to be completed in the first half of the 2009 fiscal year with generating capacity of 11 megawatts of electricity.
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. As stated above, ESI has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates. ESI also has market-based rate authority for power sales to wholesale customers to the extent that ESI purchases power in excess of its retail customer needs. ESI is also subject to FERC market manipulation rules and enforcement and regulatory powers. See “Gas Utility and Electric Utility Regulation and Rates - FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers.”
The operation of Hunlock Station complies with the air quality standards of the Pennsylvania Department of Environmental Protection (“DEP”) with respect to stack emissions. Under the Federal Water Pollution Control Act, Hunlock Station has a permit from the DEP to discharge water into the North Branch of the Susquehanna River. The federal Clean Air Act Amendments of 1990 impose emissions limitations for certain compounds, including sulfur dioxide and nitrous oxides. Both the Conemaugh Station and the Hunlock Station are in material compliance with these current emission standards. New environmental regulations related to sulfur dioxide allowances and mercury emission standards have recently been enacted by the DEP and will take effect in 2009-2010. ESI is currently assessing the operational impact of compliance with these new regulatory standards.
ESI is subject to various federal, state and local environmental, safety and transportation laws and regulations governing the storage, distribution and transportation of propane and the operation of bulk storage LPG terminals. These laws include, among others, the Resource Conservation and Recovery Act, 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.
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Employees
At September 30, 2008, ESI and its subsidiaries had approximately 200 employees.
HVAC/R
We conduct a heating, ventilation, air-conditioning, refrigeration and electrical contracting service business through UGI HVAC Enterprises, Inc. (“HVAC/R”) serving portions of eastern Pennsylvania and the Mid-Atlantic region, including the Philadelphia suburbs and portions of New Jersey and northern Delaware. This business serves more than 150,000 customers in residential, commercial, industrial and new construction markets. During Fiscal 2008, HVAC/R generated approximately $87 million in revenues and employed approximately 550 people.
BUSINESS SEGMENT INFORMATION
The table stating the amounts of revenues, operating income (loss) and identifiable assets attributable to each of UGI’s reportable business segments, and to the geographic areas in which we operate, for the 2008, 2007 and 2006 fiscal years appears in Note 16 to the Consolidated Financial Statements included in Item 8 of this Report and is incorporated herein by reference.
EMPLOYEES
At September 30, 2008, UGI and its subsidiaries had approximately 9,500 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 five-month peak heating season of November through March and is directly affected by the severity of the winter weather. For example, historically, approximately 55% to 60% of AmeriGas Partners’ annual retail propane volume has been sold during these months and approximately 55% to 60% of our natural gas throughput (the total volume of gas sold to or transported for customers within our distribution system) occurs during these months. Antargaz’ sales volume is similarly seasonal. There can be no assurance that normal winter weather in our market areas will occur in the future.
Our holding company structure could limit our ability to pay dividends or debt service.
We are a holding company whose material assets are the stock of our subsidiaries and interests in joint ventures. Accordingly, we conduct all of our operations through our subsidiaries and joint venture affiliates. Our ability to pay dividends on our common stock and to pay principal and accrued interest on our debt, if any, depends on the payment of dividends to us by our principal subsidiaries, AmeriGas, Inc., UGI Utilities, Inc. and UGI Enterprises, Inc. (including Antargaz). Payments to us by those subsidiaries, in turn, depend upon their consolidated results of operations and cash flows and, in the case of AmeriGas Partners, the provisions of its partnership agreement. The operations of our subsidiaries are affected by conditions beyond our control, including weather, competition in national and international markets we serve, the costs and availability of propane, butane, natural gas, electricity and other energy sources and 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.
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Our profitability is subject to propane pricing and inventory risk.
The retail propane business is a “margin-based” business in which gross profits are dependent upon the excess of the sales price over the propane supply costs. Propane is a commodity, and, as such, its unit price is subject to volatile fluctuations in response to changes in supply or other market conditions. We have no control over these market conditions. Consequently, the unit price of the propane that our subsidiaries and other marketers purchase can change rapidly over a short period of time. Most of our domestic propane product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major U.S. storage points such as Mont Belvieu, Texas or Conway, Kansas. Most of our international propane supply contracts are based on internationally quoted market prices. Because our subsidiaries’ profitability is sensitive to changes in wholesale propane supply costs, it will be adversely affected if we cannot pass on increases in the cost of propane to our customers. Due to competitive pricing in the propane industry, our subsidiaries may not be able to pass on product cost increases to our customers when product costs rise rapidly, or when our competitors do not raise their product prices. Finally, market volatility may cause our subsidiaries to sell propane at less than the price at which they purchased it, which would adversely affect our operating results.
Energy efficiency and technology advances, as well as price induced customer conservation, may result in reduced demand for our energy products and services.
The trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, may reduce the demand for energy products. Prices for propane and natural gas are subject to volatile fluctuations in response to changes in supply and other market conditions. During periods of high energy commodity costs, our prices generally increase which may lead to customer conservation. We cannot predict the materiality of the effect of future conservation measures or the effect that any technological advances in heating, conservation, energy generation or other devices might have on our operations.
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 resulting from, among 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 adversely affect our operating results.
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, electricity and natural gas, a default of one or more of our suppliers under such contracts could cause us to purchase LPG, electricity and natural gas at higher prices which would have a negative impact on our operating results.
Changes in commodity market prices may have a negative effect on our liquidity.
Depending on the terms of our contracts with suppliers and some large customers, 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 or 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, but propane generally enjoys a competitive price advantage over electricity for space heating, water heating and cooking. Fuel oil is also a major competitor of propane and is generally less expensive than propane. Furnaces and appliances that burn propane will not operate on fuel oil and vice versa, and, therefore, a conversion from one fuel to the other requires the installation of new equipment. Our customers generally have an incentive to switch to fuel oil only if fuel oil becomes significantly less expensive than propane. Except for certain industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is generally a less expensive source of energy than propane. The gradual expansion of natural gas distribution systems in our service areas has resulted, and may continue to result, in the availability of natural gas in some areas that previously depended upon propane. 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.
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Our natural gas businesses compete primarily with electricity and fuel oil, and, to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of fuel utilization equipment. There can be no assurance that our natural gas revenues will not be adversely affected by this competition.
Our ability to increase revenues is adversely affected by the maturity of the retail propane industry.
The retail propane industry in the U.S., France and Austria is mature, with only modest growth in total demand for the product foreseen. Given this limited growth, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, our ability to grow within the propane industry is dependent on our ability to acquire other retail distributors and to achieve internal growth, which includes expansion of the AmeriGas Cylinder Exchange and Strategic Accounts programs, as well as the success of our sales and marketing programs designed to attract and retain customers. Any failure to retain and grow our customer base would have an adverse effect on our results.
Our ability to grow our businesses will be adversely affected if we are not successful in making acquisitions or integrating the acquisitions we have made.
One of our strategies is to grow through acquisitions in the United States and in international markets. We may choose to finance future acquisitions with debt, equity, cash or a combination of the three. We can give no assurances that we will find attractive acquisition candidates in the future, that we will be able to acquire such candidates on economically acceptable terms, that 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.
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.
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, Inc., UGI Penn Natural Gas, Inc., or UGI Central Penn Gas, Inc. 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, UGIPNG and UGI Central Penn Gas, Inc. may charge their utility customers, thus impacting the returns that UGI Utilities, UGIPNG, and UGI Central Penn Gas, Inc. may earn on the assets that are dedicated to those operations. UGI Utilities’ subsidiaries, UGIPNG and of UGI Central Penn Gas, Inc., expect to file requests with the PUC to increase base rates that each company charges customers in early 2009. If UGI Utilities, UGIPNG and/or UGI Central Penn Gas, Inc. are required in a rate proceeding to reduce the rates they charge their utility customers, or if UGI Utilities, UGIPNG and/or UGI Central Penn Gas, Inc. are unable to obtain approval for timely rate increases from the PUC, particularly when necessary to cover increased costs, UGI Utilities’, UGIPNG’s and UGI Central Penn Gas, Inc.’s revenue growth will be limited and earnings may decrease.
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Our operations, capital expenditures and financial results may be affected by regulatory changes and/or market responses to global climate change.
There is a growing concern, both nationally and internationally, about climate change and the contribution of greenhouse gas emissions, most notably carbon dioxide, to global warming. In response to this concern, many foreign nations, including the countries in the European Union, have agreed to limit emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” The Kyoto Protocol requires participating countries to reduce its emissions of greenhouse gases to 6% below 1990 levels by 2012. While the United States did not ratify the Kyoto Protocol, there have been numerous federal legislative proposals, as well as the enactment or consideration of various state and local laws, aimed at reducing greenhouse gas emissions.
Increased regulation of greenhouse gas emissions, especially in the electric generation and transportation sectors, could impose significant additional costs on us. While there is currently no federal regulation in the United States that mandates the reduction of greenhouse gas emissions, it is likely that legislation governing such emissions will be enacted in fiscal year 2009 or fiscal year 2010. Until legislation is passed in the United States, it will remain unclear as to (i) what industry sectors would be impacted, (ii) when compliance would be required, (iii) the magnitude of the greenhouse gas emissions reductions that would be required and (iv) the costs and opportunities associated with compliance. At this time, we cannot predict the effect that domestic and international 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. We believe that we are adequately insured for claims in excess of our self-insurance; however, certain types of damages, such as punitive damages and penalties, if any, may not be covered by insurance. There can be no assurance that our insurance will be adequate to protect us from all material expenses related to pending and future claims or that such levels of insurance will be available in the future at economical prices.
We may be unable to respond effectively to competition, which may adversely affect our operating results.
We may be unable to timely respond to changes within the energy and utility sectors that may result from regulatory initiatives to further increase competition within our industry. Such regulatory initiatives may create opportunities for additional competitors to enter our markets and, as a result, we may be unable to maintain our revenues or continue to pursue our current business strategy.
Our net income will decrease if we are required to incur additional costs to comply with new governmental safety, health, transportation and environmental regulations.
We are subject to extensive and changing international, federal, state and local safety, health, transportation and environmental laws and regulations governing the storage, distribution and transportation of our energy products.
New regulations, or a change in the interpretation of existing regulations, could result in increased expenditures. In addition, for many of our operations, we are required to obtain permits from regulatory authorities. Failure to comply with these permits or applicable laws could result in civil and criminal fines or the cessation of the operations in violation. Governmental regulations and policies in the United States and Europe may provide for subsidies or incentives to customers who use alternative fuels instead of carbon fuels. These subsidies and incentives may result in reduced demand for our energy products and services.
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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 be recovered in future 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.
The expansion of our international business means that we will face increased risks, which may negatively affect our business results.
Our acquisition of Antargaz in March of 2004 significantly increased our international presence. As we continue to add new subsidiaries and enter into new joint ventures in countries around the world, we face risks in doing business abroad that we do not face domestically. Certain aspects inherent in transacting business internationally could negatively impact our operating results, including:
| • | costs and difficulties in staffing and managing international operations; | ||
| • | tariffs and other trade barriers; | ||
| • | difficulties in enforcing contractual rights; | ||
| • | longer payment cycles; | ||
| • | local political and economic conditions; | ||
| • | potentially adverse tax consequences, including restrictions on repatriating earnings and the threat of “double taxation”; | ||
| • | fluctuations in currency exchange rates, which can affect demand and increase our costs; and | ||
| • | regulatory requirements and changes in regulatory requirements, including French and EU competition laws that may adversely affect the terms of contracts with customers, and stricter regulations applicable to the storage and handling of LPG. For additional information see “LEGAL PROCEEDINGS” below. |
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
With the exception of the matter set forth below and those matters set forth in Note 10 to the Company’s Consolidated Financial Statements, 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.
Antargaz Competition Authority Matter. In June 2005, officials from France’s General Division of Competition, Consumption and Fraud Punishment (“DGCCRF”) conducted an unannounced inspection of, and obtained documents from, Antargaz’ headquarters building. Management believes that the DGCCRF performed similar unannounced inspections and document seizures at the locations of other distributors of LPG in France, as well as the industry association, Comite Francais du Butane et du Propane (“CFBP”). The DGCCRF apparently sought evidence of unlawful anti-competitive activities affecting the packaged LPG (i.e., cylinder) business in northern France.
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Antargaz did not have any further contact with the DGCCRF regarding this matter until February 2007, when it received a letter from the DGCCRF requesting documents and information relating to Antargaz’ pricing policies and practices. In March 2007, and again in August 2007, the DGCCRF requested additional information from Antargaz and three joint ventures in which it participates. Based on these requests, it appears that the DGCCRF has expanded the scope of its investigation to include both bulk and cylinder markets throughout France. In July 2008, the Competition Council interviewed Mr. Varagne, as President of Antargaz and President of the CFBP, about competitive practices in the LPG cylinder market in France.
France’s Conseil de la Concurrence (“Competition Council”) is conducting a related investigation regarding alleged concerted behavior among certain distributors of LPG in France. We believe one of the companies under investigation has applied for leniency, pursuant to the French law that allows a company to offer evidence of anti-competitive behavior in exchange for partial or total amnesty from financial sanctions. A company seeking leniency may present testimony or other evidence of anti-competitive activities adverse to Antargaz’ interests. As part of any investigation, the Competition Council and the DGCCRF may uncover information from other sources, including customers, suppliers or employees of Antargaz and other LPG companies, that may be adverse to Antargaz’ interests.
We do not believe Antargaz is in violation of France’s competition laws. Management intends to continue to cooperate with the DGCCRF and the Competition Council investigations. At this time, the French authorities have not made any claim against Antargaz. However, in the event a claim is made against Antargaz and it is found to have violated the competition laws in France, it would be subject to civil penalties up to a maximum of 10% of the total annual revenues of UGI.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the last fiscal quarter of Fiscal 2008.
EXECUTIVE OFFICERS
Information regarding our executive officers is included in Part III of this Report and is incorporated in Part I by reference.
PART II:
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Market Information
Our Common Stock is traded on the New York 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 inTheWallStreetJournal for each full quarterly period within the two most recent fiscal years:
| 2008 Fiscal Year | High | Low | ||||||
| 4th Quarter | $ | 28.23 | $ | 25.17 | ||||
| 3rd Quarter | 28.71 | 25.25 | ||||||
| 2nd Quarter | 27.24 | 24.67 | ||||||
| 1st Quarter | 27.79 | 24.99 | ||||||
| 2007 Fiscal Year | High | Low | ||||||
| 4th Quarter | $ | 28.30 | $ | 22.75 | ||||
| 3rd Quarter | 29.63 | 25.77 | ||||||
| 2nd Quarter | 27.94 | 24.10 | ||||||
| 1st Quarter | 29.00 | 24.26 | ||||||
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Dividends
Quarterly dividends on our Common Stock were paid in Fiscal 2008 and Fiscal 2007 as follows:
| 2008 Fiscal Year | Amount | |||
| 4th Quarter | $ | 0.19250 | ||
| 3rd Quarter | 0.18500 | |||
| 2nd Quarter | 0.18500 | |||
| 1st Quarter | 0.18500 | |||
| 2007 Fiscal Year | Amount | |||
| 4th Quarter | $ | 0.18500 | ||
| 3rd Quarter | 0.17625 | |||
| 2nd Quarter | 0.17625 | |||
| 1st Quarter | 0.17625 | |||
Record Holders
On November 3, 2008, UGI had 6,393 holders of record of Common Stock.
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ITEM 6. SELECTED FINANCIAL DATA
| Year Ended September 30, | ||||||||||||||||||||
| (Millions of dollars, except per share amounts) | 2008 | 2007 | 2006 | 2005 | 2004 | |||||||||||||||
FOR THE PERIOD: | ||||||||||||||||||||
Income statement data: | ||||||||||||||||||||
| Revenues | $ | 6,648.2 | $ | 5,476.9 | $ | 5,221.0 | $ | 4,888.7 | $ | 3,784.7 | ||||||||||
| Net income | $ | 215.5 | $ | 204.3 | $ | 176.2 | $ | 187.5 | $ | 111.6 | ||||||||||
| Earnings per common share: | ||||||||||||||||||||
| Basic net income | $ | 2.01 | $ | 1.92 | $ | 1.67 | $ | 1.81 | $ | 1.18 | ||||||||||
| Diluted net income | $ | 1.99 | $ | 1.89 | $ | 1.65 | $ | 1.77 | $ | 1.15 | ||||||||||
| Cash dividend declared per common share | $ | 0.755 | $ | 0.723 | $ | 0.690 | $ | 0.650 | $ | 0.598 | ||||||||||
AT PERIOD END: | ||||||||||||||||||||
Balance sheet data: | ||||||||||||||||||||
| Total assets | $ | 5,685.0 | $ | 5,502.7 | $ | 5,080.5 | $ | 4,571.5 | $ | 4,242.6 | ||||||||||
| Capitalization: | ||||||||||||||||||||
| Debt: | ||||||||||||||||||||
| Bank loans — UGI Utilities | $ | 57.0 | $ | 190.0 | $ | 216.0 | $ | 81.2 | $ | 60.9 | ||||||||||
| Bank loans — Antargaz | 70.4 | — | — | — | — | |||||||||||||||
| Bank loans — other | 9.0 | 8.9 | 9.4 | 16.2 | 17.2 | |||||||||||||||
| Long-term debt (including current maturities): | ||||||||||||||||||||
| AmeriGas Propane | 933.4 | 933.1 | 933.7 | 913.5 | 901.4 | |||||||||||||||
| Antargaz | 537.4 | 544.9 | 483.5 | 431.1 | 474.5 | |||||||||||||||
| UGI Utilities | 532.0 | 512.0 | 512.0 | 237.0 | 217.2 | |||||||||||||||
| Other | 66.3 | 63.5 | 67.7 | 62.9 | 76.9 | |||||||||||||||
| Total debt | 2,205.5 | 2,252.4 | 2,222.3 | 1,741.9 | 1,748.1 | |||||||||||||||
| Minority interests, principally in AmeriGas Partners | 159.2 | 192.2 | 139.5 | 206.3 | 178.4 | |||||||||||||||
| UGI Utilities preferred shares subject to mandatory redemption | — | — | — | — | 20.0 | |||||||||||||||
| Common stockholders’ equity | 1,417.7 | 1,321.9 | 1,099.6 | 997.6 | 834.1 | |||||||||||||||
| Total capitalization | $ | 3,782.4 | $ | 3,766.5 | $ | 3,461.4 | $ | 2,945.8 | $ | 2,780.6 | ||||||||||
Ratio of capitalization: | ||||||||||||||||||||
| Total debt | 58.3 | % | 59.8 | % | 64.2 | % | 59.1 | % | 62.9 | % | ||||||||||
| Minority interests, principally in AmeriGas Partners | 4.2 | % | 5.1 | % | 4.0 | % | 7.0 | % | 6.4 | % | ||||||||||
| UGI Utilities preferred shares subject to mandatory redemption | — | — | — | — | 0.7 | % | ||||||||||||||
| Common stockholders’ equity | 37.5 | % | 35.1 | % | 31.8 | % | 33.9 | % | 30.0 | % | ||||||||||
| 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | |||||||||||
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Business Overview
UGI Corporation (“UGI”) is a holding company that, through subsidiaries and joint-venture affiliates, distributes and markets energy products and related services. We are a domestic and international distributor of propane and butane which are liquefied petroleum gases (“LPG”); a provider of natural gas and electric service through regulated local distribution utilities; a generator of electricity through our ownership interests in Pennsylvania electric generation facilities; a regional marketer of energy commodities; and a regional provider of heating, ventilation, air conditioning, refrigeration and electrical services.
We conduct a national propane distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”) and its principal operating subsidiaries AmeriGas Propane, L.P. and AmeriGas Eagle Propane, L.P. At September 30, 2008, UGI, through its wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”), held an approximate 44% effective interest in AmeriGas Partners. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.”
Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries (1) conducts an LPG distribution business in France; (2) conducts LPG distribution businesses and participates in an LPG joint-venture business (“ZLH”) in central and eastern Europe (collectively, “Flaga”); and (3) participates in an LPG joint-venture business in the Nantong region of China. Our LPG distribution business in France is conducted through Antargaz, an operating subsidiary of AGZ Holding (“AGZ”), and its operating subsidiaries (collectively, “Antargaz”). We refer to our foreign operations collectively as “International Propane.”
Our natural gas and electric distribution utility businesses are conducted through UGI Utilities, Inc. and its subsidiary, UGI Penn Natural Gas, Inc. (“UGIPNG”). The term “UGI Utilities” is used herein as an abbreviated reference to UGI Utilities, Inc., or UGI Utilities, Inc. and its subsidiaries collectively, including UGIPNG. UGI Utilities owns and operates (1) natural gas distribution utilities in eastern and northeastern Pennsylvania (“UGI Gas” and “PNG Gas,” respectively) and (2) an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Gas and PNG Gas are collectively referred to herein as “Gas Utility.” Gas Utility and Electric Utility are subject to regulation by the Pennsylvania Public Utility Commission (“PUC”). On August 24, 2006, UGI Utilities, Inc., through UGIPNG, acquired the natural gas utility business of PG Energy, an operating division of Southern Union Company (the “PG Energy Acquisition”). The acquired natural gas distribution business now comprises PNG Gas. On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL Gas Utilities Corporation (the “CPG Acquisition”), now named UGI Central Penn Gas, Inc. (“CPG”) (see “Subsequent Event — Acquisition of PPL Gas Utilities Corporation and Penn Fuel Propane, LLC and Partnership Sale of Storage Facility” below). Because the CPG Acquisition occurred after the end of Fiscal 2008, it did not directly affect the accompanying financial statements.
Through other subsidiaries, Enterprises also conducts an energy marketing business primarily in the eastern United States (collectively, “Energy Services”). Energy Services’ wholly owned subsidiary, UGI Development Company (“UGID”), owns and operates a 48-megawatt coal-fired electric generation station located in northeastern Pennsylvania and owns an approximate 6% interest in a 1,711-megawatt coal-fired electric generation station located in western Pennsylvania. In addition, Energy Services’ wholly owned subsidiary UGI Asset Management, Inc., through its subsidiary Atlantic Energy, Inc. (collectively, “Asset Management”), owns a propane storage terminal located in Chesapeake, Virginia. Energy Services also owns and operates a natural gas liquefaction, storage and vaporization facility, and propane storage and propane-air mixing assets. Through other subsidiaries, Enterprises owns and operates heating, ventilation, air-conditioning, refrigeration and electrical contracting services businesses in the Middle Atlantic states (“HVAC/R”).
This financial review should be read in conjunction with our Consolidated Financial Statements and Notes to Consolidated Financial Statements including the reportable segment information included in Note 16.
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Executive Overview
Our financial results over the three fiscal years ended September 30, 2008 (“Fiscal 2008,” “Fiscal 2007” and “Fiscal 2006,” respectively) reflect the benefits of our commitment to grow through acquisitions and capital projects, as well as through our continued focus on executing our strategies in our business units. In Fiscal 2006, our growth transactions included the PG Energy Acquisition by UGI Utilities and Flaga’s formation of ZLH which expanded our International Propane operations into eastern Europe. In Fiscal 2007, the Partnership acquired the retail propane businesses of All Star Gas Corporation and Shell Gas (LPG) USA. In Fiscal 2008 and Fiscal 2007, Energy Services added peaking storage assets to its portfolio of midstream assets. On October 1, 2008, we acquired the stock of CPG from PPL Corporation which expanded our natural gas distribution utility and retail propane businesses in Pennsylvania.
Because most of our businesses sell energy products used in large part for heating purposes, our results are significantly influenced by temperatures in our service territories, particularly during the peak-heating season months of November through March. As a result, our earnings are generally higher in the first and second fiscal quarters. In addition, high and volatile commodity prices like those experienced by our domestic and international businesses over the last several years and weak economic conditions can result in lower customer consumption and increased competitive pressures in certain markets.
Net income in Fiscal 2008 increased to $215.5 million from $204.3 million in the prior year principally as a result of improved Energy Services and U.S. dollar-denominated International Propane results. Energy Services experienced higher total margin in Fiscal 2008 particularly from greater income from peaking supply and storage management services and higher total electric generation margin. During Fiscal 2008, temperatures in our International Propane operations were warmer than normal but much colder than the record-setting warm temperatures experienced during Fiscal 2007. In our International Propane operations, the beneficial effects from the weather-related increase in volumes were offset by a decline in total average retail unit margin due to significantly higher LPG commodity costs and increased competition in certain customer segments at Antargaz.
Although Flaga’s results, including those of ZLH, improved in Fiscal 2008 due in large part to the colder weather, ZLH continued to experience the effects on sales volumes of customer conservation and competition from other suppliers and alternative fuels caused in large part by high and increasing LPG commodity costs. AmeriGas Propane’s sales volumes were also affected by price-induced customer conservation due to extraordinarily high propane product costs in the U.S. Additionally, each of our domestic businesses and, to a lesser extent, our International Propane operations were negatively affected by general economic conditions during Fiscal 2008.
The U.S. dollar was weaker versus the euro in Fiscal 2008 than in Fiscal 2007. Although the weaker dollar resulted in higher translated International Propane operating results, the effects of the weaker dollar on reported International Propane net income were substantially offset by the effects of Fiscal 2008 losses on forward currency contracts used to hedge purchases of dollar-denominated LPG.
Looking ahead, we expect that our Fiscal 2009 financial results will be significantly influenced by, among other things, heating-season temperatures in our domestic and international service territories, the effects of commodity prices on customer consumption of our products and competition in the markets we serve. The severity and duration of the weak U.S. economy and weak economies in France and eastern and central Europe may affect consumption of energy products in the markets we serve. Notwithstanding these economic challenges, in order to continue our strategy of growing our businesses in markets in which we have core competencies, we expect to continue to pursue growth through acquisitions and internal growth initiatives, extend our presence in the markets we serve with new and innovative products and services, and control our operating costs throughout the organization.
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Results of Operations
The following analyses compare the Company’s results of operations for (1) Fiscal 2008 with Fiscal 2007 and (2) Fiscal 2007 with Fiscal 2006.
Fiscal 2008 Compared with Fiscal 2007
Consolidated Results
Consolidated Results
| Variance- Favorable | ||||||||||||||||||||||||
| 2008 | 2007 | (Unfavorable) | ||||||||||||||||||||||
| % of | Net | % of | Net | |||||||||||||||||||||
| Net | Total Net | Income | Total Net | Income | % | |||||||||||||||||||
| (Millions of dollars) | Income | Income | (Loss) | Income | (Loss) | Change | ||||||||||||||||||
| AmeriGas Propane | $ | 43.9 | 20.4 | % | $ | 53.2 | 26.0 | % | $ | (9.3 | ) | (17.5 | )% | |||||||||||
| International Propane | 52.3 | 24.3 | % | 44.9 | 22.0 | % | 7.4 | 16.5 | % | |||||||||||||||
| Gas Utility | 60.3 | 28.0 | % | 59.0 | 28.9 | % | 1.3 | 2.2 | % | |||||||||||||||
| Electric Utility | 13.1 | 6.1 | % | 13.7 | 6.7 | % | (0.6 | ) | (4.4 | )% | ||||||||||||||
| Energy Services | 45.3 | 21.0 | % | 34.5 | 16.9 | % | 10.8 | 31.3 | % | |||||||||||||||
| Corporate & Other | 0.6 | 0.2 | % | (1.0 | ) | (0.5 | )% | 1.6 | N.M. | |||||||||||||||
| Total | $ | 215.5 | 100.0 | % | $ | 204.3 | 100.0 | % | $ | 11.2 | 5.5 | % | ||||||||||||
N.M. — Variance is not meaningful.
Highlights — Fiscal 2008 versus Fiscal 2007
| • | Energy Services Fiscal 2008 results benefited from greater income from peaking supply and storage management services and higher electric generation margin. |
| • | Fiscal 2008 International Propane results improved driven by a return to more normal weather compared with the record-setting warm weather experienced in Fiscal 2007. |
| • | Significant increases in LPG cost during most of Fiscal 2008 caused all propane businesses to experience increased conservation and certain of our International Propane business units to experience modest unit margin reductions. |
| • | AmeriGas Propane total margin was higher in Fiscal 2008 despite the effects of price-induced customer conservation on volumes sold. |
| Increase | ||||||||||||||||
| AmeriGas Propane | 2008 | 2007 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 2,815.2 | $ | 2,277.4 | $ | 537.8 | 23.6 | % | ||||||||
| Total margin (a) | $ | 906.9 | $ | 840.2 | $ | 66.7 | 7.9 | % | ||||||||
| Partnership EBITDA (b) | $ | 313.0 | $ | 338.7 | $ | (25.7 | ) | (7.6 | )% | |||||||
| Operating income | $ | 235.0 | $ | 265.8 | $ | (30.8 | ) | (11.6 | )% | |||||||
| Retail gallons sold (millions) | 993.2 | 1,006.7 | (13.5 | ) | (1.3 | )% | ||||||||||
| Degree days — % warmer than normal (c) | 3.4 | % | 6.5 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane reportable segment (see Note 16 to Consolidated Financial Statements). | |
| (c) | Deviation from average heating degree days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska. |
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Based upon heating degree-day data, average temperatures in AmeriGas Propane’s service territories were 3.4% warmer than normal in Fiscal 2008 compared with temperatures that were 6.5% warmer than normal in Fiscal 2007. Notwithstanding the slightly colder Fiscal 2008 weather and the full year benefits of acquisitions made in Fiscal 2007, retail gallons sold were slightly lower reflecting, among other things, customer conservation in response to increasing propane product costs and a weak economy. The average wholesale propane cost at Mont Belvieu, Texas, one of the major LPG supply points in the U.S., increased nearly 50% during Fiscal 2008 over the average cost during the same period last year.
Retail propane revenues increased $480.7 million in Fiscal 2008 reflecting a $507.0 million increase due to the higher average selling prices partially offset by a $26.3 million decrease as a result of the lower retail volumes sold. Wholesale propane revenues increased $47.8 million in Fiscal 2008 reflecting a $55.1 million increase from higher average wholesale selling prices partially offset by a $7.3 million decrease from lower wholesale volumes sold. Other revenues increased $9.3 million reflecting in large part higher fee income. Total cost of sales increased $471.1 million to $1,908.3 million in Fiscal 2008 reflecting higher propane product costs.
Total margin was $66.7 million greater in Fiscal 2008 principally reflecting higher average propane margin per retail gallon sold and, to a much lesser extent, higher fee income.
Partnership EBITDA in Fiscal 2008 was $313.0 million compared to EBITDA of $338.7 million in Fiscal 2007. Fiscal 2007 EBITDA includes $46.1 million resulting from the sale of the Partnership’s Arizona storage facility. Excluding the effects of this gain in Fiscal 2007, EBITDA in Fiscal 2008 increased $20.4 million over Fiscal 2007 principally reflecting the previously mentioned increase in total margin partially offset by a $47.9 million increase in operating and administrative expenses. The increased operating expenses reflect expenses associated with acquisitions, increased vehicle fuel and maintenance expenses, greater general insurance expense and, to a lesser extent, higher uncollectible accounts expenses largely attributable to the higher revenues.
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AmeriGas Propane’s operating income decreased $30.8 million in Fiscal 2008 reflecting the lower EBITDA and higher depreciation and amortization expense resulting from the full-year effects of Fiscal 2007 propane business acquisitions and plant and equipment expenditures.
| Increase | ||||||||||||||||
| International Propane | 2008 | 2007 | (Decrease) | |||||||||||||
| (Millions of euros) | ||||||||||||||||
| Revenues | € | 749.8 | € | 602.4 | € | 147.4 | 24.5 | % | ||||||||
| Total margin (a) | € | 314.9 | € | 309.8 | € | 5.1 | 1.6 | % | ||||||||
| Operating income | € | 70.4 | € | 73.3 | € | (2.9 | ) | (4.0 | )% | |||||||
| Income before income taxes | € | 48.8 | € | 51.4 | € | (2.6 | ) | (5.1 | )% | |||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,124.8 | $ | 800.4 | $ | 324.4 | 40.5 | % | ||||||||
| Total margin (a) | $ | 472.9 | $ | 411.8 | $ | 61.1 | 14.8 | % | ||||||||
| Operating income | $ | 106.8 | $ | 94.5 | $ | 12.3 | 13.0 | % | ||||||||
| Income before income taxes | $ | 73.0 | $ | 64.1 | $ | 8.9 | 13.9 | % | ||||||||
| Antargaz retail gallons sold (millions) | 292.6 | 269.1 | 23.5 | 8.7 | % | |||||||||||
| Degree days — % warmer than normal (b) | 4.1 | % | 21.1 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30 locations in our French service territory. |
Based upon heating degree-day data, temperatures in Antargaz’ service territory were approximately 4.1% warmer than normal during Fiscal 2008 compared with temperatures that were approximately 21.1% warmer than normal during Fiscal 2007. Temperatures in Flaga’s service territory were also warmer than normal and significantly colder than the prior year. Principally as a result of the colder weather, Antargaz’ retail volumes sold increased to 292.6 million gallons in Fiscal 2008 from 269.1 million gallons in Fiscal 2007. Flaga also recorded higher retail gallons sold in Fiscal 2008. The beneficial volume effects on Antargaz resulting from the colder weather were partially offset by customer conservation in response to substantially higher LPG commodity costs, the loss of a low-margin industrial customer and a weaker economy. The average wholesale price for propane in northwest Europe during Fiscal 2008 was nearly 35% higher than such average price in Fiscal 2007.
During Fiscal 2008, the average currency translation rate was $1.51 per euro compared to a rate of $1.34 during Fiscal 2007. The effects of the weaker dollar on year-over-year International Propane net income were substantially offset, however, by the impact of losses on forward currency contracts used to purchase dollar denominated LPG.
International propane euro-based revenues increased€147.4 million principally reflecting higher Antargaz and Flaga average selling prices during Fiscal 2008 and the higher Antargaz and Flaga retail volumes sold. International Propane’s total cost of sales increased to€434.9 million in Fiscal 2008 from€292.6 million in Fiscal 2007, largely reflecting the higher per-unit LPG commodity costs, the greater volumes sold and, to a much lesser extent, higher losses on forward currency contracts.
International Propane total margin increased€5.1 million or 1.6% in Fiscal 2008 reflecting the effects of the greater retail sales of LPG substantially offset by a decline in average retail unit margin per gallon primarily due to the significantly higher LPG commodity costs and increased competition in certain customer segments at Antargaz. In U.S. dollars, total margin increased $61.1 million or 14.8% principally reflecting the effects of the weaker dollar on translated euro base-currency revenues and cost of sales.
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International Propane euro-based operating income decreased€2.9 million principally reflecting the previously mentioned€5.1 million increase in total margin more than offset by higher operating and administrative expenses, due in large part to the effects of the increased sales activity and higher fuel costs, and greater depreciation from plant and equipment additions. On a U.S. dollar basis, operating income increased $12.3 million as the previously-mentioned $61.1 million increase in total margin was substantially offset by higher U.S. dollar denominated operating and administrative expenses and depreciation and amortization expense. Euro-based income before income taxes was€2.6 million lower than last year primarily reflecting the lower operating income. In U.S. dollars, income before income taxes was $8.9 million higher than the prior year reflecting the higher operating income slightly offset by greater U.S. dollar translated interest expense. Although Flaga’s results, including those of ZLH, improved in Fiscal 2008 due in large part to the colder weather, ZLH continued to experience the effects on sales volumes of customer conservation and competition from alternative fuels and other suppliers caused in large part by high and increasing LPG commodity costs.
| Gas Utility | 2008 | 2007 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,138.3 | $ | 1,044.9 | $ | 93.4 | 8.9 | % | ||||||||
| Total margin (a) | $ | 307.2 | $ | 303.4 | $ | 3.8 | 1.3 | % | ||||||||
| Operating income | $ | 137.6 | $ | 136.6 | $ | 1.0 | 0.7 | % | ||||||||
| Income before income taxes | $ | 100.5 | $ | 96.7 | $ | 3.8 | 3.9 | % | ||||||||
| System throughput — billions of cubic feet (“bcf”) | 133.7 | 131.8 | 1.9 | 1.4 | % | |||||||||||
| Degree days — % warmer than normal (b) | 5.5 | % | 4.7 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Deviation from average heating degree days for the 30-year period 1975-2004 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory. |
Temperatures in the Gas Utility service territory based upon heating degree days were 5.5% warmer than normal in Fiscal 2008 compared with temperatures that were 4.7% warmer than normal in Fiscal 2007. Total distribution system throughput increased 1.9 bcf in Fiscal 2008 principally reflecting greater interruptible delivery service volumes (principally volumes associated with low margin cogeneration customers) and an increase in the number of Gas Utility core market customers partially offset by lower average usage per customer due in large part to price-induced customer conservation and a weak economy. Gas Utility’s core market customers principally comprise 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 and industrial (“core market transportation”) customers who purchase their gas from alternate suppliers.
Gas Utility revenues increased $93.4 million in Fiscal 2008 principally reflecting a $57.4 million increase in revenues from off-system sales and the effects of higher average purchased gas costs (“PGC”) rates on retail core-market revenues. 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 sales was $831.1 million in Fiscal 2008 compared with $741.5 million in Fiscal 2007 principally reflecting the greater off-system sales and the increase in average retail core-market PGC rates.
Gas Utility total margin increased $3.8 million in Fiscal 2008 primarily reflecting modest increases in interruptible delivery service and core market total margin.
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The increase in Gas Utility operating income principally reflects the previously mentioned $3.8 million increase in total margin and a $5.3 million increase in other income partially offset by modestly higher operating and administrative expenses. The higher other income reflects in large part greater storage contract fees and a $2.2 million postretirement benefit plan curtailment gain. The increase in operating and administrative expenses includes, among other things, higher environmental legal costs and greater uncollectible accounts expense. Gas Utility income before income taxes also reflects lower interest expense on bank loans.
| Increase | ||||||||||||||||
| Electric Utility | 2008 | 2007 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 139.2 | $ | 121.9 | $ | 17.3 | 14.2 | % | ||||||||
| Total margin (a) | $ | 47.0 | $ | 47.3 | $ | (0.3 | ) | (0.6 | )% | |||||||
| Operating income | $ | 24.4 | $ | 26.0 | $ | (1.6 | ) | (6.2 | )% | |||||||
| Income before income taxes | $ | 22.4 | $ | 23.6 | $ | (1.2 | ) | (5.1 | )% | |||||||
| Distribution sales — millions of kilowatt hours (“gwh”) | 1,004.4 | 1,010.6 | (6.2 | ) | (0.6 | )% | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. gross receipts taxes of $7.9 million and $6.8 million in Fiscal 2008 and Fiscal 2007, 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 2008 were about equal to Fiscal 2007 on heating-season weather that was slightly warmer and cooling-season weather that was slightly cooler. Electric Utility revenues increased $17.3 million principally as a result of higher Provider of Last Resort (“POLR”) rates. Electric Utility cost of sales increased to $84.3 million in Fiscal 2008 from $67.8 million in the prior year principally reflecting higher per-unit purchased power costs.
Electric Utility total margin in Fiscal 2008 was about equal to Fiscal 2007 reflecting the effects of the higher POLR rates offset principally by the higher per-unit purchased power costs and higher revenue-related taxes.
The decrease in Fiscal 2008 Electric Utility operating income reflects slightly higher operating and administrative costs including higher system maintenance and uncollectible accounts expense. Income before income taxes reflects the lower operating income partially offset by lower interest expense on bank loans.
| Energy Services | 2008 | 2007 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,619.5 | $ | 1,336.1 | $ | 283.4 | 21.2 | % | ||||||||
| Total margin (a) | $ | 124.1 | $ | 100.9 | $ | 23.2 | 23.0 | % | ||||||||
| Operating income | $ | 77.3 | $ | 57.4 | $ | 19.9 | 34.7 | % | ||||||||
| Income before income taxes | $ | 77.3 | $ | 57.4 | $ | 19.9 | 34.7 | % | ||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Notwithstanding retail gas volumes in Fiscal 2008 that were approximately equal to the prior-year period, Energy Services revenues increased $283.4 million principally reflecting the effects of higher commodity costs for natural gas and propane, higher electricity spot-market and fixed contract prices, and higher revenues from peaking supply services.
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Total margin from Energy Services was $23.2 million higher in Fiscal 2008 reflecting greater total margin from peaking supply and storage management services, due in part to the expansion of peaking facilities and higher peaking rates charged, and higher electric generation margin resulting in large part from higher spot-market and fixed contract prices for electricity in Fiscal 2008 compared with Fiscal 2007. The increase in Energy Services’ operating income and income before income taxes in Fiscal 2008 principally reflects the previously mentioned $23.2 million increase in total margin partially offset by slightly higher operating and administrative expenses.
Interest Expense and Income Taxes.Consolidated interest expense increased to $142.5 million in Fiscal 2008 from $139.6 million in Fiscal 2007 principally due to higher interest expense associated with greater Partnership short-term borrowings to fund increases in working capital principally as a result of higher commodity prices for propane during Fiscal 2008 and the effects of foreign exchange on International Propane interest expense. Our effective income tax rate in Fiscal 2008 was comparable to our rate in Fiscal 2007.
Fiscal 2007 Compared with Fiscal 2006
Consolidated Results
Consolidated Results
| Variance- Favorable | ||||||||||||||||||||||||
| 2007 | 2006 | (Unfavorable) | ||||||||||||||||||||||
| Net | % of | % of | ||||||||||||||||||||||
| Income | Total Net | Net | Total Net | Net | % | |||||||||||||||||||
| (Millions of dollars) | (Loss) | Income | Income | Income | Income | Change | ||||||||||||||||||
| AmeriGas Propane | $ | 53.2 | 26.0 | % | $ | 25.1 | 14.2 | % | $ | 28.1 | 112.0 | % | ||||||||||||
| International Propane | 44.9 | 22.0 | % | 67.1 | 38.1 | % | (22.2 | ) | (33.1 | )% | ||||||||||||||
| Gas Utility | 59.0 | 28.9 | % | 38.1 | 21.6 | % | 20.9 | 54.9 | % | |||||||||||||||
| Electric Utility | 13.7 | 6.7 | % | 10.5 | 6.0 | % | 3.2 | 30.5 | % | |||||||||||||||
| Energy Services | 34.5 | 16.9 | % | 31.3 | 17.8 | % | 3.2 | 10.2 | % | |||||||||||||||
| Corporate & Other | (1.0 | ) | (0.5 | )% | 4.1 | 2.3 | % | (5.1 | ) | N.M. | ||||||||||||||
| Total | $ | 204.3 | 100.0 | % | $ | 176.2 | 100.0 | % | $ | 28.1 | 15.9 | % | ||||||||||||
N.M. — Variance is not meaningful.
Highlights — Fiscal 2007 versus Fiscal 2006
| • | The full-year benefit of the PG Energy Acquisition completed in August 2006 increased Fiscal 2007 net income from our Gas Utility. |
| • | AmeriGas Propane operating income benefited from a $46.1 million gain on the sale of its Arizona LPG storage facility adding $12.5 million to UGI net income. |
| • | Our European International Propane operations experienced record-setting warm temperatures which reduced volumes and margin and increased competitive pressures in the markets they serve. |
| • | Greater average unit margins and sales volumes from AmeriGas Propane and Energy Services increased domestic operations’ results in Fiscal 2007. |
| • | New POLR rates effective January 2007 increased earnings from our Electric Utility. |
| • | Our effective income tax rate in Fiscal 2007 was higher than in Fiscal 2006 as the Fiscal 2006 effective tax rate reflected management’s lower estimate of taxes to be paid associated with planned repatriation of foreign earnings. |
| • | Absence of losses recorded in Fiscal 2006 associated with debt extinguishments were offset by the absence of the gain recorded in Fiscal 2006 from the sale of our investment in Hunlock Creek Energy Ventures. |
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| AmeriGas Propane | 2007 | 2006 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 2,277.4 | $ | 2,119.3 | $ | 158.1 | 7.5 | % | ||||||||
| Total margin (a) | $ | 840.2 | $ | 775.5 | $ | 64.7 | 8.3 | % | ||||||||
| Partnership EBITDA (b) | $ | 338.7 | $ | 237.9 | $ | 100.8 | 42.4 | % | ||||||||
| Operating income | $ | 265.8 | $ | 184.1 | $ | 81.7 | 44.4 | % | ||||||||
| Retail gallons sold (millions) | 1,006.7 | 975.2 | 31.5 | 3.2 | % | |||||||||||
| Degree days — % warmer than normal (c) | 6.5 | % | 10.2 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane reportable segment (see Note 16 to Consolidated Financial Statements). | |
| (c) | Deviation from average heating degree days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska. |
Temperatures in the Partnership’s service territories based upon heating degree days during Fiscal 2007 were 6.5% warmer than normal compared with temperatures that were 10.2% warmer than normal during Fiscal 2006. Retail propane volumes sold increased approximately 3.2% reflecting greater demand attributable to the colder weather and the effects of higher sales in our AmeriGas Cylinder Exchange program.
Retail propane revenues increased $142.5 million in Fiscal 2007 reflecting an $83.8 million increase due to higher average selling prices and a $58.7 million increase due to the higher volumes sold. Wholesale propane revenues decreased slightly reflecting a $2.6 million decrease due to lower volumes sold largely offset by a $2.5 million increase due to higher average selling prices. In Fiscal 2007, our average retail propane product cost per retail gallon sold was approximately 4% higher than in Fiscal 2006 resulting in higher year-over-year prices to our customers. Total cost of sales increased to $1,437.2 million in Fiscal 2007 from $1,343.8 million in Fiscal 2006 primarily reflecting the increase in propane product costs and the increased volumes sold. Total margin increased $64.7 million principally due to the higher volumes, higher average retail propane margins per gallon and increased fee income in response to increases in operating and administrative expenses.
Partnership EBITDA during Fiscal 2007 increased $100.8 million as a result of the previously mentioned increase in total margin, a $46.1 million gain from the sale of the Partnership’s storage facility in Arizona, and the absence of a $17.1 million loss on early extinguishments of debt recorded in Fiscal 2006 partially offset by a $27.2 million increase in operating and administrative expenses. The $17.1 million loss on early extinguishments of debt during Fiscal 2006 was associated with the refinancings of AmeriGas Propane, L.P.’s (“AmeriGas OLP’s”) Series A and Series C First Mortgage Notes totaling $228.8 million, and AmeriGas Partners’ 10% Senior Notes totaling $59.6 million, with $350 million of 7.125% AmeriGas Partners’ Senior Notes due 2016. The Partnership also used a portion of the proceeds from the issuance of the 7.125% Senior Notes to repay AmeriGas OLP’s $35 million term loan. The increase in Fiscal 2007 operating and administrative expenses principally resulted from higher (1) employee compensation and benefits, (2) vehicle costs and (3) maintenance and repair expenses. Both Fiscal 2007 and 2006 benefited from favorable expense reductions related to general insurance primarily reflecting improved claims experience.
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Operating income increased $81.7 million in Fiscal 2007 mainly reflecting the previously mentioned $64.7 million increase in Partnership margin and the $46.1 million gain from the sale of the Partnership’s storage facility in Arizona partially offset by the increase in operating and administrative expenses and depreciation expense.
| International Propane | 2007 | 2006 | Decrease | |||||||||||||
| (Millions of euros) | ||||||||||||||||
| Revenues | € | 602.4 | € | 776.5 | € | (174.1 | ) | (22.4 | )% | |||||||
| Total margin (a) | € | 309.8 | € | 350.5 | € | (40.7 | ) | (11.6 | )% | |||||||
| Operating income | € | 73.3 | € | 99.9 | € | (26.6 | ) | (26.6 | )% | |||||||
| Income before income taxes | € | 51.4 | € | 79.8 | € | (28.4 | ) | (35.6 | )% | |||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 800.4 | $ | 945.5 | $ | (145.1 | ) | (15.3 | )% | |||||||
| Total margin (a) | $ | 411.8 | $ | 428.3 | $ | (16.5 | ) | (3.9 | )% | |||||||
| Operating income | $ | 94.5 | $ | 119.3 | $ | (24.8 | ) | (20.8 | )% | |||||||
| Income before income taxes | $ | 64.1 | $ | 93.9 | $ | (29.8 | ) | (31.7 | )% | |||||||
| Antargaz retail gallons sold (millions) | 269.1 | 315.2 | (46.1 | ) | (14.6 | )% | ||||||||||
| Degree days — % warmer than normal — Antargaz (b) | 21.1 | % | 3.6 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30 locations in our French service territory. |
Based upon heating degree day data, temperatures in Antargaz’ service territory were approximately 21% warmer than normal in Fiscal 2007 compared to temperatures that were approximately 3.6% warmer than normal in Fiscal 2006. Flaga experienced similar record-setting warm weather across its service territories during Fiscal 2007. Antargaz’ retail LPG volumes sold decreased to 269.1 million gallons in Fiscal 2007 from 315.2 million gallons in Fiscal 2006. The decrease in Antargaz retail volumes sold occurred across all of Antargaz’ customer classes and was in large part the result of significantly warmer weather and, to a lesser extent, customer conservation and increased competitive pressures from other LPG marketers and alternate fuels. Flaga’s volumes declined largely reflecting the absence of volumes from its previously consolidated Czech Republic and Slovakia businesses which were contributed to ZLH in February 2006. Flaga’s 50% ownership interest in ZLH has been accounted for under the equity method since its formation in February 2006. International base-currency results are translated into U.S. dollars based upon exchange rates experienced during the reporting periods. During Fiscal 2007, the monthly average currency translation rate was $1.34 per euro compared to a rate of $1.23 per euro during Fiscal 2006.
International Propane euro-based revenues decreased€174.1 million during Fiscal 2007 primarily reflecting (1) a decline of approximately€90.8 million principally due to Antargaz’ lower retail volumes sold at slightly lower average prices, (2) approximately€46.7 million in lower revenues from Antargaz’ low-margin wholesale sales, (3) the absence of revenues from Flaga’s Czech Republic and Slovakia businesses subsequent to the formation of ZLH in February 2006 and lower revenues from Flaga’s wholly owned Austrian business, and (4) lower ancillary sales and services. International Propane’s total cost of sales decreased to€388.6 million in Fiscal 2007 from€517.2 million in Fiscal 2006 largely reflecting the effects of the lower retail volumes sold, LPG product costs that were lower than in Fiscal 2006 and the decline in low-margin wholesale sales. Although LPG product costs were lower in Fiscal 2007 than in Fiscal 2006, they were volatile and remained at historically high levels.
Total margin decreased€40.7 million or 11.6% in Fiscal 2007 largely reflecting (1) the lower retail volumes sold partially offset by higher average margins per retail gallon and (2) lower margin from ancillary sales and services. In U.S. dollars, total margin declined a less dramatic 3.9% reflecting the effects of the stronger euro versus the U.S. dollar during Fiscal 2007.
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International Propane operating income declined€26.6 million in Fiscal 2007 principally reflecting the lower total margin partially offset by a€10.7 million decrease in operating and administrative expenses. The decrease in operating and administrative expenses is largely the result of decreases in Antargaz’ employee compensation and benefits expenses and vehicle costs and decreases in Flaga’s expenses due in large part to the absence of expenses from the businesses contributed to ZLH in February 2006.
The decrease in International Propane income before income taxes principally reflects the previously described decrease in operating income as slightly lower base-currency interest expense and the absence of a loss on extinguishment of debt recorded in Fiscal 2006 were largely offset by changes in minority interest. The decrease in interest expense is attributable to interest savings as a result of our refinancings which are discussed further in Financial Condition and Liquidity. The changes in minority interest reflect the minority interest holder’s share of costs associated with the shut-down of one of Antargaz’ majority-owned filling centers in Fiscal 2006.
| Gas Utility | 2007 | 2006 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,044.9 | $ | 724.0 | $ | 320.9 | 44.3 | % | ||||||||
| Total margin (a) | $ | 303.4 | $ | 201.1 | $ | 102.3 | 50.9 | % | ||||||||
| Operating income | $ | 136.6 | $ | 84.2 | $ | 52.4 | 62.2 | % | ||||||||
| Income before income taxes | $ | 96.7 | $ | 62.4 | $ | 34.3 | 55.0 | % | ||||||||
| System throughput — billions of cubic feet (“bcf”) | 131.8 | 82.6 | 49.2 | 59.6 | % | |||||||||||
| Degree days — % warmer than normal (b) | 4.7 | % | 8.7 | % | — | — | ||||||||||
| (a) | Total margin represents total revenues less total cost of sales. | |
| (b) | Deviation from average heating degree days for the 30-year period 1975-2004 based upon weather statistics provided by NOAA for airports located within Gas Utility’s service territory. |
Temperatures in Gas Utility’s service territory based upon heating degree days were 4.7% warmer than normal in Fiscal 2007 compared with temperatures that were 8.7% warmer than normal in Fiscal 2006. Total distribution system throughput increased 49.2 bcf reflecting a 43.4 bcf increase from the full-year results of PNG Gas and greater UGI Gas distribution system throughput. The greater UGI Gas distribution system throughput primarily reflects (1) greater interruptible delivery service throughput and (2) increased sales to retail core-market customers as a result of the colder Fiscal 2007 weather and year-over-year growth in the number of UGI Gas customers.
Gas Utility revenues increased $320.9 million during Fiscal 2007 principally reflecting $308.9 million of incremental revenues attributable to the full year results of PNG Gas and a $37.5 million increase in UGI Gas revenues from greater low-margin off-system sales. These increases were partially offset by a $30.7 million decrease in revenues from UGI Gas’ retail core-market customers as a result of lower average PGC rates. Gas Utility’s cost of gas was $741.5 million in Fiscal 2007 compared to $522.9 million in Fiscal 2006 largely reflecting the effects of the full-year results of PNG Gas and greater cost of gas associated with the higher UGI Gas off-system sales partially offset by the effects of the previously mentioned lower average UGI Gas PGC rates.
Gas Utility total margin in Fiscal 2007 increased $102.3 million primarily reflecting $93.0 million of incremental margin from the full-year results of PNG Gas and a $9.3 million increase in UGI Gas’ total margin. The increase in UGI Gas’ total margin in Fiscal 2007 principally reflects greater margin from retail core-market customers on higher volumes and higher average interruptible delivery service unit margins reflecting higher natural gas versus oil price spreads.
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Gas Utility operating income increased to $136.6 million in Fiscal 2007 from $84.2 million in Fiscal 2006 principally reflecting the previously mentioned increase in total margin and slightly higher other income partially offset by a $39.5 million increase in operating and administrative expenses and $14.1 million higher depreciation and amortization expense. The increase in total operating and administrative expenses and depreciation and amortization expense principally reflects the full-year results of PNG Gas.
The increase in Gas Utility income before income taxes reflects the higher operating income partially offset by an increase of $18.1 million in interest expense. The increase in interest expense is principally due to higher long- and short-term debt outstanding, primarily as a result of the PG Energy Acquisition, and higher short-term interest rates.
| Electric Utility | 2007 | 2006 | Increase | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 121.9 | $ | 98.0 | $ | 23.9 | 24.4 | % | ||||||||
| Total margin (a) | $ | 47.3 | $ | 41.7 | $ | 5.6 | 13.4 | % | ||||||||
| Operating income | $ | 26.0 | $ | 20.7 | $ | 5.3 | 25.6 | % | ||||||||
| Income before income taxes | $ | 23.6 | $ | 18.2 | $ | 5.4 | 29.7 | % | ||||||||
| Distribution sales — millions of kilowatt hours (“gwh”) | 1,010.6 | 1,005.0 | 5.6 | 0.6 | % | |||||||||||
| (a) | Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. gross receipts taxes of $6.8 million and $5.3 million in Fiscal 2007 and Fiscal 2006, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Consolidated Statements of Income. |
Electric Utility’s Fiscal 2007 kilowatt-hour sales were approximately equal to those of Fiscal 2006. Electric Utility revenues increased $23.9 million in Fiscal 2007 largely reflecting the effects of higher POLR rates. In accordance with the terms of our June 2006 POLR Settlement, Electric Utility increased its POLR rates effective January 1, 2007. This increase raised the average cost to residential customers by approximately 35% over costs in effect during calendar year 2006. Electric Utility’s cost of sales increased to $67.8 million in Fiscal 2007 from $51.0 million in Fiscal 2006 principally reflecting higher per unit purchased power costs.
Electric Utility total margin increased $5.6 million during Fiscal 2007 principally reflecting the effects of the higher POLR rates partially offset by the higher per-unit purchased power costs.
The increase in Fiscal 2007 Electric Utility operating income and income before income taxes principally reflects the increase in total margin partially offset by slightly higher operating and administrative expenses.
| Increase | ||||||||||||||||
| Energy Services | 2007 | 2006 | (Decrease) | |||||||||||||
| (Millions of dollars) | ||||||||||||||||
| Revenues | $ | 1,336.1 | $ | 1,414.3 | $ | (78.2 | ) | (5.5 | )% | |||||||
| Total margin (a) | $ | 100.9 | $ | 86.1 | $ | 14.8 | 17.2 | % | ||||||||
| Operating income | $ | 57.4 | $ | 53.1 | $ | 4.3 | 8.1 | % | ||||||||
| Income before income taxes | $ | 57.4 | $ | 53.1 | $ | 4.3 | 8.1 | % | ||||||||
| (a) | Total margin represents total revenues less total cost of sales. |
Notwithstanding the effects of a 4% increase in natural gas volumes sold and higher electric generation kilowatt-hour sales, Energy Services revenues decreased to $1,336.1 million in Fiscal 2007 from $1,414.3 million in Fiscal 2006 principally reflecting the revenue effects of lower natural gas prices.
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Total margin increased to $100.9 million in Fiscal 2007 from $86.1 million in Fiscal 2006. The increase in total margin is primarily attributable to higher natural gas unit margins, the previously mentioned increase in natural gas volumes sold, and improved results from storage management and peaking supply services.
The increase in Energy Services operating income and income before income taxes principally reflects the increase in total margin largely offset by the absence of a $9.1 million pre-tax gain on the sale of Energy Ventures recorded in Fiscal 2006 and increased operating and administrative expenses due in part to the full-year consolidation of the Hunlock Creek Electric Generation station acquired as a result of the sale of Energy Ventures in March 2006 and greater compensation and benefits costs.
Interest Expense and Income Taxes.Consolidated interest expense increased to $139.6 million in Fiscal 2007 from $123.6 million in Fiscal 2006 principally due to higher interest expense associated with the PG Energy Acquisition debt partially offset by the full-year benefits of AmeriGas Partners debt refinancing in Fiscal 2006. Our effective income tax rate in Fiscal 2007 was higher than in Fiscal 2006 as the Fiscal 2006 effective tax rate reflected management’s lower estimate of taxes to be paid associated with planned repatriation of foreign earnings.
Financial Condition and Liquidity
Capitalization and Liquidity
Total cash and cash equivalents not subject to restriction were $245.2 million at September 30, 2008 compared with $251.8 million at September 30, 2007. Excluding cash and cash equivalents not subject to restriction at UGI’s operating subsidiaries of $148.0 million, and excluding the $120 million cash contribution made to UGI Utilities on September 25, 2008 in conjunction with the CPG Acquisition (as further described below), UGI had $97.2 million of cash and cash equivalents at September 30, 2008. In connection with the previously mentioned October 1, 2008, CPG Acquisition, on September 25, 2008, UGI made a $120 million cash contribution to UGI Utilities. This cash contribution was used by UGI Utilities to reduce its bank loans outstanding. On October 1, 2008, UGI Utilities borrowed under its revolving credit agreement to fund a portion of the CPG Acquisition. Cash and cash equivalents at UGI’s operating subsidiaries at September 30, 2008 include $70.4 million (€50 million) of cash and cash equivalents at Antargaz generated from bank loan borrowings in September 2008 as further described below under “International Propane.”
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, 2008, its 44% effective ownership interest in the Partnership consisted of approximately 24.7 million Common Units and its combined 2% general partner interests. Approximately 45 days after the end of each fiscal quarter, the Partnership distributes all of its Available Cash (as defined in the Third Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, as amended, the “Partnership Agreement”) relating to such fiscal quarter. The ability of the Partnership to pay distributions depends upon a number of factors. These factors include (1) the level of Partnership earnings; (2) the cash needs of the Partnership’s operations (including cash needed for maintaining and increasing operating capacity); (3) changes in operating working capital; and (4) the ability of the Partnership to borrow under its Credit Agreement, to refinance maturing debt and to increase its long-term debt. Some of these factors are affected by conditions beyond the Partnership’s control including weather, competition in markets it serves, the cost of propane and capital market conditions.
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During Fiscal 2008, Fiscal 2007 and Fiscal 2006, our principal business units paid cash dividends and made cash payments to UGI and its subsidiaries as follows:
| Year Ended September 30, | 2008 | 2007 | 2006 | |||||||||
| (Millions of dollars) | ||||||||||||
| AmeriGas Propane | $ | 38.6 | $ | 53.8 | $ | 38.3 | ||||||
| UGI Utilities | 68.8 | 40.0 | 37.6 | |||||||||
| International Propane | 60.7 | 68.4 | 104.6 | |||||||||
| Energy Services | 18.4 | 6.1 | 34.8 | |||||||||
| Total | $ | 186.5 | $ | 168.3 | $ | 215.3 | ||||||
Dividends and other cash distributions are available to pay dividends on UGI Common Stock and for investment purposes. The higher dividend from AmeriGas Propane in Fiscal 2007 reflects the benefit of a one-time $0.25 per AmeriGas Partners Common Unit (“Common Unit”) increase in the August 2007 quarterly distribution and the associated increased General Partner distribution resulting from the July 2007 sale of the Partnership’s 3.5 million barrel LPG storage facility (See Note 2 to Consolidated Financial Statements). The higher dividend and cash payments from International Propane in Fiscal 2006 largely reflect the effects of Antargaz’ significantly higher earnings in Fiscal 2005 and its December 2005 refinancing. Energy Services dividends in Fiscal 2006 included, in part, dividends of proceeds from the sale of its 50% interest in Energy Ventures (see Note 2 to Consolidated Financial statements).
On April 29, 2008, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.1925 per share, or $0.77 per share on an annual basis, effective with the dividend payable on July 1, 2008 to shareholders of record on June 16, 2008. On April 28, 2008, AmeriGas Propane’s Board of Directors approved an increase in the quarterly distribution rate on Common Units to $0.64 per Common Unit ($2.56 annually) from $0.61 per Common Unit ($2.44 annually) previously. The increase in AmeriGas Partners’ distribution was effective with the payment of its distribution for the quarter ended March 31, 2008 paid on May 18, 2008.
The Company’s debt outstanding at September 30, 2008 totaled $2,205.5 million (including current maturities of long-term debt of $81.8 million) compared to $2,252.4 million of debt outstanding (including current maturities of long-term debt of $14.7 million) at September 30, 2007. The slight decrease in total debt outstanding at September 30, 2008 principally reflects net repayments of debt totaling $42.6 million. Total debt outstanding at September 30, 2008 principally consists of $933.4 million of Partnership debt, $668.9 million (€475.2 million) of International Propane debt, including the previously mentioned€50 million ($70.4 million) of Antargaz bank loans, $589 million of UGI Utilities’ debt, and $14.2 million of other debt, as further described below. In May 2008, a first-tier subsidiary of UGI issued $14 million of amortizing fifteen-year long-term debt collateralized by UGI Corporation’s headquarters building.
AmeriGas Partners.AmeriGas Partners’ total debt outstanding at September 30, 2008 includes long-term debt comprising $779.7 million of AmeriGas Partners’ Senior Notes, $150.3 million of AmeriGas OLP First Mortgage Notes and $3.4 million of other long-term debt. There were no borrowings outstanding under AmeriGas OLP’s Credit Agreement at September 30, 2008. AmeriGas OLP expects to refinance $70 million of long-term debt maturing in March 2009 with proceeds from the issuance of a term loan.
AmeriGas OLP’s Credit Agreement expires on October 15, 2011 and consists of (1) a $125 million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 million to finance the purchase of propane businesses or propane business assets or, to the extent it is not so used, for working capital and general purposes, subject to restrictions in the AmeriGas OLP First Mortgage Notes. Issued and outstanding letters of credit under the Revolving Credit Facility, which reduce the amount available for borrowings, totaled $42.9 million at September 30, 2008 and $58.0 million at September 30, 2007. AmeriGas OLP’s short-term borrowing needs are seasonal and are typically greatest during the fall and winter heating-season months due to the need to fund higher levels of working capital. The average daily and peak bank loan borrowings outstanding under the Credit Agreement in Fiscal 2008 were $39.1 million and $106.0 million, respectively. The average daily and peak bank loan borrowings outstanding under the Credit Agreement in Fiscal 2007 were $1.6 million and $92.0 million, respectively. At September 30, 2008, the Partnership’s available borrowing capacity under the Credit Agreement was $157.1 million.
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Although commodity propane prices increased through much of Fiscal 2008, a precipitous decline in prices in late Fiscal 2008 which continued into Fiscal 2009 has resulted in greater cash needed by the Partnership to fund counterparty collateral requirements. These collateral requirements are associated with derivative financial instruments used by the Partnership to manage market price risk associated with fixed sales price commitments to customers principally during the heating season months of October through March. At September 30, 2008, the Partnership had made collateral deposits of $17.8 million associated with these derivative financial instruments. At November 20, 2008, such collateral deposits totaled $144.5 million. In order to reduce the Partnership’s cash collateral payment obligations and to provide the Partnership with more borrowing flexibility and a more cost effective use of its Credit Agreement, in October 2008, UGI agreed to provide guarantees of up to $50 million to AmeriGas OLP’s propane suppliers through September 30, 2009. In addition, on November 14, 2008, AmeriGas OLP entered into a revolving credit agreement with two major banks (“Supplemental Credit Agreement”). The Supplemental Credit Agreement expires on May 14, 2009 and permits AmeriGas OLP to borrow up to $50 million for working capital and general purposes. Except for more restrictive covenants regarding the incurrence of additional indebtedness by AmeriGas OLP, the Supplemental Credit Agreement has restrictive covenants substantially similar to the existing AmeriGas OLP Credit Agreement. At November 20, 2008, the Partnership had $49.5 million of available borrowing capacity under its revolving credit agreements and $25.0 million of unused UGI guarantees.
Based upon existing cash balances, the availability of the UGI guarantees, cash expected to be generated from operations, and borrowings available under AmeriGas OLP’s Credit Agreement and the Supplemental Credit Agreement, the Partnership’s management believes that the Partnership will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2009. In addition, the Partnership’s management believes its liquidity will begin to improve in December 2008.
AmeriGas OLP must meet certain financial covenants in order to borrow under its Credit Agreement and its Supplemental Credit Agreement including, but not limited to, a minimum interest coverage ratio, a maximum debt to EBITDA ratio and a minimum EBITDA, as defined. AmeriGas OLP’s financial covenants calculated as of September 30, 2008 permitted it to borrow up to the maximum amount available under the Credit Agreement. For a more detailed discussion of the Partnership’s credit facilities, see Note 3 to Consolidated Financial Statements.
International Propane.International Propane’s total debt at September 30, 2008 includes long-term debt comprising $534.9 million (€380 million) outstanding under Antargaz’ Senior Facilities term loan and $50.7 million (€36.0 million) outstanding under Flaga’s term loan. Total International Propane debt outstanding at September 30, 2008 also includes $70.4 million (€50 million) outstanding under Antargaz’ revolving credit facility, $9.0 million (€6.4 million) outstanding under Flaga’s working capital facility and $3.9 million (€2.8 million) of other Antargaz and Flaga long-term debt.
Antargaz. In December 2005, AGZ executed a five-year floating-rate Senior Facilities Agreement that expires on March 31, 2011 and consists of (1) a€380 million variable-rate term loan and (2) a€50 million revolving credit facility. AGZ executed interest rate swap agreements to fix the underlying euribor rate of interest on the term loan at approximately 3.25% for the duration of the loan. The effective interest rate on Antargaz’ term loan at September 30, 2008 was 4.40%. The proceeds from the term loan were used to repay its€175 million term loan, to fund the redemption of its€165 million High Yield Bonds and for general corporate purposes. During October 2008, the Senior Facilities Agreement was amended to include a€50 million letter of credit facility. In order to minimize the interest margin it pays on Senior Facilities Agreement borrowings, in September 2008 Antargaz borrowed€50 million ($70.4 million), the total amount available under its revolving credit facility, which amount remained outstanding at September 30, 2008. This amount is included in bank loans on the Consolidated Balance Sheet. Excluding this borrowing in September 2008, no other amounts were borrowed under the revolving credit facility during Fiscal 2008. This borrowing was repaid by Antargaz on October 27, 2008.
The Senior Facilities term loan is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivable. Antargaz’ management believes that it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2009 with cash generated from operations, borrowings under its revolving credit facility and guarantees under its letter of credit facility.
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The Senior Facilities Agreement restricts the ability of Antargaz to, among other things, incur additional indebtedness and make investments. For a more detailed discussion of Antargaz’ debt, see Note 3 to Consolidated Financial Statements.
Flaga. Effective in July 2006, Flaga entered into a euro-based variable rate term loan facility in the amount of€48 million (€36 million of which is outstanding at September 30, 2008) and a working capital facility with a major European bank for up to€8 million both of which expire in September 2011. Borrowings under the working capital facility commitment totaled€6.4 million ($9.0 million) at September 30, 2008. Generally, principal payments on the term loan of€3 million are due semi-annually on March 31 and September 30 each year through 2010 with final payments totaling€6.0 million,€6.4 million and€14.6 million in March, August and September 2011, respectively. In November 2006, Flaga effectively fixed the euribor component of its interest rate on a substantial portion of its term loan through September 2011 at 3.91% by entering into an interest rate swap agreement. The effective interest rate on Flaga’s term loan at September 30, 2008 was 4.80%. Debt issued under these agreements is guaranteed by UGI. Flaga’s joint venture, ZLH, has multi-currency working capital facilities that provide for borrowings up to a total of€16 million, half of which is guaranteed by UGI. At September 30, 2008, the total amount outstanding under the ZLH facility was€14.2 million ($20 million). For a more detailed discussion of Flaga’s debt, see Note 3 to Consolidated Financial Statements.
UGI Utilities.UGI Utilities’ total debt outstanding at September 30, 2008 includes long-term debt comprising $275 million of Senior Notes and $257 million of Medium-Term Notes. Total debt outstanding also includes $57 million under UGI Utilities’ Revolving Credit Agreement. In January 2008, UGI Utilities issued $20 million of Medium-Term Notes due 2018 bearing interest at a rate of 5.67%. The proceeds were used by UGI Utilities to reduce borrowings under the Revolving Credit Agreement. In connection with the CPG Acquisition, on October 1, 2008, UGI Utilities issued $108 million face amount of 6.375% Senior Notes due 2013.
UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement. This agreement expires in August 2011. At September 30, 2008 and 2007, there was $57 million and $190 million, respectively, outstanding under the Revolving Credit Agreement. As previously mentioned, the September 30, 2008 amount is reduced by the $120 million cash contribution made by UGI on September 25, 2008 to finance a portion of the CPG Acquisition on October 1, 2008. Amounts outstanding under the Revolving Credit Agreement are classified as bank loans on the Consolidated Balance Sheets. UGI Utilities’ Revolving Credit Agreement requires it to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. During Fiscal 2008 and Fiscal 2007, peak bank loan borrowings totaled $267.0 million and $259.0 million, respectively. Peak bank loan borrowings typically occur during the peak heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is generally greatest. Average daily bank loan borrowings were $121.0 million in Fiscal 2008 and $164.3 million in Fiscal 2007.
UGI Utilities has a shelf registration statement with the U.S. Securities and Exchange Commission under which it may issue up to an additional $112 million of debt securities subject to the financial ratio covenant in its Revolving Credit Agreement and PUC approval.
Based upon cash expected to be generated from Gas Utility and Electric Utility operations, including those of CPG, and borrowings available under its Revolving Credit Agreement and our ability to issue public debt, UGI Utilities’ management believes that it will be able to meet its anticipated contractual and projected cash commitments, including those of CPG, during Fiscal 2009. For a more detailed discussion of UGI Utilities’ long-term debt and Revolving Credit Agreement, see Note 3 to Consolidated Financial Statements.
Energy Services.Energy Services has a $200 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper expiring in April 2009, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility’s back-up purchasers. Management expects it will extend or replace the Receivables Facility prior to its termination date.
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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 provisions of Statement of Financial Accounting Standards (“SFAS”) No. 140, “Accounting for Transfers and Servicing 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. At September 30, 2008, the outstanding balance of ESFC trade receivables was $28.7 million which is net of $71.0 million that was sold to the commercial paper conduit and removed from the balance sheet. During Fiscal 2008 and 2007, peak borrowings were $71.0 million and $76.0 million, respectively. Based upon cash expected to be generated from operations, borrowings available under its Receivables Facility, and capital contributions from UGI for capital projects, management believes that Energy Services will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2009.
Effect of Recent Market Conditions
The recent unprecedented volatility in credit and capital markets may create additional risks to our businesses in the future. We are exposed to financial market 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 and credit risks of our suppliers, counterparties associated with derivative financial instruments and our customers.
We believe that each of our business units has sufficient liquidity in the form of revolving credit facilities, letters of credit and guarantee arrangements to fund business operations including the cash collateral and margin deposit requirements of our product cost management activities resulting from recent steep declines in natural gas and propane commodity prices. Additionally, we do not have significant amounts of long-term debt maturing or revolving credit agreements terminating in the next several fiscal years. Accordingly, we do not believe that recent conditions in the credit and capital markets will have a significant impact on our liquidity. Although we believe that recent financial market conditions will not have a significant impact on our ability to fund our existing operations, such market conditions could restrict our ability to make a significant acquisition or limit the scope of major capital projects if access to credit and capital markets is limited and could adversely affect our operating results.
We are subject to credit risk relating to the ability of counterparties to meet their contractual payment obligations or the potential non-performance of counterparties to deliver contracted commodities or services at contract prices. We monitor our counterparty credit risk exposure in order to minimize credit risk with any one supplier or financial instrument counterparty. Our business units generally have diverse customer bases that span broad geographic, economic and demographic constituencies. No single customer in any of our business units represents more than ten percent of our revenues or operating income. Notwithstanding this diverse customer profile, current conditions in the credit markets could affect the ability of some of our customers to pay timely or result in increased customer bankruptcies which may lead to increased bad debts.
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We sponsor funded defined benefit pension and postretirement benefit plans. We believe that the oversight of the plans’ investments is rigorous and that our investment strategies are prudent. During Fiscal 2008, actual returns on plans’ investments were significantly below the expected rate of return due to adverse conditions in the financial markets. Reductions in asset values from the lower than expected investment performance resulted in increases in the plans’ unfunded status and, in accordance with the provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (“SFAS 158”), a decrease in shareholders’ equity. Notwithstanding the investment results in Fiscal 2008, we do not expect that we will be required to make significant contributions to the plans in Fiscal 2009. Continued actual returns below the expected rates of return would, however, accelerate the timing and increase the amount of future contributions to these plans beyond Fiscal 2009. Additionally, reduced benefit plan assets would likely result in increased benefit expense in future years.
As previously mentioned, in order to manage market risk associated with the Partnership’s fixed-price programs which permit customers to lock in the prices they pay for propane, the Partnership has entered into derivative financial instruments that have collateral provisions. These derivative instruments are used to manage market price risk principally during the heating-season months of October through March. If market prices for propane were to continue to fall during the Fiscal 2009 heating season, we could be required to make significant additional cash collateral payments or provide guarantees. The Partnership’s management believes it has sufficient liquidity to meet such obligations and its projected cash needs in Fiscal 2009. In addition, the Partnership’s management believes its liquidity will begin to improve in December 2008.
Cash Flows
Operating Activities.Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest. AmeriGas Propane and UGI Utilities primarily use bank loans to satisfy their seasonal operating cash flow needs. Energy Services uses its Receivables Facility to satisfy its operating cash flow needs. During Fiscal 2008, Fiscal 2007 and Fiscal 2006, Antargaz generally funded its operating cash flow needs without using its revolving credit facility.
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 most of Fiscal 2008, commodity prices of natural gas and LPG increased significantly. The increases in commodity prices resulted in higher investments in accounts receivable and inventory during much of Fiscal 2008. Late in Fiscal 2008 and continuing into Fiscal 2009, falling natural gas and LPG prices have resulted in greater cash required to fund commodity futures margin and counterparty collateral requirements associated with Gas Utility’s, Energy Services’ and the Partnership’s product cost management activities.
Cash flow provided by operating activities was $464.4 million in Fiscal 2008, $456.2 million in Fiscal 2007 and $279.4 million in Fiscal 2006. Cash flow from operating activities before changes in operating working capital was $525.3 million in Fiscal 2008, $518.4 million in Fiscal 2007 and $404.6 million in Fiscal 2006. Changes in operating working capital required operating cash flow of $60.9 million in Fiscal 2008, $62.2 million in Fiscal 2007 and $125.2 million in Fiscal 2006. Cash flow from changes in operating working capital principally reflects the impacts of the timing of and 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 and increases in LPG and natural gas prices on our investments in inventories; the timing of cash recoveries in excess of purchase gas costs through Gas Utility’s PGC recovery mechanism including settled gains on natural gas futures contracts; the effects of the timing of payments and increased purchase price per gallon of LPG and natural gas on accounts payable; and net collateral deposits of $17.8 million associated with Partnership derivative contracts. The significant increase in cash flow from operating activities in Fiscal 2007 compared to Fiscal 2006 largely reflects greater cash flow from UGI Utilities, reflecting the full-year effects of PNG Gas and lower cash used for working capital purposes, and greater cash flow from AmeriGas Propane principally reflecting the cash flow effects of the Partnership’s improved Fiscal 2007 financial performance.
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Investing Activities.Investing activity cash flow is principally affected by investments in 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 $289.5 million in Fiscal 2008, $223.8 million in Fiscal 2007 and $707.5 million in Fiscal 2006. Fiscal 2008 investing activity cash flows include a $57.5 million increase in restricted margin deposits in natural gas futures accounts due to declining natural gas prices late in Fiscal 2008. The significant Fiscal 2006 cash flow used by investing activities reflects in large part $580 million paid at settlement for the PG Energy Acquisition. Cash flow for acquisitions in Fiscal 2007, principally Partnership propane business acquisitions, totaled $78.8 million. During Fiscal 2007, the Partnership also received $49.0 million in cash proceeds from the sale of its Arizona storage facility and UGI Utilities received $23.7 million in settlement of its working capital adjustment associated with the PG Energy Acquisition. During Fiscal 2008, Fiscal 2007 and Fiscal 2006, we spent $232.1 million, $223.1 million and $191.7 million, respectively, for property, plant and equipment. The increase in Fiscal 2007 expenditures compared with Fiscal 2006 reflects in large part the full-year affects of the PNG Gas acquisition.
Financing Activities.Cash flow (used) provided by financing activities was $(180.1) million, $(178.5) million and $299.7 million in Fiscal 2008, Fiscal 2007 and Fiscal 2006, 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 AmeriGas Partners Common Units and UGI Common Stock.
Fiscal 2008 issuances of long-term debt include $20 million of 5.67% ten-year Medium-Term notes of UGI Utilities the proceeds of which were used to reduce UGI Utilities Revolving Credit Agreement borrowings and $14 million of amortizing debt collateralized by UGI’s corporate headquarters building. Fiscal 2007 issuances of long-term debt include $20 million of UGI Utilities’ 6.17% Medium-Term Notes the proceeds of which were used to repay UGI Utilities maturing 7.17% Medium-Term Notes. We also made scheduled repayments of€6 million of Flaga’s term loan during Fiscal 2008 and Fiscal 2007. Long-term debt issuances in Fiscal 2006 were affected by a number of significant financing transactions including the issuance of $275 million of UGI Utilities Senior Notes associated with the PG Energy Acquisition; a€380 million term loan entered into by Antargaz; and $350 million of Senior Notes issued by AmeriGas Partners. The proceeds from the Antargaz€380 million term loan were used to repay the then-existing€175 million Antargaz Senior Facilities term loan, redeem Antargaz€165 million High Yield Bonds and for general corporate purposes. The proceeds of the AmeriGas Partners Senior Notes were used to refinance AmeriGas OLP’s $160 million Series A and $68.8 million Series C First Mortgage Notes, including a make-whole premium, its $35 million term loan due October 1, 2006, and $59.6 million of the Partnership’s 10% Senior Notes.
Pension Plans
UGI Utilities sponsors two defined benefit pension plans (“Pension Plans”) for employees of UGI Utilities, UGIPNG, UGI and certain of UGI’s other subsidiaries. The fair value of Pension Plans’ assets totaled $241.0 million and $290.1 million at September 30, 2008 and 2007, respectively. At September 30, 2008 and 2007, the underfunded position of Pension Plans, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension Plans’ assets, was $59.6 million and $9.3 million, respectively. The increase in the underfunded status at September 30, 2008 principally resulted from changes in the fair value of Pension Plans’ assets due to the general decline in the financial markets during Fiscal 2008. Antargaz employees are also covered by certain defined benefit pension and postretirement plans. The plan assets, PBOs and the funded statuses of these plans are not material.
Effective January 1, 2009, participation in Pension Plans will be closed to new hires, rehires or first transfers from affiliates. In lieu of participation in Pension Plans, these employees will receive enhanced benefits under company-sponsored 401(k) savings plans. The impact of this change is not expected to have a material effect on Fiscal 2009 postretirement benefit plans expense.
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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, and we do not anticipate that we will be required to make contributions to Pension Plans during Fiscal 2009. In conjunction with the settlement of obligations under a subsidiary retirement benefit plan, Antargaz expects to make a payment of approximately €4.0 million during Fiscal 2009. Pre-tax pension costs associated with Pension Plans in Fiscal 2008, Fiscal 2007 and Fiscal 2006 were not material. Pension cost associated with Pension Plans in Fiscal 2009 is expected to be approximately $3.3 million.
SFAS 158 requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension as well as postretirement benefit plans such as retiree health and life, with current year changes recognized in shareholders’ equity. We adopted SFAS 158 effective September 30, 2007. In accordance with the requirements of SFAS 158, through September 30, 2008 we have recorded cumulative after-tax charges to Common Stockholders’ Equity of $39.4 million in order to reflect the funded status of these plans. For a more detailed discussion of the Pension Plans and other postretirement benefit plans, see Notes 1 and 5 to Consolidated Financial Statements.
Capital Expenditures
In the following table, we present capital expenditures (which exclude acquisitions but include capital leases) by our business segments for Fiscal 2008, Fiscal 2007 and Fiscal 2006. We also provide amounts we expect to spend in Fiscal 2009. We expect to finance Fiscal 2009 capital expenditures principally from cash generated by operations and borrowings under our credit facilities and cash on hand.
| Year Ended September 30, | 2009 | 2008 | 2007 | 2006 | ||||||||||||
| (Millions of dollars) | (estimate) | |||||||||||||||
| AmeriGas Propane | $ | 87.1 | $ | 62.8 | $ | 73.8 | $ | 70.7 | ||||||||
| International Propane | 82.4 | 75.0 | 64.3 | 55.5 | ||||||||||||
| Gas Utility | 74.8 | 58.3 | 66.2 | 49.2 | ||||||||||||
| Electric Utility | 5.9 | 6.0 | 7.2 | 9.0 | ||||||||||||
| Energy Services | 74.7 | 30.7 | 10.7 | 7.0 | ||||||||||||
| Other | 2.6 | 1.4 | 0.9 | 0.3 | ||||||||||||
| $ | 327.5 | $ | 234.2 | $ | 223.1 | $ | 191.7 | |||||||||
The higher Gas Utility capital expenditures expected in Fiscal 2009 is due to capital expenditures of CPG. The increase in Energy Services capital expenditures in Fiscal 2009 includes greater capital expenditures related to electric generation projects and liquefied natural gas and propane air plants. AmeriGas Propane capital expenditures in Fiscal 2009 include expenditures associated with a system software replacement.
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Contractual Cash Obligations and Commitments
The Company has contractual cash obligations that extend beyond Fiscal 2008. 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, 2008.
| Payments Due by Period | ||||||||||||||||||||
| Fiscal | Fiscal | Fiscal | ||||||||||||||||||
| (Millions of dollars) | Total | 2009 | 2010-2011 | 2012-2013 | Thereafter | |||||||||||||||
| Long-term debt (a) | $ | 2,069.1 | $ | 81.8 | $ | 676.3 | $ | 67.1 | $ | 1,243.9 | ||||||||||
| Interest on long-term fixed rate debt (b) | 903.5 | 122.9 | 218.0 | 172.3 | 390.3 | |||||||||||||||
| Operating leases | 239.4 | 57.2 | 82.0 | 51.9 | 48.3 | |||||||||||||||
| AmeriGas Propane supply contracts | 36.5 | 36.5 | — | — | — | |||||||||||||||
| International Propane supply contracts | 414.3 | 414.3 | — | — | — | |||||||||||||||
| Energy Services supply contracts | 697.9 | 589.8 | 108.1 | — | — | |||||||||||||||
| Gas Utility and Electric Utility supply, storage and transportation contracts | 860.5 | 420.6 | 221.5 | 109.4 | 109.0 | |||||||||||||||
| Derivative financial instruments (c) | 114.1 | 103.2 | 10.9 | — | — | |||||||||||||||
| Other purchase obligations (d) | 36.3 | 35.3 | 1.0 | — | — | |||||||||||||||
| Total | $ | 5,371.6 | $ | 1,861.6 | $ | 1,317.8 | $ | 400.7 | $ | 1,791.5 | ||||||||||
| (a) | Based upon stated maturity dates. Excludes $108 million of 6.375% UGI Utilities Senior Notes due 2013 issued on October 1, 2008 in connection with the CPG Acquisition. | |
| (b) | Based upon stated interest rates adjusted for the effects of interest rate swaps. Excludes interest on $108 million of UGI Utilities 6.375% Senior Notes issued on October 1, 2008 in connection with the CPG Acquisition. | |
| (c) | Represents the sum of amounts due from us if derivative financial instrument liabilities were settled at the September 30, 2008 amounts reflected in the financial statements. | |
| (d) | Includes material capital expenditure obligations. Excludes CPG Acquisition purchase obligation of $303.0 million. |
Components of other noncurrent liabilities included in our Consolidated Balances Sheet at September 30, 2008 principally comprise refundable tank and cylinder deposits (as further described in Note 1 to Consolidated Financial Statements under the caption “Refundable Tank and Cylinder Deposits”); property and casualty liabilities and obligations under environmental remediation agreements (see Note 10); pension and other post-employment benefit liabilities recorded in accordance with SFAS 158 (see Note 5); and liabilities associated with executive compensation plans (see Note 8). 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.
Related Party Transactions
During Fiscal 2008, Fiscal 2007 and Fiscal 2006, we did not enter into any related-party transactions that had a material effect on our financial condition, results of operations or cash flows.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements that are expected to have a material effect on our financial condition, change in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
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Utility Regulatory Matters
Since 1999, all natural gas consumers in Pennsylvania, including core market customers, have been able to purchase gas supplies from entities other than natural gas distribution companies (“NGDCs”). Under the Gas Competition Act, NGDCs, like UGI Gas and PNG Gas, continue to serve as the supplier of last resort for all core market customers, and such sales of gas, as well as the distribution service provided by NGDCs, continue to be subject to rate regulation by the PUC. As of September 30, 2008, fewer than 1% of Gas Utility’s core market customers purchase their gas from alternate suppliers.
In an order entered on November 30, 2006, the PUC approved a settlement of a base rate proceeding of PNG Gas. The settlement authorized PNG Gas to increase annual base rates $12.5 million, or approximately 4%, effective December 2, 2006.
As a result of the Electricity Generation Customer Choice and Competition Act that became effective January 1, 1997, all of Electric Utility’s customers have the ability to acquire their electricity from entities other than Electric Utility. As of September 30, 2008, none of Electric Utility’s customers have chosen an alternative electricity generation supplier and no alternate suppliers of electricity are currently offering such service in Electric Utility’s service territory. Electric Utility remains the provider of last resort, or default service provider, for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements, the latest of which became effective on June 23, 2006 (collectively, the “POLR Settlement”).
Electric Utility’s POLR service rules provide for annual shopping periods during which customers may elect to remain on POLR service or choose an alternate supplier, if available. Customers who do not select an alternate supplier are obligated to remain on POLR service until the next shopping period. Residential customers who return to POLR service must remain on POLR service until the date of the second open shopping period after returning. Commercial and industrial customers who return to POLR service must remain on POLR service until the next open shopping period, and may, in certain circumstances, be subject to generation rate surcharges.
In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. Consistent with the terms of the POLR Settlement, Electric Utility’s POLR rates increased 3% on January 1, 2006. Electric Utility also increased its POLR rates effective January 1, 2007, which increased the average cost to a residential heating customer by approximately 35% over such costs in effect during calendar year 2006, and increased its POLR rates effective January 1, 2008, which increased the average cost to a residential heating customer by approximately 5.5% over such costs in effect during calendar year 2007. Effective January 1, 2009, average residential heating customer rates will increase by approximately 1.5%. Electric Utility is also permitted to and has entered into multiple-year fixed-rate POLR contracts with certain of its customers.
On July 17, 2008, the PUC approved Electric Utility’s default service procurement, implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with the PUC’s default service regulations. These plans do not affect Electric Utility’s existing POLR Settlement effective through December 31, 2009. The approved plans specify how Electric Utility will solicit and acquire default service 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. Under applicable statutory standards, Electric Utility is entitled to fully recover its default service costs.
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Because Electric Utility will be assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010 Electric Utility will no longer be subject to the risk that actual costs for purchased power will exceed POLR revenues. However, beginning January 1, 2010, Electric Utility will forego the opportunity to recover revenues in excess of actual costs as currently permitted under the POLR Settlement. During Fiscal 2008, such excess of revenues over actual costs was material to UGI Utilities’ results of operations. Although we believe the impact of the approved default service plans will be material to the Electric Utility’s results of operations beginning in Fiscal 2010, we believe such impact will not be material to UGI Utilities because it will be offset by expected increases in operating income from our Gas Utility.
We account for the operations of Gas Utility and Electric Utility in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). SFAS 71 requires us to record the effects of rate regulation in the financial statements. SFAS 71 allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement of an unregulated company. These deferred assets and liabilities are then flowed through the income statement in the period in which the same amounts are included in rates and recovered from or refunded to customers. As required by SFAS 71, we monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these regulatory assets is no longer probable, such assets would be written off against earnings. We believe that SFAS 71 continues to apply to our regulated operations and that the recovery of our regulatory assets is probable.
Manufactured Gas Plants
UGI Utilities
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. At September 30, 2008, neither the Company’s undiscounted amount nor its accrued liability for environmental investigation and cleanup costs was material.
UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. In accordance with the terms of the PNG Gas base rate case order which became effective December 2, 2006, site-specific environmental investigation and remediation costs associated with PNG Gas incurred prior to December 2, 2006 are amortized as removal costs over five-year periods. Such costs incurred after December 1, 2006 are expensed as incurred.
As a result of the acquisition of PG Energy by UGI Utilities’ wholly-owned subsidiary, UGIPNG, UGIPNG became party to a Multi-Site Remediation Consent Order and Agreement between PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform annually a specified level of activities associated with environmental investigation and remediation work at 11 currently owned properties on which MGP-related facilities were operated (“Properties”). Under the Multi-Site Agreement, environmental expenditures, including costs to perform work on the Properties, are capped at $1.1 million in any calendar year. The Multi-Site Agreement terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date.
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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. We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated.
Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.
South Carolina Electric & Gas Company v. UGI Utilities, Inc.On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for 47% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 million in remediation costs and $26 million in third-party claims relating to the site and estimates that future remediation costs could be as high as $2.5 million. SCE&G further asserts that it has received a demand from the United States Justice Department for natural resource damages. UGI Utilities is defending the suit.
City of Bangor, Maine v. Citizens Communications Company.In April 2003, Citizens Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that 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. Studies conducted by the City and Citizens suggest that it could cost up to $18 million to clean up the river. Citizens’ third-party claims were stayed pending a resolution of the City’s suit against Citizens, which was tried in September 2005. Citizen’s third-party claims were stayed pending trial of the City’s suit against Citizens. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. On February 14, 2007, Citizens and the City entered into a settlement agreement pursuant to which Citizens agreed to pay $7.6 million in exchange for a release of its and all predecessors’ liabilities. Separately, the Maine Department of Environmental Protection has disclaimed its previously announced intention to pursue third-party defendants, including UGI Utilities, for costs incurred by the State of Maine related to contaminants at this site. UGI Utilities believes that it has good defenses to all Citizens’ claims.
Consolidated Edison Company of New York v. UGI Utilities, Inc.On September 20, 2001, Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at twelve former MGP sites in Westchester County, New York. The complaint alleged that UGI Utilities “owned and operated” the MGPs prior to 1904 as a result of control of subsidiaries that owned the MGPs and at three sites where UGI Utilities allegedly operated the MGPs under lease with the owner.
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UGI Utilities successfully moved for summary judgment on all but the three sites where UGI Utilities allegedly operated the MGP sites under lease. On June 17, 2008, UGI Utilities and ConEd agreed to a settlement with respect to the three remaining sites. UGI Utilities’ obligations under the settlement agreement will not have a material effect on the Company’s operating results or financial condition.
Sag Harbor, New York Matter.By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 million and expects to spend another $11 million to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10 million. KeySpan believes that the cost could be as high as $20 million. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.
Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc.On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of its subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs for all of the sites would total approximately $215 million and asserted that UGI Utilities is responsible for approximately $103 million of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23 million. UGI Utilities is defending the suit. Trial is scheduled for April 2009.
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 manufactured gas plant operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The General Partner is researching the history of the site and is investigating DEC’s findings. The General Partner has reviewed the preliminary site characterization study prepared by the DEC and is in the early stages of investigating the extent of contamination and the possible existence of other potentially responsible parties. Due to the early stage of such investigation, the amount of expected clean up costs cannot be reasonably estimated. When such expected clean up costs can be reasonably estimated, it is possible that the amount could be material to the Partnership’s results of operations.
Antargaz Tax Matters
French tax authorities levy various taxes on legal entities and individuals regularly operating a business in France which are commonly referred to collectively as “business tax.” The amount of business tax charged annually is generally dependent upon the value of the entity’s tangible fixed assets. 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.
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Market Risk Disclosures
Our primary market risk exposures are (1) market prices for LPG, natural gas and electricity; (2) changes in interest rates; and (3) foreign currency exchange rates.
The risk associated with fluctuations in the prices the Partnership and our International Propane operations pay for LPG is principally a result of market forces reflecting changes in supply and demand for LPG and other energy commodities. Their profitability is sensitive to changes in LPG supply costs. Increases in supply costs are generally passed on to customers. International Propane and the Partnership may not, however, always be able to pass on product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements, and over-the-counter derivative commodity instruments including price swap and option contracts. In addition, Antargaz hedges a portion of its anticipated U.S. dollar denominated LPG product purchases through the use of forward foreign exchange contracts. Antargaz may also enter into other contracts, similar to those used by the Partnership. Flaga has used and may use derivative commodity instruments to reduce market risk associated with a portion of its propane purchases. Currently, Flaga’s hedging activities are not material to the Company’s financial position or results of operations. Over-the-counter derivative commodity instruments utilized to hedge forecasted purchases of propane are generally settled at expiration of the contract. These derivative financial instruments contain collateral provisions. As previously mentioned, precipitous declines in propane commodity prices late in Fiscal 2008 which continued into Fiscal 2009 has resulted in greater collateral requirements by the Partnership’s derivative instrument counterparties. In order to minimize credit risk associated with derivative commodity contracts, we monitor established credit limits with the contract counterparties. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.
Gas Utility’s tariffs contain clauses that permit recovery of substantially all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures contracts to reduce volatility in the cost of gas it purchases for retail core-market customers. The cost of these derivative instruments, net of any associated gains or losses, is included in Gas Utility’s PGC mechanism. At September 30, 2008 and 2007, Gas Utility had $34.0 million and $6.6 million, respectively, of restricted cash associated with natural gas futures accounts with brokers.
Electric Utility purchases its electric power needs from electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market. Wholesale prices for electricity can be volatile especially during periods of high demand or tight supply. As previously mentioned and in accordance with POLR settlements approved by the PUC, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. Electric Utility’s fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 31, 2009. With respect to its existing fixed-price power contracts, should any of the counterparties fail to provide electric power under the terms of such contracts, any increases in the cost of replacement power could negatively impact Electric Utility results. In order to reduce this nonperformance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. From time to time, Electric Utility enters into electric price swap agreements to reduce the volatility in the cost of a portion of its anticipated electricity requirements. There were no price swaps outstanding as of September 30, 2008. At September 30, 2007, Electric Utility had an electric price swap agreement associated with purchases of a portion of electricity anticipated to occur through December 2007.
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As previously mentioned, on July 17, 2008, the PUC approved the Electric Utility’s default service plans filed in accordance with the PUC’s default service regulations. Under applicable statutory standards, Electric Utility is entitled to fully recover its default service costs. Because Electric Utility will be assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010, Electric Utility will no longer be subject to the risk that actual costs for purchased power will exceed POLR revenues.
In order to manage market price risk relating to substantially all of Energy Services’ fixed-price sales contracts for natural gas, Energy Services purchases exchange-traded and over-the-counter natural gas futures contracts or enters into fixed-price supply arrangements. Energy Services’ exchange-traded natural gas futures contracts are guaranteed by the New York Mercantile Exchange (“NYMEX”) and have nominal credit risk. The change in market value of these contracts generally requires daily cash deposits in margin accounts with brokers. At September 30, 2008 and 2007, Energy Services had $36.3 million and $6.2 million, respectively, of restricted cash on deposit in such margin accounts. Although Energy Services’ fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the natural gas suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas would adversely impact Energy Services’ results. In order to reduce this risk of supplier nonperformance, Energy Services has diversified its purchases across a number of suppliers.
UGID has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by its interests in electric generation assets. In the event that these generation assets would not be able to produce all of the electricity needed to supply electricity under these agreements, UGID would be required to purchase such electricity on the spot market or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact the Company’s results.
Electric Utility obtains financial transmission rights (“FTRs”) through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, from purchases through monthly PJM auctions. Energy Services purchases FTRs to economically hedge certain transmission costs associated with its fixed-price electricity sales contracts. 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. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Although FTRs are economically effective as hedges of congestion charges, they do not currently qualify for hedge accounting treatment.
Asset Management has entered and may continue to enter into fixed-price sales agreements for a portion of its propane sales. In order to manage the market price risk relating to substantially all of its fixed-price sales contracts for propane, Asset Management enters into price swap and option contracts.
We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact its fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.
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Our variable-rate debt includes borrowings under AmeriGas OLP’s Credit Agreement, UGI Utilities’ Revolving Credit Agreement and a substantial portion of Antargaz’ and Flaga’s debt. These debt agreements have interest rates that are generally indexed to short-term market interest rates. As previously mentioned, Antargaz has effectively fixed the underlying euribor interest rate on its variable-rate debt through March 2011 and Flaga has fixed the underlying euribor interest rate on a substantial portion of its term loan through September 2011 through the use of interest rate swaps. At September 30, 2008 and 2007, combined borrowings outstanding under variable-rate agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled $137.8 million and $199.0 million, respectively. Excluding the fixed portions of Antargaz’ and Flaga’s variable-rate debt, and based upon weighted average borrowings outstanding under variable-rate agreements during Fiscal 2008 and Fiscal 2007, an increase in short-term interest rates of 100 basis points (1%) would have increased our Fiscal 2008 interest expense by $1.9 million and $1.8 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 $74.0 million and $88.4 million at September 30, 2008 and 2007, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $81.4 million and $98.1 million at September 30, 2008 and 2007, respectively.
Long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. This debt may have an interest rate that is more or less than the refinanced debt. In order to reduce interest rate risk associated with near to medium term forecasted issuances of fixed-rate debt, we may enter into interest rate protection agreements.
Our primary exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign-denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investment in foreign subsidiaries (“net investment hedges”). Realized gains or losses associated with net investments in foreign operations remain in other comprehensive income until such foreign operations are liquidated. With respect to our net investments in Flaga and Antargaz, a 10% decline in the value of the euro versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value by approximately $57.1 million, which amount would be reflected in other comprehensive income.
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The following table summarizes the fair values of unsettled market risk sensitive derivative instruments assets and (liabilities) held at September 30, 2008 and 2007. Fair values reflect the estimated amounts that we would receive or (pay) to terminate the contracts at the reporting date based upon quoted market prices or the fair value of comparable contracts at September 30, 2008 and 2007, respectively. The table also includes the changes in fair value that would result if there were a 10% adverse change in (1) the market price of propane; (2) the market price of natural gas; (3) the market price of electricity; (4) the three-month LIBOR and the three- and six-month Euribor and; (5) the value of the euro versus the U.S. dollar. The fair values of Gas Utility’s exchange-traded natural gas derivative contracts comprising losses of $23.3 million and $0.6 million at September 30, 2008 and 2007, respectively, are excluded from the table below because any associated net gains or losses are included in Gas Utility’s PGC recovery mechanism.
| Asset (Liability) | ||||||||
| Change in | ||||||||
| (Millions of dollars) | Fair Value | Fair Value | ||||||
| September 30, 2008: | ||||||||
| Propane commodity price risk | $ | (53.7 | ) | $ | (29.2 | ) | ||
| FTRs | 5.7 | (0.6 | ) | |||||
| Natural gas commodity price risk | (29.1 | ) | (21.7 | ) | ||||
| Electricity commodity price risk | (0.7 | ) | (0.2 | ) | ||||
| Interest rate risk | 9.1 | (9.9 | ) | |||||
| Foreign currency exchange rate risk | 3.4 | (19.5 | ) | |||||
| September 30, 2007: | ||||||||
| Propane commodity price risk | $ | 18.3 | $ | (18.5 | ) | |||
| Natural gas commodity price risk | (1.4 | ) | (8.6 | ) | ||||
| Electricity commodity price risk | 0.8 | (0.3 | ) | |||||
| Interest rate risk | 21.3 | (12.6 | ) | |||||
| Foreign currency exchange rate risk | (14.7 | ) | (27.1 | ) | ||||
Because the Company’s derivative instruments, other than FTRs, generally qualify as hedges under SFAS 133, we expect that changes in the fair value of derivative instruments used to manage commodity, currency or interest rate market risk would be substantially offset by gains or losses on the associated anticipated transactions.
Critical Accounting Policies and Estimates
The preparation of financial statements and related disclosures in compliance with accounting principles generally accepted in the United States of America requires the selection and application of accounting principles appropriate to the relevant facts and circumstances of the Company’s operations and the use of estimates made by management. The Company has identified the following critical accounting policies and estimates that are most important to the portrayal of the Company’s financial condition and results of operations. Changes in these policies and estimates could have a material effect on the financial statements. The application of these accounting policies and estimates necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements. Management has reviewed these critical accounting policies, and the estimates and assumptions associated with them, with the Company’s Audit Committee. In addition, management has reviewed the following disclosures regarding the application of these critical accounting policies and estimates with the Audit Committee.
Litigation Accruals and Environmental Remediation Liabilities.We are involved in litigation regarding pending claims and legal actions that arise in the normal course of our businesses. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere, and PNG 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.
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Regulatory Assets and Liabilities.Gas Utility and Electric Utility are subject to regulation by the PUC. In accordance with SFAS 71, we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. As of September 30, 2008, our regulatory assets totaled $107.4 million. See Notes 1 and 6 to the Consolidated Financial Statements.
Depreciation and Amortization of Long-lived Assets.We compute depreciation on UGI Utilities’ property, plant and equipment on a straight-line basis over the average remaining lives of its various classes of depreciable property and on our other property, plant and equipment on a straight-line basis over estimated useful lives generally ranging from 2 to 40 years. We also use amortization methods and determine asset values of intangible assets other than goodwill using reasonable assumptions and projections. Changes in the estimated useful lives of property, plant and equipment and changes in intangible asset amortization methods or values could have a material effect on our results of operations. As of September 30, 2008, our net property, plant and equipment totaled $2,449.5 million and we recorded depreciation expense of $163.8 million during Fiscal 2008. As of September 30, 2008, our net intangible assets totaled $155.0 million and we recorded intangible amortization expense of $18.8 million during Fiscal 2008.
Purchase Price Allocation.From time to time, the Company enters into material business combinations. In accordance with SFAS No. 141, “Business Combinations” (“SFAS 141”), the purchase price is allocated to the various assets acquired and liabilities assumed at their estimated fair value. Fair values of assets acquired and liabilities assumed are based upon available information and we may involve an independent third party to perform an appraisal. Estimating fair values can be 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 SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, management must determine the reporting unit’s fair value using quoted market prices or, in the absence of quoted market prices, valuation techniques which use discounted estimates of future cash flows to be generated by the reporting unit. These cash flow estimates involve management judgments based on a broad range of information and historical results. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill which would adversely impact our results of operations. As of September 30, 2008, our goodwill totaled $1,489.7 million.
Pension Plan Assumptions.The costs of providing benefits under our Pension Plans is dependent on historical information such as employee age, length of service, level of compensation and the actual rate of return on plan assets. In addition, certain assumptions relating to the future are used to determine pension expense including the discount rate applied to benefit obligations, the expected rate of return on plan assets and the rate of compensation increase, among others. Assets of the Pension Plans are held in trust and consist principally of equity and fixed income mutual funds. Changes in plan assumptions as well as fluctuations in actual equity or bond market returns could have a material impact on future pension costs. We believe the two most critical assumptions are (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 $1.4 million in Fiscal 2009. A decrease in the discount rate of 50 basis points to a rate of 6.3% would result in an increase in pre-tax pension cost of approximately $1.6 million in Fiscal 2009.
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Income Taxes.We use the asset and liability method of accounting for income taxes. Under this method, income tax expense is recognized for the amount of taxes payable or refundable for the current year and for deferred tax liabilities and assets for the future tax consequences of events that have been recognized in our financial statements or tax returns. We use assumptions, judgments and estimates to determine our current provision for income taxes. We also use assumptions, judgments and estimates to determine our deferred tax assets and liabilities and any valuation allowance to be recorded against a deferred tax asset. Our assumptions, judgments and estimates relative to the current provision for income tax give consideration to current tax laws, our interpretation of current tax laws and possible outcomes of current and future audits conducted by foreign and domestic tax authorities. Changes in tax law or our interpretation of such and the resolution of current and future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. Our assumptions, judgments and estimates relative to the amount of deferred income taxes take into account estimates of the amount of future taxable income. Actual taxable income or future estimates of taxable income could render our current assumptions, judgments and estimates inaccurate. Changes in the assumptions, judgments and estimates mentioned above could cause our actual income tax obligations to differ significantly from our estimates. As of September 30, 2008, our net deferred tax liabilities totaled $463.5 million.
Subsequent Events — Acquisition of PPL Gas Utilities Corporation and Penn Fuel Propane, LLC and Partnership Sale of Storage Facility
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 Corporation, for cash consideration of $267.6 million plus estimated working capital of $35.4 million. 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 for cash consideration of $32 million plus estimated working capital of $1.6 million. 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 sells propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition with a combination of $120 million cash contributed by UGI, proceeds from the issuance of $108 million principal amount of 6.375% Senior Notes due 2013 and approximately $75 million of borrowings under UGI Utilities Revolving Credit Agreement. AmeriGas OLP funded its acquisition of the assets of CPP principally with borrowings under the AmeriGas OLP 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. The acquisition of CPG and CPP will be reflected in our financial statements beginning October 1, 2008. See Note 15 to Consolidated Financial Statements.
On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated, above-ground storage facility located on leased property in California for approximately $43.0 million in cash. We expect to record an after-tax gain associated with the sale of approximately $11.0 million in the first quarter of Fiscal 2009.
Newly Adopted and Recently Issued Accounting Pronouncements
Effective October 1, 2007, the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). The impact of the adoption of FIN 48 and related disclosures are included in Notes 1 and 4 to Consolidated Financial Statements. As previously mentioned, effective September 30, 2007, we adopted SFAS 158. The impact of SFAS 158 and related disclosures are included in Notes 1 and 5 to Consolidated Financial Statements.
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Below is a listing of recently issued accounting pronouncements by the FASB which have not yet been adopted as of September 30, 2008. See Note 1 to the Consolidated Financial Statements for additional discussion of these pronouncements.
| Title of Pronouncement | Month of Issue | Effective Date | ||
| FASB Staff Position No. SFAS 142-3, “Determination of the Useful Life of Intangible Assets” | April 2008 | Fiscal 2010 | ||
SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities” | March 2008 | Fiscal 2009 (2nd Quarter) | ||
| SFAS 141R, “Business Combinations” | December 2007 | Fiscal 2010 | ||
| SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” | December 2007 | Fiscal 2010 | ||
| FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39” | April 2007 | Fiscal 2009 | ||
| SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities” | February 2007 | Fiscal 2009 | ||
| SFAS 157, “Fair Value Measurements” | September 2006 | Fiscal 2009 |
Forward-Looking Statements
Information contained in this Annual Report on Form 10-K may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other LPG, oil, electricity, and natural gas and the capacity to transport product to our market areas; (3) changes in domestic and foreign laws and regulations, including safety, tax and accounting matters; (4) 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 LPG; (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; and (17) the timing and success of the Company’s efforts to develop new business opportunities.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
“Quantitative and Qualitative Disclosures About Market Risk” are contained in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Market Risk Disclosures” and are incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management’s Annual Report on Internal Control Over Financial Reporting and the financial statements and financial statement schedules referred to in the Index contained on page F-2 of this Report are incorporated herein by reference.
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
ITEM 9A. CONTROLS AND PROCEDURES
| (a) | The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this Report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures as of the end of the period covered by this Report were designed and functioning effectively to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure. | ||
| (b) | For “Management’s Annual Report on Internal Control Over Financial Reporting” see Item 8 of this Report (which information is incorporated herein by reference). | ||
| (c) | No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. |
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 January 9, 2009.
| Captions of Proxy Statement | ||||
| Information | Incorporated by Reference | |||
| Item 10. | Directors, Executive Officers and Corporate Governance | Election of Directors — Nominees; Corporate Governance; Communications with the Board; Board Committees and Meeting Attendance; Securities Ownership of Management - Section 16(a) — Beneficial Ownership Reporting Compliance; Report of the Audit Committee of the Board of Directors | ||
| The Code of Ethics for the Chief Executive Officer and Senior Financial Officers of UGI Corporation is available without charge on the Company’s website, www.ugicorp.com or by writing to Robert W. Krick, Vice President and Treasurer, UGI Corporation, P. O. Box 858, Valley Forge, PA 19482. | ||||
| Item 11. | Executive Compensation | Compensation of Directors; Report of the Compensation and Management Development Committee of the Board of Directors; Compensation Discussion and Analysis; Compensation of Executive Officers; Compensation Committee Interlocks and Insider Participation | ||
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | Securities Ownership of Certain Beneficial Owners; Securities Ownership of Management | ||
| Item 13. | Certain Relationships and Related Transactions, and Director Independence | Election of Directors — Board Committees and Meeting Attendance; Policy for Approval of Related Person Transactions | ||
| Item 14. | Principal Accountant Fees and Services | The Independent Registered Public Accountants |
Equity Compensation Table
The following table sets forth information as of the end of our Fiscal 2008 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 | 6,377,572 | $ | 22.14 | |||||||||
| security holders (1) | 881,675 | $ | 0 | 7,075,400 | ||||||||
| Equity compensation plans not approved by security holders (2) | 274,675 | $ | 11.52 | 0 | ||||||||
| Total | 7,533,922 | $ | 21.710 | (3) | 7,075,400 | |||||||
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| (1) | Column (a) represents 6,377,572 stock options under the 1997 Stock Option and Dividend Equivalent Plan, the 2000 Directors’ Stock Option Plan, the 2000 Stock Incentive Plan and the 2004 Omnibus Equity Compensation Plan, as amended, and 881,675 phantom share units under the 2004 Omnibus Equity Compensation Plan, as amended. | |
| (2) | Column (a) represents 274,675 stock options under the 1992 and 2002 Non-Qualified Stock Option Plans. Under the 1992 and 2002 Non-Qualified Stock Option Plans, the option exercise price is not less than 100% of the fair market value of the Company’s common stock on the date of grant. Generally, options become exercisable in three equal annual installments beginning on the first anniversary of the grant date. All options are non-transferable and generally exercisable only while the holder is employed by the Company or an affiliate, with exceptions for exercise following retirement, disability and death. Options are subject to adjustment in the event of recapitalization, stock splits, mergers and other similar corporate transactions affecting the Company’s common stock. | |
| (3) | Weighted-average exercise price of outstanding options; excludes phantom share units. |
The information concerning the Company’s executive officers required by Item 10 is set forth below.
EXECUTIVE OFFICERS
| Name | Age | Position | ||||
| Lon R. Greenberg | 58 | Chairman and Chief Executive Officer | ||||
| John L. Walsh | 53 | President and Chief Operating Officer | ||||
| Eugene V.N. Bissell | 55 | President and Chief Executive Officer, AmeriGas Propane, Inc. | ||||
| Bradley C. Hall | 55 | Vice President — New Business Development | ||||
| Robert H. Knauss | 55 | Vice President and General Counsel and Assistant Secretary | ||||
| Peter Kelly | 51 | Vice President — Finance and Chief Financial Officer | ||||
| David W. Trego | 50 | President and Chief Executive Officer, UGI Utilities, Inc. | ||||
| François Varagne | 53 | Chairman of the Board and Chief Executive Officer of Antargaz | ||||
All officers, except Mr. Varagne, are elected for a one-year term at the organizational meetings of the respective Boards of Directors held each year. Mr. Varagne was appointed as Chairman of the Board of Antargaz on January 26, 2005. His term of office is five years.
There are no family relationships between any of the officers or between any of the officers and any of the directors.
Lon R. Greenberg
Mr. Greenberg was elected Chairman of 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 compensation committee of Aqua America, Inc.
John L. Walsh
Mr. Walsh is President and Chief Operating Officer and a Director (since April 2005). He is also Vice Chairman and Director of both AmeriGas Propane, Inc. and UGI Utilities, Inc. (since April 2005). He previously served as Chief Executive of the Industrial and Special Products division and executive director of BOC Group PLC, an industrial gases company (2001-2005). From 1986 to 2001, he held various senior management positions with the BOC Group. Prior to joining BOC Group, Mr. Walsh was a Vice President of UGI’s industrial gas division prior to its sale to BOC Group in 1989. From 1981 until 1986, Mr. Walsh held several management positions with affiliates of UGI.
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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). He joined the Company in 1982 and held various positions in UGI Utilities, Inc., including Vice President — Marketing and Rates.
Robert H. Knauss
Mr. Knauss was elected Vice President and General Counsel and Assistant Secretary on September 30, 2003. He previously served as Vice President — Law and Associate General Counsel of AmeriGas Propane, Inc. (1996 to 2003), and Group Counsel — Propane of UGI (1989 to 1996). He joined the Company in 1985. Previously, Mr. Knauss was an associate at the firm of Ballard, Spahr, Andrews & Ingersoll in Philadelphia.
Peter Kelly
Mr. Kelly is Vice President — Finance and Chief Financial Officer (since September 2007). He previously served as Executive Vice President and Chief Financial Officer of Agere Systems, Inc., a global manufacturer of semiconductors, a position in which he served from 2005 to 2007. Mr. Kelly served as Executive Vice President-Global Operations for Agere Systems, Inc. (2001-2005). Mr. Kelly currently serves on the board of directors and the audit and compensation committees of Plexus Corp., an electronics manufacturing services company.
David W. Trego
Mr. Trego is President and Chief Executive Officer of UGI Utilities, Inc. (since October 2004). He previously served as Vice President-Electric Distribution (2002 to 2004). Prior to that assignment, Mr. Trego served in a number of capacities in the Gas Utility Division, including marketing, operations, customer relations and engineering. He joined UGI Utilities in 1987.
François Varagne
Mr. Varagne is Chairman of the Board and Chief Executive Officer of Antargaz (since 2001). Before joining Antargaz, Mr. Varagne was Chairman of the Board and Chief Executive Officer of VIA GTI, a common carrier in France (1998-2001). Prior to that, Mr. Varagne was Chairman of the Board and Chief Executive Officer of Brink’s France, a funds carrier (1997 to 1998).
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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, 2008 and 2007
Consolidated Statements of Income for the years ended September 30, 2008, 2007 and 2006
Consolidated Statements of Cash Flows for the years ended September 30, 2008, 2007 and 2006
Consolidated Statements of Stockholders’ Equity for the years ended September 30, 2008, 2007 and 2006
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, 2008, 2007 and 2006
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.
| (3) | List of Exhibits: |
The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):
| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 3.1 | (Second) Amended and Restated Articles of Incorporation of the Company as amended through June 6, 2005 | UGI | Form 10-Q (6/30/05) | 3.1 | ||||||||
| 3.2 | Bylaws of UGI as amended through September 28, 2004 | UGI | Form 8-K (9/28/04) | 3.2 | ||||||||
| 4 | Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of long-term debt not required to be filed pursuant to Item 601(b)(4) of Regulation S-K) | |||||||||||
| 4.1 | [Intentionally Omitted] | |||||||||||
| 4.2 | The description of the Company’s Common Stock contained in the Company’s registration statement filed under the Securities Exchange Act of 1934, as amended | UGI | Form 8-B/A (4/17/96) | 3. | (4) | |||||||
| 4.3 | UGI’s (Second) Amended and Restated Articles of Incorporation and Bylaws referred to in 3.1 and 3.2 above | |||||||||||
| 4.4 | Third Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of December 1, 2004, and Amendment No. 1 effective October 15, 2007 thereto | AmeriGas Partners, L.P. | Form 10-K (9/30/08) | 3.1 | ||||||||
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| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 4.5 | Indenture, dated May 3, 2005, by and among AmeriGas Partners, L.P., a Delaware limited partnership, AmeriGas Finance Corp., a Delaware corporation, and Wachovia Bank, National Association, as trustee | AmeriGas Partners, L.P. | Form 8-K (5/3/05) | 4.1 | ||||||||
| 4.6 | Indenture, dated January 26, 2006, by and among AmeriGas Partners, L.P., a Delaware limited partnership, AP Eagle Finance Corp., a Delaware corporation, and U.S. Bank National Association, as trustee | AmeriGas Partners, L.P. | Form 8-K (1/26/06) | 4.1 | ||||||||
| 4.7 | Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994 | Utilities | Registration Statement No. 33-77514 (4/8/94) | 4 | (c) | |||||||
| 4.8 | Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association | Utilities | Form 8-K (9/12/06) | 4.2 | ||||||||
| 4.9 | Form of Fixed Rate Medium-Term Note | Utilities | Form 8-K (8/26/94) | 4 | (i) | |||||||
| 4.10 | Form of Fixed Rate Series B Medium-Term Note | Utilities | Form 8-K (8/1/96) | 4 | (i) | |||||||
| 4.11 | Form of Floating Rate Series B Medium-Term Note | Utilities | Form 8-K (8/1/96) | 4 | (ii) | |||||||
| 4.12 | Officer’s Certificate establishing Medium-Term Notes Series | Utilities | Form 8-K (8/26/94) | 4 | (iv) | |||||||
| 4.13 | Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture | Utilities | Form 8-K (8/1/96) | 4 | (iv) | |||||||
| 4.14 | Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture | Utilities | Form 8-K (5/21/02) | 4.2 | ||||||||
| 10.1 | Service Agreement (Rate FSS) dated as of November 1, 1989 between Utilities and Columbia, as modified pursuant to the orders of the Federal Energy Regulatory Commission at Docket No. RS92-5-000 reported at Columbia Gas Transmission Corp., 64 FERC ¶61,060 (1993), order on rehearing, 64 FERC ¶61,365 (1993) | UGI | Form 10-K (9/30/95) | 10.5 | ||||||||
| 10.2 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan Directors Stock Unit Grant Letter dated as of January 2006 | UGI | Form 8-K (12/6/05) | 10.2 | |||||||
| 10.3 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan Directors Nonqualified Stock Option Grant Letter dated as of January 1, 2006 | UGI | Form 8-K (12/6/05) | 10.3 | |||||||
| 10.4 | Credit Agreement dated as of November 14, 2008 among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as Guarantor, Petrolane Incorporated, as Guarantor, Citizens Bank of Pennsylvania, as Syndication Agent, and Wachovia Bank, National Association, as Administrative Agent | AmeriGas Partners, L.P. | Form 8-K (11/14/08) | 10.1 | ||||||||
| *10.5 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Employees Stock Unit Grant Letter dated as of January 1, 2008 | ||||||||||
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| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.6 | ** | UGI Corporation Directors Deferred Compensation Plan Amended and Restated as of January 1, 2000 | UGI | Form 10-K (9/30/00) | 10.6 | |||||||
| 10.7 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Employees Performance Unit Grant Letter dated as of January 1, 2006 | UGI | Form 10-K (9/30/06) | 10.7 | |||||||
| 10.8 | ** | UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006 | UGI | Form 10-K (9/30/07) | 10.8 | |||||||
| 10.9 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan AmeriGas Employees Nonqualified Stock Option Grant Letter dated as of January 1, 2006 | UGI | Form 8-K (12/6/05) | 10.6 | |||||||
| 10.10 | ** | UGI Corporation 1997 Stock Option and Dividend Equivalent Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.10 | |||||||
| 10.11 | ** | AmeriGas Propane, Inc. Executive Employee Severance Plan, as in effect January 1, 2008 | AmeriGas Partners, L.P. | Form 10-K (9/30/08) | 10.4 | |||||||
| 10.12 | ** | UGI Corporation Senior Executive Employee Severance Plan as in effect as of January 1, 2008 | UGI | Form 10-Q (3/31/08) | 10.1 | |||||||
| 10.13 | ** | UGI Corporation 2000 Directors’ Stock Option Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.13 | |||||||
| 10.14 | ** | UGI Corporation 2000 Stock Incentive Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.14 | |||||||
| 10.15 | ** | Letter Agreement dated May 15, 2002 regarding severance arrangement for Mr. Varagne | UGI | Form 10-K (9/30/05) | 10.15 | |||||||
| 10.16 | ** | UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated on July 31, 2007 | UGI | Form 10-K (9/30/07) | 10.16 | |||||||
| 10.17 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 | UGI | Form 8-K (3/27/07) | 10.1 | |||||||
| 10.17 | (a)** | UGI Corporation 2004 Omnibus Equity Compensation Plan, as amended December 7, 2004 — Terms and Conditions as amended December 6, 2005 | UGI | Form 8-K (12/6/05) | 10.10 | |||||||
| 10.18 | Credit Agreement dated as of November 6, 2006 among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as Guarantor, Petrolane Incorporated, as Guarantor, Citigroup Global Markets Inc., as Syndication Agent, J.P. Morgan Securities Inc. and Credit Suisse Securities (USA) LLC, as Co-Documentation Agents, Wachovia Bank, National Association, as Agent, Issuing Bank and Swing Line Bank, and the other financial institutions party thereto | AmeriGas Partners, L.P. | Form 8-K (11/6/06) | 10.1 | ||||||||
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| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.19 | Credit Agreement, dated as of August 11, 2006, among UGI Utilities, Inc., as borrower, and Citibank, N.A., as agent, Wachovia Bank, National Association, as syndication agent, and Citizens Bank of Pennsylvania, Credit Suisse, Cayman Islands Branch, Deutsche Bank AG New York Branch, JPMorgan Chase Bank, N.A., Mellon Bank, N.A., PNC Bank, National Association, and the other financial institutions from time to time parties thereto | Utilities | Form 8-K (8/11/06) | 10.1 | ||||||||
| 10.20 | ** | Form of Confidentiality and Post-Employment Activities Agreement with AmeriGas Propane, Inc., in its own right and as general partner of AmeriGas Partners, L.P., for Messrs. Bissell, Katz and Knauss | AmeriGas Partners, L.P. | Form 10-Q (3/31/05) | 10.3 | |||||||
| 10.21 | [Intentionally Omitted] | |||||||||||
| 10.22 | ** | Summary of Director Compensation as of October 1, 2006 | UGI | Form 10-K (9/30/06) | 10.22 | |||||||
| 10.23 | [Intentionally Omitted] | |||||||||||
| 10.24 | Restricted Subsidiary Guarantee by the Restricted Subsidiaries of AmeriGas Propane, L.P., as Guarantors, for the benefit of Wachovia Bank, National Association and the Banks dated as of November 6, 2006 | AmeriGas Partners, L.P. | Form 10-K (9/30/06) | 10.2 | ||||||||
| 10.25 | Release of Liens and Termination of Security Documents dated as of November 6, 2006 by and among AmeriGas Propane, Inc., Petrolane Incorporated, AmeriGas Propane, L.P., AmeriGas Propane Parts & Service, Inc. and Wachovia Bank, National Association, as Collateral Agent for the Secured Creditors, pursuant to the Intercreditor and Agency Agreement dated as of April 19, 1995 | AmeriGas Partners, L.P. | Form 10-K (9/30/06) | 10.3 | ||||||||
| 10.26 | Purchase Agreement dated January 30, 2001 and Amended and Restated on August 7, 2001 by and among Columbia Energy Group, Columbia Propane Corporation, Columbia Propane, L.P., CP Holdings, Inc., AmeriGas Propane, L.P., AmeriGas Partners, L.P., and AmeriGas Propane, Inc. | AmeriGas Partners, L.P. | Form 8-K (8/8/01) | 10.1 | ||||||||
| 10.27 | Trademark License Agreement dated April 19, 1995 among UGI Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | AmeriGas Partners, L.P. | �� | Form 10-Q (3/31/95) | 10.6 | |||||||
| 10.28 | Trademark License Agreement, dated April 19, 1995 among AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P. | AmeriGas Partners, L.P. | Form 10-Q (3/31/95) | 10.7 | ||||||||
| 10.29 | Stock Purchase Agreement dated May 27, 1989, as amended and restated July 31, 1989, between Texas Eastern Corporation and QFB Partners | Petrolane Incorporated/ AmeriGas Partners, L.P. | Registration Statement No. 33-69450 | 10.16 | (a) | |||||||
| *10.30 | ** | Description of oral compensation arrangements for Messrs. Greenberg, Varagne and Walsh | ||||||||||
| 10.31 | ** | Description of oral employment at-will arrangement for Mr. Bissell | AmeriGas Partners, L.P. | Form 10-K (9/30/05) | 10.30 | |||||||
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| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.32 | ** | AmeriGas Propane, Inc. Supplemental Executive Retirement Plan, as Amended July 30, 2007 | AmeriGas Partners, L.P. | Form 10-K (9/30/07) | 10.25 | |||||||
| 10.33 | ** | AmeriGas Propane, Inc. Executive Annual Bonus Plan, effective as of October 1, 2006 | AmeriGas Partners, L.P. | Form 10-K (9/30/07) | 10.19 | |||||||
| 10.34 | ** | 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 | |||||||
| 10.35 | [Intentionally Omitted] | |||||||||||
| 10.36 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Employees Nonqualified Stock Option Grant Letter dated as of January 1, 2006 | UGI | Form 8-K (12/6/05) | 10.4 | |||||||
| 10.37 | ** | Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Messrs. Greenberg, Kelly and Walsh | UGI | Form 10-Q (6/30/08) | 10.3 | |||||||
| 10.38 | ** | 2002 Non-Qualified Stock Option Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.38 | |||||||
| 10.39 | ** | 1992 Non-Qualified Stock Option Plan Amended and Restated as of May 24, 2005 | UGI | Form 10-K (9/30/06) | 10.39 | |||||||
| 10.40 | ** | AmeriGas Propane, Inc. Discretionary Long-Term Incentive Plan for Non-Executive Key Employees Effective July 1, 2000 and Amended as of January 1, 2005 | AmeriGas Partners, L.P. | Form 10-K (9/30/08) | 10.6 | |||||||
| 10.41 | Service Agreement for comprehensive delivery service (Rate CDS) dated February 23, 1999 between UGI Utilities, Inc. and Texas Eastern Transmission Corporation | UGI | Form 10-K (9/30/00) | 10.41 | ||||||||
| 10.42 | ** | UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees effective December 6, 2005 | UGI | Form 10-K (9/30/06) | 10.66 | |||||||
| 10.43 | ** | Amended and Restated UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Stock Option Grant Letter effective May 20, 2008 | UGI | Form 10-Q (6/30/08) | 10.3 | |||||||
| 10.44 | Purchase Agreement by and among Columbia Propane, L.P., CP Holdings, Inc., Columbia Propane Corporation, National Propane Partners, L.P., National Propane Corporation, National Propane SPG, Inc., and Triarc Companies, Inc. dated as of April 5, 1999 | National Propane Partners, L.P. | Form 8-K (4/19/99) | 10.5 | ||||||||
| 10.45 | Capital Contribution Agreement dated as of August 21, 2001 by and between Columbia Propane, L.P. and AmeriGas Propane, L.P. acknowledged and agreed to by CP Holdings, Inc. | AmeriGas Partners, L.P. | Form 8-K (8/21/01) | 10.2 | ||||||||
| 10.46 | Promissory Note by National Propane L.P., a Delaware limited partnership in favor of Columbia Propane Corporation dated July 19, 1999 | AmeriGas Partners, L.P. | Form 10-K (9/30/01) | 10.39 | ||||||||
| 10.47 | Loan Agreement dated July 19, 1999, between National Propane, L.P. and Columbia Propane Corporation | AmeriGas Partners, L.P. | Form 10-K (9/30/01) | 10.40 | ||||||||
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| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.48 | First Amendment dated August 21, 2001 to Loan Agreement dated July 19, 1999 between National Propane, L.P. and Columbia Propane Corporation | AmeriGas Partners, L.P. | Form 10-K (9/30/01) | 10.41 | ||||||||
| 10.49 | Columbia Energy Group Payment Guaranty dated April 5, 1999 | AmeriGas Partners, L.P. | Form 10-K (9/30/01) | 10.42 | ||||||||
| 10.50 | Keep Well Agreement by and between AmeriGas Propane, L.P. and Columbia Propane Corporation dated August 21, 2001 | AmeriGas Partners, L.P. | Form 10-K (9/30/01) | 10.46 | ||||||||
| 10.51 | ** | AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., as amended and restated effective January 1, 2005 (“AmeriGas 2000 Plan”) | AmeriGas Partners, L.P. | Form 10-K (9/30/08) | 10.7 | |||||||
| 10.51 | (a)** | AmeriGas 2000 Plan Restricted Unit Grant Letter dated as of January 1, 2006 | AmeriGas Partners, L.P. | Form 10-K (9/30/06) | 10.20 | |||||||
| 10.52 | Storage Transportation Service Agreement (Rate Schedule SST) between Utilities and Columbia dated November 1, 1993, as modified pursuant to orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.25 | ||||||||
| 10.53 | Gas Service Delivery and Supply Agreement between Utilities and UGI Energy Services, Inc. dated August 1, 2004 | Utilities | Form 10-K (9/30/04) | 10.32 | ||||||||
| 10.54 | No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern Transmission dated February 23, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.27 | ||||||||
| 10.55 | No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern Transmission dated October 31, 2000, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.28 | ||||||||
| 10.56 | Firm Transportation Service Agreement (Rate Schedule FT-1) between Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.29 | ||||||||
| 10.57 | Amendment No. 1 dated November 1, 2004, to the Service Agreement (Rate FSS) dated as of November 1, 1989 between Utilities and Columbia, as modified pursuant to the orders of the Federal Energy Regulatory Commission at Docket No. RS92-5-000 reported at Columbia Gas Transmission Corp., 64 FERC ¶61,060 (1993), order on rehearing, 64 FERC ¶61,365 (1993) | Utilities | Form 10-K (9/30/04) | 10.26 | ||||||||
| 10.58 | Firm Transportation Service Agreement (Rate Schedule FT) between Utilities and Transcontinental Gas Pipe Line dated October 1, 1996, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/02) | 10.31 | ||||||||
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| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.58 | (a) | Amendment dated March 20, 2007 to the Firm Transportation Service Agreement (Rate Schedule FT) dated October 1, 1996 between UGI Utilities and Transcontinental Gas Pipe Line Corporation, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 8-K (3/20/07) | 10.1 | |||||||
| 10.59 | Amendment No. 1 dated November 1, 2004, to the No-Notice Transportation Service Agreement (Rate Schedule CDS) between Utilities and Texas Eastern Transmission dated February 23, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/04) | 10.30 | ||||||||
| 10.60 | Amendment No. 1 dated November 1, 2004, to the Firm Transportation Service Agreement (Rate Schedule FT-1) between Utilities and Texas Eastern Transmission dated June 15, 1999, as modified pursuant to various orders of the Federal Energy Regulatory Commission | Utilities | Form 10-K (9/30/04) | 10.33 | ||||||||
| 10.61 | Firm Transportation Service Agreement (Rate Schedule FTS) between Utilities and Columbia Gas Transmission dated November 1, 2004 | Utilities | Form 10-K (9/30/04) | 10.34 | ||||||||
| 10.62 | Purchase and Sale Agreement by and between Southern Union Company, as Seller, and UGI Corporation, as Buyer, dated as of January 26, 2006 (See Exhibit No. 10.64) | UGI | Form 8-K (1/26/06) | 10.1 | ||||||||
| 10.63 | Employee Agreement by and between Southern Union Company and UGI Corporation dated as of January 26, 2006 (See Exhibit No. 10.64) | UGI | Form 8-K (1/26/06) | 10.2 | ||||||||
| 10.64 | First Amendment Agreement, dated August 24, 2006, by and between Southern Union Company, as Seller, and UGI Corporation, as Buyer | Utilities | Form 8-K (8/24/06) | 10.2 | ||||||||
| 10.65 | Tax Consolidation Agreement, dated June 18, 2004, entered into by UGI Bordeaux Holding and its Subsidiaries named therein | UGI | Form 10-Q (6/30/04) | 10.8 | ||||||||
| 10.65 | (a) | Amendment No. 1 dated as of June 24, 2004, to Tax Consolidation Agreement, dated June 18, 2004, as amended, entered into by UGI Bordeaux Holding and its Subsidiaries named therein | UGI | Form 10-Q (12/31/05) | 10.5 | |||||||
| 10.65 | (b) | Amendment No. 2 dated as of December 7, 2005 to Tax Consolidation Agreement, dated June 18, 2004, as amended, entered into by UGI Bordeaux Holding and its Subsidiaries named therein | UGI | Form 10-Q (12/31/05) | 10.6 | |||||||
| 10.66 | ** | UGI Corporation 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 | |||||||
| 10.66 | (a)** | Amended and Restated UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Performance Unit Grant Letter effective May 20, 2008 | UGI | Form 10-Q (6/30/08) | 10.2 | |||||||
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| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.67 | Senior Facilities Agreement dated December 7, 2005 by and among AGZ Holding, as Borrower and Guarantor, Antargaz, as Borrower and Guarantor, Calyon, as Mandated Lead Arranger, Facility Agent and Security Agent and the Financial Institutions named therein | UGI | Form 10-Q (12/31/05) | 10.1 | ||||||||
| *10.67 | (a) | 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 | ||||||||||
| 10.68 | Pledge of Financial Instruments Account relating to Financial Instruments held by AGZ Holding in Antargaz, dated December 7, 2005, by and among AGZ Holding, as Pledgor, Calyon, as Security Agent, and the Lenders | UGI | Form 10-Q (12/31/05) | 10.2 | ||||||||
| 10.69 | Pledge of Financial Instruments Account relating to Financial Instruments held by Antargaz in certain subsidiary companies, dated December 7, 2005, by and among Antargaz, as Pledgor, Calyon, as Security Agent, and the Revolving Lenders | UGI | Form 10-Q (12/31/05) | 10.3 | ||||||||
| 10.70 | Letter of Undertakings dated December 7, 2005, by UGI Bordeaux Holding to AGZ Holding, the Parent of Antargaz, and Calyon, the Facility Agent, acting on behalf of the Lenders, (as defined within the Senior Facilities Agreement) | UGI | Form 10-Q (12/31/05) | 10.4 | ||||||||
| 10.71 | Seller’s Guarantee dated February 16, 2001 among Elf Antar France, Elf Aquitaine and AGZ Holding | UGI | Form 10-Q (3/31/04) | 10.5 | ||||||||
| 10.72 | Security Agreement for the Assignment of Receivables dated as of December 7, 2005 by and among AGZ Holding, as Assignor, Calyon, as Security Agent, and the Lenders named therein | UGI | Form 10-Q (12/31/05) | 10.7 | ||||||||
| 10.73 | Security Agreement for the Assignment of Receivables dated as of December 7, 2005 by and among Antargaz, as Assignor, Calyon, as Security Agent, and the Lenders named therein | UGI | Form 10-Q (12/31/05) | 10.8 | ||||||||
| 10.74 | Assignment and Assumption Agreement, dated August 24, 2006, by and between UGI Corporation, as Assignor, and UGI Penn Natural Gas, Inc., as Assignee | Utilities | Form 8-K (8/24/06) | 10.1 | ||||||||
| 10.75 | Guarantee Agreement, dated July 26, 2006, between UGI Corporation, as Guarantor, and Raiffeisen Zentralbank Österreich Aktiengesellschaft (“RZB”), as Beneficiary, relating to the Working Capital Facility dated July 26, 2006 between Flaga GmbH and RZB | UGI | Form 10-Q (6/30/06) | 10.6 | ||||||||
| 10.76 | Guarantee Agreement, dated July 26, 2006, between UGI Corporation, as Guarantor, and RZB, as Beneficiary, relating to the Term Loan Agreement dated July 26, 2006 between Flaga GmbH and RZB | UGI | Form 10-Q (6/30/06) | 10.7 | ||||||||
| 10.77 | Term Loan Agreement, dated July 26, 2006, between Flaga GmbH, as Borrower, and RZB, as Lender | UGI | Form 10-Q (6/30/06) | 10.8 | ||||||||
| 10.78 | Working Capital Facility Agreement, dated July 26, 2006, between Flaga GmbH, as Borrower, and RZB, as Lender | UGI | Form 10-Q (6/30/06) | 10.9 | ||||||||
| *10.79 | Amendment and Extension dated June 10, 2008 to and of the Working Capital Facility Agreement, dated July 26, 2006, between Flaga GmbH, as Borrower, and RZB, as Lender | |||||||||||
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| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.80 | Stock Purchase Agreement by and between PPL Corporation, as Seller, and UGI Utilities, Inc., as Buyer, dated as of March 5, 2008 | Utilities | Form 8-K (3/5/08) | 10.1 | ||||||||
| 10.81 | Amendment dated May 2, 2008 to the Stock Purchase Agreement by and between PPL Corporation, as Seller, and UGI Utilities, Inc., as Buyer, dated as of March 5, 2008 | Utilities | Form 10-Q (3/31/08) | 10.2 | ||||||||
| 10.82 | Assignment and Assumption Agreement, dated August 24, 2006, by and between UGI Corporation, as Assignor, and UGI Utilities, Inc., as Assignee with respect to the Southern Union Company Pension | Utilities | Form 8-K (8/24/06) | 10.3 | ||||||||
| 10.83 | Service Agreement (Rate FSS) dated August 16, 2004 between Columbia Gas Transmission Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.4 | ||||||||
| 10.84 | Service Agreement (Rate SST) dated August 16, 2004 between Columbia Gas Transmission Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.5 | ||||||||
| 10.85 | Firm Transportation Service Agreement (Rate FT) dated February 1, 1992 between Transcontinental Gas Pipe Line Corporation and PG Energy (as successor to Pennsylvania Gas and Water Company) | Utilities | Form 8-K (8/24/06) | 10.6 | ||||||||
| 10.86 | Firm Transportation Service Agreement (Rate FT) dated July 10, 1997 between Transcontinental Gas Pipe Line Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.7 | ||||||||
| 10.87 | Firm Storage and Delivery Service Agreement (Rate GSS) dated July 1, 1996 between Transcontinental Gas Pipe Line Corporation and PG Energy | Utilities | Form 8-K (8/24/06) | 10.8 | ||||||||
| 10.88 | ** | AmeriGas Propane, Inc. Non-Qualified Deferred Compensation Plan, as amended and restated effective January 1, 2009 | AmeriGas Partners, L.P. | Form 10-K (9/30/08) | 10.44 | |||||||
| 10.89 | ** | Description of oral employment at-will arrangement with Peter Kelly, Vice President — Finance and CFO | UGI | Form 8-K (6/21/07) | 10.1 | |||||||
| 10.90 | Extension of Guarantee Agreement dated July 26, 2006, between UGI Corporation, as Guarantor, and Raiffeisen Zentralbank Österreich Aktiengesellschaft (“RZB”), as Beneficiary, relating to the extension of the Working Capital Facility Agreement dated July 26, 2006, between RZB and Flaga GmbH | UGI | Form 10-K (9/30/07) | 10.90 | ||||||||
| 10.91 | Multi-Currency Facility Offer dated May 21, 2007 between Zentraleuropa LPG Holding GmbH and Raiffeisen Zentralbank Österreich Akteingesellschaft | UGI | Form 10-Q (6/30/07) | 10.1 | ||||||||
| *10.91 | (a) | Amendment and Extension dated July 10, 2008 to and of the Multi-Currency Facility Offer dated May 21, 2007 between Zentraleuropa LPG Holding GmbH and Raiffeisen Zentralbank Österreich Akteingesellschaft | ||||||||||
| 10.92 | Guarantee Agreement, dated May 21, 2007, between UGI Corporation, as Guarantor, and Raiffeisen Zentralbank Österreich Aktiengesellschaft, as Beneficiary, relating to the Multi-Currency Working Capital Facility dated May 21, 2007 between Zentraleuropa LPG Holding GmbH and RZB | UGI | Form 10-Q (6/30/07) | 10.2 | ||||||||
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| Incorporation by Reference | ||||||||||||
| Exhibit No. | Exhibit | Registrant | Filing | Exhibit | ||||||||
| 10.93 | Transition Services Agreement, dated October 1, 2008, by and between UGI Utilities, Inc. and PPL Corporation | Utilities | Form 8-K (10/1/08) | 10.1 | ||||||||
| 10.94 | FSS Service Agreement No. 49789, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.) | Utilities | Form 8-K (10/1/08) | 10.2 | ||||||||
| 10.95 | FSS Service Agreement No. 49791, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.) | Utilities | Form 8-K (10/1/08) | 10.3 | ||||||||
| 10.96 | FSS Service Agreement No. 80935, dated October 29, 2004, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to PPL Gas Utilities Corporation) | Utilities | Form 8-K (10/1/08) | 10.4 | ||||||||
| 10.97 | SST Service Agreement No. 49788, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.) | Utilities | Form 8-K (10/1/08) | 10.5 | ||||||||
| 10.98 | SST Service Agreement No. 49790, dated November 20, 1995, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to Penn Fuel Gas, Inc.) | Utilities | Form 8-K (10/1/08) | 10.6 | ||||||||
| 10.99 | SST Service Agreement No. 80934, dated October 29, 2004, by and between Columbia Gas Transmission Corporation and UGI Central Penn Gas, Inc. (as successor to PPL Gas Utilities Corporation) | Utilities | Form 8-K (10/1/08) | 10.7 | ||||||||
| 14 | Code of Ethics for principal executive, financial and accounting officers | UGI | Form 10-K (9/30/03) | 14 | ||||||||
| *21 | Subsidiaries of the Registrant | |||||||||||
| *23 | Consent of PricewaterhouseCoopers LLP | |||||||||||
| *31.1 | Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2008 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, 2008 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, 2008, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |||||||||||
| * | Filed herewith. | |
| ** | As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement. |
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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 21, 2008 | By: | /s/ Peter Kelly | ||
| 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 21, 2008, 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) and Chief Accounting Officer (Principal Accounting Officer) | |
/s/ Stephen D. Ban | Director | |
/s/ Richard C. Gozon | Director | |
/s/ Ernest E. Jones | Director | |
/s/ Anne Pol | Director | |
/s/ Marvin O. Schlanger | Director | |
/s/ James W. Stratton | 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, 2008
F-1
Table of Contents
UGI CORPORATION
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULES
SCHEDULES
| Pages | ||||
| F-3 | ||||
| Financial Statements: | ||||
| F-4 | ||||
| F-5 to F-6 | ||||
| F-7 | ||||
| F-8 | ||||
| F-9 | ||||
| F-10 to F-50 | ||||
| Financial Statement Schedules: | ||||
| For the years ended September 30, 2008, 2007 and 2006: | ||||
| S-1 to S-3 | ||||
| S-4 to S-5 | ||||
Amended Annual Report on Form 10-K/A
An Amended Annual Report on Form 10-K/A containing audited financial statements of the UGI Utilities, Inc., AmeriGas Propane, Inc. and UGI HVAC Enterprises, Inc. savings plans will be filed by amendment within the time period specified by Rule 15d-21(b).
We have omitted all other financial statement schedules because the required information is either (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.
F-2
Table of Contents
Report of Management
Financial Statements
The Company’s consolidated financial statements and other financial information contained in this Annual Report are prepared by management, which is responsible for their fairness, integrity and objectivity. The consolidated financial statements and related information were prepared in accordance with accounting principles generally accepted in the United States of America and include amounts that are based on management’s best judgments and estimates.
The Audit Committee of the Board of Directors is composed of three members, none of whom is an employee of the Company. This Committee is responsible for (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 maintained effective internal control over financial reporting as of September 30, 2008, based on the COSO Framework.
| /s/ Lon R. Greenberg Chief Executive Officer | ||
| /s/ Peter Kelly Chief Financial Officer |
F-3
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of UGI Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of UGI Corporation and its subsidiaries at September 30, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2008 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, 2008 based on criteria established inInternal Control — Integrated Frameworkissued 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 Notes 1 and 4 to the consolidated financial statements, effective October 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109”. Additionally, as discussed in Notes 1 and 5 to the consolidated financial statements, the Company changed the manner in which it accounts for defined benefit pension and other postretirement plans as of September 30, 2007.
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 21, 2008
Philadelphia, Pennsylvania
November 21, 2008
F-4
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
| September 30, | ||||||||
| 2008 | 2007 | |||||||
| ASSETS | ||||||||
Current assets | ||||||||
| Cash and cash equivalents | $ | 245.2 | $ | 251.8 | ||||
| Restricted cash | 70.3 | 12.8 | ||||||
| Accounts receivable (less allowances for doubtful accounts of $40.8 and $37.7, respectively) | 488.0 | 459.8 | ||||||
| Accrued utility revenues | 20.8 | 17.9 | ||||||
| Inventories | 400.8 | 359.5 | ||||||
| Deferred income taxes | 27.5 | 9.6 | ||||||
| Income taxes recoverable | — | 7.8 | ||||||
| Utility regulatory assets | 16.0 | 14.8 | ||||||
| Derivative financial instruments | 12.7 | 20.3 | ||||||
| Prepaid expenses and other current assets | 57.3 | 19.3 | ||||||
| Total current assets | 1,338.6 | 1,173.6 | ||||||
Property, Plant and Equipment | ||||||||
| AmeriGas Propane | 1,368.4 | 1,321.6 | ||||||
| International Propane | 777.3 | 724.5 | ||||||
| UGI Utilities | 1,669.1 | 1,620.0 | ||||||
| Other | 149.8 | 118.5 | ||||||
| 3,964.6 | 3,784.6 | |||||||
| Accumulated depreciation and amortization | (1,515.1 | ) | (1,387.2 | ) | ||||
| Net property, plant, and equipment | 2,449.5 | 2,397.4 | ||||||
Other Assets | ||||||||
| Goodwill | 1,489.7 | 1,498.8 | ||||||
| Intangible assets (less accumulated amortization of $90.1 and $84.2, respectively) | 155.0 | 173.1 | ||||||
| Utility regulatory assets | 91.4 | 89.0 | ||||||
| Investments in equity investees | 63.1 | 63.9 | ||||||
| Other assets | 97.7 | 106.9 | ||||||
| Total assets | $ | 5,685.0 | $ | 5,502.7 | ||||
See accompanying notes to consolidated financial statements.
F-5
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of dollars)
(Millions of dollars)
| September 30, | ||||||||
| 2008 | 2007 | |||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities | ||||||||
| Current maturities of long-term debt | $ | 81.8 | $ | 14.7 | ||||
| UGI Utilities bank loans | 57.0 | 190.0 | ||||||
| International Propane bank loans | 79.4 | 8.9 | ||||||
| Accounts payable | 461.8 | 420.8 | ||||||
| Employee compensation and benefits accrued | 76.3 | 79.4 | ||||||
| Interest accrued | 32.3 | 38.5 | ||||||
| Deposits and advances | 164.8 | 157.2 | ||||||
| Derivative financial instruments | 103.2 | 14.3 | ||||||
| Deferred income taxes | — | 19.0 | ||||||
| Accrued income taxes | 6.7 | — | ||||||
| Other current liabilities | 120.9 | 114.7 | ||||||
| Total current liabilities | 1,184.2 | 1,057.5 | ||||||
Debt and Other Liabilities | ||||||||
| Long-term debt | 1,987.3 | 2,038.8 | ||||||
| Deferred income taxes | 491.0 | 506.4 | ||||||
| Deferred investment tax credits | 6.0 | 6.4 | ||||||
| Other noncurrent liabilities | 439.6 | 379.5 | ||||||
| Total liabilities | 4,108.1 | 3,988.6 | ||||||
| Commitments and contingencies (note 10) | ||||||||
| Minority interests, principally in AmeriGas Partners | 159.2 | 192.2 | ||||||
Common Stockholders’ Equity | ||||||||
| Common Stock, without par value (authorized — 300,000,000 shares; issued — 115,247,694 and 115,152,994 shares, respectively) | 858.3 | 831.6 | ||||||
| Retained earnings | 630.9 | 497.5 | ||||||
| Accumulated other comprehensive (loss) income | (15.2 | ) | 57.7 | |||||
| 1,474.0 | 1,386.8 | |||||||
| Treasury stock, at cost | (56.3 | ) | (64.9 | ) | ||||
| Total common stockholders’ equity | 1,417.7 | 1,321.9 | ||||||
| Total liabilities and stockholders’ equity | $ | 5,685.0 | $ | 5,502.7 | ||||
See accompanying notes to consolidated financial statements.
F-6
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)
| Year Ended September 30, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
Revenues | ||||||||||||
| AmeriGas Propane | $ | 2,815.2 | $ | 2,277.4 | $ | 2,119.3 | ||||||
| International Propane | 1,124.8 | 800.4 | 945.5 | |||||||||
| Utilities | 1,277.5 | 1,166.8 | 822.0 | |||||||||
| Energy Services and other | 1,430.7 | 1,232.3 | 1,334.2 | |||||||||
| 6,648.2 | 5,476.9 | 5,221.0 | ||||||||||
Costs and Expenses | ||||||||||||
| Cost of sales (excluding depreciation shown below): | ||||||||||||
| AmeriGas Propane | 1,908.3 | 1,437.2 | 1,343.8 | |||||||||
| International Propane | 651.9 | 388.6 | 517.2 | |||||||||
| Utilities | 915.4 | 809.3 | 573.9 | |||||||||
| Energy Services and other | 1,269.0 | 1,095.7 | 1,223.0 | |||||||||
| Operating and administrative expenses | 1,157.3 | 1,055.8 | 969.2 | |||||||||
| Utility taxes other than income taxes | 18.3 | 17.7 | 14.3 | |||||||||
| Depreciation and amortization | 184.4 | 169.2 | 148.7 | |||||||||
| Other income, net | (41.6 | ) | (77.9 | ) | (36.8 | ) | ||||||
| 6,063.0 | 4,895.6 | 4,753.3 | ||||||||||
Operating Income | 585.2 | 581.3 | 467.7 | |||||||||
| Loss from equity investees | (2.9 | ) | (3.8 | ) | (2.2 | ) | ||||||
| Loss on extinguishments of debt | — | — | (18.5 | ) | ||||||||
| Interest expense | (142.5 | ) | (139.6 | ) | (123.6 | ) | ||||||
Income before Income Taxes and Minority Interests | 439.8 | 437.9 | 323.4 | |||||||||
| Income taxes | (134.5 | ) | (126.7 | ) | (98.5 | ) | ||||||
| Minority interests, principally in AmeriGas Partners | (89.8 | ) | (106.9 | ) | (48.7 | ) | ||||||
Net Income | $ | 215.5 | $ | 204.3 | $ | 176.2 | ||||||
Earnings Per Common Share: | ||||||||||||
| Basic | $ | 2.01 | $ | 1.92 | $ | 1.67 | ||||||
| Diluted | $ | 1.99 | $ | 1.89 | $ | 1.65 | ||||||
| Average common shares outstanding (millions): | ||||||||||||
| Basic | 107.396 | 106.451 | 105.455 | |||||||||
| Diluted | 108.521 | 107.941 | 106.727 | |||||||||
See accompanying notes to consolidated financial statements.
F-7
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)
| Year Ended September 30, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
| Net income | $ | 215.5 | $ | 204.3 | $ | 176.2 | ||||||
| Reconcile to net cash provided by operating activities: | ||||||||||||
| Depreciation and amortization | 184.4 | 169.2 | 148.7 | |||||||||
| Gain on sale of Arizona storage facility | — | (46.1 | ) | — | ||||||||
| Minority interests, principally in AmeriGas Partners | 89.8 | 106.9 | 48.7 | |||||||||
| Deferred income taxes, net | (0.9 | ) | 27.1 | 7.4 | ||||||||
| Provision for uncollectible accounts | 37.1 | 26.7 | 25.0 | |||||||||
| Loss on extinguishments of debt | — | — | 18.5 | |||||||||
| Stock-based compensation expense | 11.8 | 9.1 | 6.9 | |||||||||
| Net change in settled accumulated other comprehensive income | (3.8 | ) | 21.5 | (37.1 | ) | |||||||
| Other, net | (8.6 | ) | (0.3 | ) | 10.3 | |||||||
| Net change in: | ||||||||||||
| Accounts receivable and accrued utility revenues | (22.2 | ) | (80.5 | ) | 34.8 | |||||||
| Inventories | (42.3 | ) | (9.1 | ) | (31.9 | ) | ||||||
| Utility deferred fuel costs, net of changes in unsettled derivatives | 21.5 | (25.7 | ) | (17.9 | ) | |||||||
| Accounts payable | (6.0 | ) | 30.3 | (61.1 | ) | |||||||
| Other current assets | (28.5 | ) | 4.6 | 5.9 | ||||||||
| Other current liabilities | 16.6 | 18.2 | (55.0 | ) | ||||||||
| Net cash provided by operating activities | 464.4 | 456.2 | 279.4 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
| Expenditures for property, plant and equipment | (232.1 | ) | (223.1 | ) | (191.7 | ) | ||||||
| Acquisitions of businesses, net of cash acquired | (1.3 | ) | (78.8 | ) | (590.4 | ) | ||||||
| Net proceeds from disposals of assets | 11.9 | 3.2 | 8.8 | |||||||||
| Proceeds from sale of Arizona storage facility | — | 49.0 | — | |||||||||
| PG Energy Acquisition working capital adjustment | — | 23.7 | — | |||||||||
| Net proceeds from sale of Energy Ventures | — | — | 13.3 | |||||||||
| Decrease in short-term investments | — | 0.6 | 69.4 | |||||||||
| (Increase) decrease in restricted cash | (57.5 | ) | 1.4 | (9.3 | ) | |||||||
| Other, net | (10.5 | ) | 0.2 | (7.6 | ) | |||||||
| Net cash used by investing activities | (289.5 | ) | (223.8 | ) | (707.5 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
| Dividends on UGI Common Stock | (80.9 | ) | (76.8 | ) | (72.5 | ) | ||||||
| Distributions on AmeriGas Partners publicly held Common Units | (80.9 | ) | (85.0 | ) | (73.6 | ) | ||||||
| Issuances of debt | 34.0 | 20.0 | 1,145.4 | |||||||||
| Repayments of debt including bank loans with maturities greater than three months | (15.7 | ) | (30.6 | ) | (918.3 | ) | ||||||
| (Decrease) increase in UGI Utilities bank loans with maturities of three months or less | (133.0 | ) | (26.0 | ) | 204.8 | |||||||
| Other bank loans increase (decrease) | 72.1 | (1.6 | ) | 2.2 | ||||||||
| Minority interest activity | — | 1.4 | — | |||||||||
| Excess tax benefits from equity-based payment arrangements | 3.4 | 3.7 | 0.9 | |||||||||
| Issuances of UGI Common Stock | 20.9 | 16.4 | 10.8 | |||||||||
| Net cash (used) provided by financing activities | (180.1 | ) | (178.5 | ) | 299.7 | |||||||
EFFECT OF EXCHANGE RATE CHANGES ON CASH | (1.4 | ) | 11.7 | 4.5 | ||||||||
| Cash and cash equivalents (decrease) increase | $ | (6.6 | ) | $ | 65.6 | $ | (123.9 | ) | ||||
| Cash and cash equivalents: | ||||||||||||
| End of year | $ | 245.2 | $ | 251.8 | $ | 186.2 | ||||||
| Beginning of year | 251.8 | 186.2 | 310.1 | |||||||||
| (Decrease) increase | $ | (6.6 | ) | $ | 65.6 | $ | (123.9 | ) | ||||
See accompanying notes to consolidated financial statements.
F-8
Table of Contents
UGI CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Millions of dollars, except per share amounts)
| Accumulated | ||||||||||||||||||||
| Other | ||||||||||||||||||||
| Common | Retained | Comprehensive | Treasury | |||||||||||||||||
| Stock | Earnings | Income (Loss) | Stock | Total | ||||||||||||||||
Balance September 30, 2005 | $ | 793.6 | $ | 266.3 | $ | 16.5 | $ | (78.8 | ) | $ | 997.6 | |||||||||
| Net income | 176.2 | 176.2 | ||||||||||||||||||
| Net loss on derivative instruments (net of tax of $43.7) | (63.7 | ) | (63.7 | ) | ||||||||||||||||
| Reclassification of net losses on derivative instruments (net of tax of $13.2) | 17.5 | 17.5 | ||||||||||||||||||
| Foreign currency translation adjustments (net of tax of $8.1) | 25.9 | 25.9 | ||||||||||||||||||
| Comprehensive income (loss) | 176.2 | (20.3 | ) | 155.9 | ||||||||||||||||
| Cash dividends on Common Stock ($0.69 per share) | (72.5 | ) | (72.5 | ) | ||||||||||||||||
| Common Stock issued: | ||||||||||||||||||||
| Employee and director plans | 4.7 | 3.8 | 8.5 | |||||||||||||||||
| Dividend reinvestment plan | 1.4 | 0.9 | 2.3 | |||||||||||||||||
| Excess tax benefits realized on equity-based compensation | 0.9 | 0.9 | ||||||||||||||||||
| Stock-based compensation expense | 6.9 | 6.9 | ||||||||||||||||||
Balance September 30, 2006 | 807.5 | 370.0 | (3.8 | ) | (74.1 | ) | 1,099.6 | |||||||||||||
| Net income | 204.3 | 204.3 | ||||||||||||||||||
| Net loss on derivative instruments (net of tax of $7.6) | (11.1 | ) | (11.1 | ) | ||||||||||||||||
| Reclassification of net losses on derivative instruments (net of tax of $20.8) | 30.1 | 30.1 | ||||||||||||||||||
| Foreign currency translation adjustments (net of tax of $9.4) | 53.7 | 53.7 | ||||||||||||||||||
| Comprehensive income | 204.3 | 72.7 | 277.0 | |||||||||||||||||
| Adjustment to initially apply SFAS 158 (net of tax of $7.7) | (11.2 | ) | (11.2 | ) | ||||||||||||||||
| Cash dividends on Common Stock ($0.723 per share) | (76.8 | ) | (76.8 | ) | ||||||||||||||||
| Common Stock issued: | ||||||||||||||||||||
| Employee and director plans | 10.2 | 8.5 | 18.7 | |||||||||||||||||
| Dividend reinvestment plan | 1.6 | 0.7 | 2.3 | |||||||||||||||||
| Excess tax benefits realized on equity-based compensation | 3.7 | 3.7 | ||||||||||||||||||
| Stock-based compensation expense | 8.6 | 8.6 | ||||||||||||||||||
Balance September 30, 2007 | 831.6 | 497.5 | 57.7 | (64.9 | ) | 1,321.9 | ||||||||||||||
| Net income | 215.5 | 215.5 | ||||||||||||||||||
| Cumulative effect from adoption of FIN 48 | (1.2 | ) | (1.2 | ) | ||||||||||||||||
| Net loss on derivative instruments (net of tax of $21.6) | (34.9 | ) | (34.9 | ) | ||||||||||||||||
| Reclassification of net gains on derivative instruments (net of tax of $2.1) | (3.1 | ) | (3.1 | ) | ||||||||||||||||
| Benefit plans, principally actuarial losses (net of tax of $20.3) | (28.5 | ) | (28.5 | ) | ||||||||||||||||
| Reclassifications of benefit plans actuarial losses and prior service costs (net of tax of $0.1) | 0.2 | 0.2 | ||||||||||||||||||
| Foreign currency translation adjustments (net of tax of $1.2) | (6.6 | ) | (6.6 | ) | ||||||||||||||||
| Comprehensive income | 214.3 | (72.9 | ) | 141.4 | ||||||||||||||||
| Cash dividends on Common Stock ($0.755 per share) | (80.9 | ) | (80.9 | ) | ||||||||||||||||
| Common Stock issued: | ||||||||||||||||||||
| Employee and director plans | 11.2 | 8.1 | 19.3 | |||||||||||||||||
| Dividend reinvestment plan | 1.7 | 0.5 | 2.2 | |||||||||||||||||
| Excess tax benefits realized on equity-based compensation | 3.4 | 3.4 | ||||||||||||||||||
| Stock-based compensation expense | 10.4 | 10.4 | ||||||||||||||||||
Balance September 30, 2008 | $ | 858.3 | $ | 630.9 | $ | (15.2 | ) | $ | (56.3 | ) | $ | 1,417.7 | ||||||||
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)
Note 1 — Organization and Significant Accounting Policies
Organization.UGI Corporation (“UGI”) is a holding company that, through subsidiaries and joint-venture affiliates, distributes and markets energy products and related services. In the United States, we own and operate (1) retail propane distribution businesses; (2) natural gas and electric distribution utilities; (3) electricity generation facilities; and (4) energy marketing and related businesses. Internationally, we distribute liquefied petroleum gases (“LPG”) in France, central and eastern Europe and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”
We conduct a national propane distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”) and its principal operating subsidiaries AmeriGas Propane, L.P. (“AmeriGas OLP”) and AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (“Eagle OLP”). AmeriGas Partners, AmeriGas OLP and Eagle OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. AmeriGas OLP and Eagle OLP (collectively referred to as “the Operating Partnerships”) comprise the largest retail propane distribution business in the United States serving residential, commercial, industrial, motor fuel and agricultural customers from locations in 46 states. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30, 2008, the General Partner and its wholly owned subsidiary Petrolane Incorporated (“Petrolane”) collectively held a 1% general partner interest and 42.9% limited partner interest in AmeriGas Partners, and an effective 44.4% ownership interest in AmeriGas OLP and Eagle OLP. Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners Common Units (“Common Units”). The remaining 56.1% interest in AmeriGas Partners comprises 32,318,742 publicly held Common Units representing limited partner interests.
The Partnership has no employees. Employees of the General Partner conduct, direct and manage the activities of AmeriGas Partners and AmeriGas OLP. The General Partner also provides management and administrative services to AmeriGas Eagle Holdings, Inc., the general partner of Eagle OLP, under a management services agreement. The General Partner is reimbursed monthly for all direct and indirect expenses it incurs on behalf of the Partnership including all General Partner employee compensation costs and a portion of UGI employee compensation and administrative costs. Although the Partnership’s operating income comprises a significant portion of our consolidated operating income, the Partnership’s impact on our consolidated net income is considerably less due to the Partnership’s significant minority interest.
Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries (1) conducts an LPG distribution business in France; (2) conducts LPG distribution businesses and participates in an LPG joint-venture business in central and eastern Europe (collectively, “Flaga”); and (3) participates in an LPG joint-venture business in the Nantong region of China. Our LPG distribution business in France is conducted through Antargaz, a subsidiary of AGZ Holding (“AGZ”), and its operating subsidiaries (collectively, “Antargaz”). We refer to our foreign operations collectively as “International Propane.” During Fiscal 2006, we formed a Dutch private limited liability company, UGI International Holdings, B.V., to hold our interests in Antargaz and Flaga.
Our natural gas and electric distribution utility businesses are conducted through our wholly owned subsidiary, UGI Utilities, Inc. and its subsidiary, UGI Penn Natural Gas, Inc. (“UGIPNG”). UGI Utilities, Inc. owns and operates (1) natural gas distribution utilities in eastern and northeastern Pennsylvania (“UGI Gas” and “PNG Gas,” respectively) and (2) an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). On August 24, 2006, UGI Utilities, Inc., through UGIPNG, acquired the natural gas business of PG Energy, an operating division of Southern Union Company (the “PG Energy Acquisition”). UGI Gas and PNG Gas (collectively, “Gas Utility”) and Electric Utility are subject to regulation by the Pennsylvania Public Utility Commission (“PUC”). The term “UGI Utilities” is used as an abbreviated reference to UGI Utilities, Inc. or UGI Utilities, Inc. and its subsidiaries, including UGIPNG. On October 1, 2008, UGI Utilities, Inc. acquired the stock of PPL Gas Utilities Corporation, a Pennsylvania natural gas distribution utility and marketer of propane (see Note 15).
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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)
Through other subsidiaries, Enterprises also conducts an energy marketing business primarily in the eastern United States (collectively, “Energy Services”). Energy Services’ wholly owned subsidiary, UGI Development Company (“UGID”), owns and operates a 48-megawatt coal-fired electric generation station located in northeastern Pennsylvania and owns an approximate 6% interest in a 1,711-megawatt coal-fired electric generation station located in western Pennsylvania. In addition, Energy Services’ wholly owned subsidiary UGI Asset Management, Inc., through its subsidiary Atlantic Energy, Inc. (collectively, “Asset Management”), owns a propane storage terminal located in Chesapeake, Virginia. Energy Services also owns and operates a natural gas liquefaction, storage and vaporization facility and propane storage and propane-air mixing assets. Through other subsidiaries, Enterprises owns and operates heating, ventilation, air-conditioning, refrigeration and electrical contracting services businesses in the Middle Atlantic states (“HVAC/R”).
UGI was incorporated in Pennsylvania in 1991. UGI is a “holding company” under the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). PUHCA 2005 and the implementing regulations of the Federal Energy Regulatory Commission (“FERC”) give FERC access to certain holding company books and records and impose certain accounting, record-keeping, and reporting requirements on holding companies. PUHCA 2005 also provides state utility regulatory commissions with access to holding company books and records in certain circumstances. Pursuant to a waiver granted in accordance with FERC’s regulations on the basis of UGI’s status as a single-state holding company system, UGI is not subject to certain of the accounting, record-keeping, and reporting requirements prescribed by FERC’s regulations.
Accounting and Consolidation Principles.Our financial statements are prepared in conformity with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We eliminate all significant intercompany accounts and transactions when we consolidate. We report the public’s limited partner interests in the Partnership and other parties’ interests in consolidated but less than 100% owned subsidiaries as minority interests. Other entities in which we own 50% or less and in which we exercise significant influence over operating and financial policies (“equity investees”) are accounted for by the equity method and presented on a one-line basis. Our principal equity investee is Zentraleuropa LPG Holding which, through subsidiaries, distributes LPG in central and eastern Europe (“ZLH”). Undistributed net earnings of our equity investees included in consolidated retained earnings were not material at September 30, 2008, or 2007. Summarized financial information for our equity investees are not presented because they are not material to our Consolidated Balance Sheets or Consolidated Statements of Income. Entities in which we own less than 20% are accounted for on the cost basis of accounting. Such cost basis investments totaled $53.2 and $52.2 at September 30, 2008 and 2007 and are included in “Other assets” in the Consolidated Balance Sheets.
Gains resulting from issuances and sales of AmeriGas Partners’ Common Units to third parties are recorded as increases to common stockholders’ equity with corresponding decreases to minority interests in accordance with U.S. Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin No. 51, “Accounting for Sales of Common Stock by a Subsidiary” (“SAB 51”). These gains result when the public offering price of the AmeriGas Partners Common Units exceeds the associated carrying amount of our investment in the Partnership on the date of sale. We record deferred income tax liabilities associated with these gains. There were no such gains recorded during Fiscal 2008, Fiscal 2007 or Fiscal 2006.
Reclassifications.We have reclassified certain prior-year balances to conform to the current-year presentation.
Use of Estimates.We make estimates and assumptions when preparing financial statements in conformity with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.
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)
Regulated Utility Operations.We account for the operations of Gas Utility and Electric Utility (collectively, “Utilities”) in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). SFAS 71 requires us to record the effects of rate regulation in the financial statements. SFAS 71 allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenue will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the income statement of an unregulated company. These deferred assets and liabilities are then flowed through the income statement in the period in which the same amounts are included in rates and recovered from or refunded to customers. As required by SFAS 71, we monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these regulatory assets is no longer probable, such assets would be written off against earnings. We believe that SFAS 71 continues to apply to our regulated utility operations and that the recovery of our regulatory assets is probable. For additional information regarding the effects of SFAS 71 on our regulated utility operations, see Note 6.
Deferred Fuel Costs.Gas Utility’s tariffs contain clauses which permit recovery of certain purchased gas costs through the application of purchased gas cost (“PGC”) rates. The clauses provide for periodic adjustments to PGC rates for the difference between the total amount of purchased gas costs collected from customers and the recoverable costs incurred. In accordance with SFAS 71, we defer the difference between amounts recognized in revenues and the applicable gas costs incurred until they are subsequently billed or refunded to customers.
Derivative Instruments.SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.
Substantially all 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, are included in deferred fuel costs in accordance with SFAS 71. Our cash flow hedges relate principally to the variability in cash flows associated with purchases of natural gas, LPG and electricity, variability in exchange rates associated with a portion of U.S. dollar-denominated purchases of LPG by our International Propane operations, variability in cash flows associated with certain of our variable rate long-term debt and variability in interest rates associated with anticipated issuances of long-term debt. We use derivative financial instruments to hedge portions of our net investments in foreign subsidiaries, the functional currency of which is the euro.
For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income, 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 are included in accumulated comprehensive income until such foreign operations are liquidated.
We also use Financial Transmission Rights (“FTRs”) to economically hedge a portion of electricity transmission costs associated with Energy Services’ fixed-price sales contracts and a portion of Electric Utility’s service obligations. Although FTRs are economically effective as hedges of certain electricity transmission costs, they do not currently qualify for hedge accounting treatment. Accordingly, FTRs are recorded at fair value with changes in fair value reflected in cost of sales.
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)
Gains and losses on derivative financial instruments qualifying as cash flow hedges of variability in the purchase prices of natural gas, LPG and electricity are recorded in cost of sales on the Consolidated Statements of Income. Gains and losses on derivative financial instruments hedging the variability in the purchase prices of natural gas at our Gas Utility are recorded in deferred fuel costs in accordance with SFAS 71 and reflected in cost of sales through the application of the PGC mechanism. Gains and losses on derivative financial instruments qualifying as cash flow hedges of the variability in interest rates, when recognized, are recorded in interest expense. The portion of any gains or losses on cash flow hedges determined to be ineffective, or any portion of gains or losses excluded from the measurement of the hedging relationship’s effectiveness, are recorded in other income, net. 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 investment activities.
For a more detailed description of the derivative instruments we use, our objectives for using them, and related supplemental information required by SFAS 133, see Note 11.
Consolidated Statements of Cash Flows.We define cash equivalents as highly liquid investments with maturities of three months or less when purchased. We record cash equivalents at cost plus accrued interest, which approximates market value. Restricted cash represents those cash balances in our commodity futures brokerage accounts which are restricted from withdrawal.
We paid interest totaling $144.9 in Fiscal 2008, $127.4 in Fiscal 2007 and $129.3 in Fiscal 2006. We paid income taxes totaling $134.8 in Fiscal 2008, $93.5 in Fiscal 2007 and $142.6 in Fiscal 2006.
Revenue Recognition.We recognize revenues from the sale of propane and other LPG principally as product is delivered to customers. We record UGI Utilities’ regulated revenues for distribution service and related commodity charges provided to the end of each month which includes an accrual for certain unbilled amounts based upon estimated usage. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. Energy Services records revenues when energy products are delivered to customers. Revenue from the sale of appliances and equipment is recognized at the time of sale or installation.
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 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 and amortization on the Consolidated Statements of Income.
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.
Inventories comprise the following at September 30:
| 2008 | 2007 | |||||||
| Non-utility LPG and natural gas | $ | 199.8 | $ | 158.8 | ||||
| Gas Utility natural gas and LPG | 155.9 | 156.9 | ||||||
| Materials, supplies and other | 45.1 | 43.8 | ||||||
| Total inventories | $ | 400.8 | $ | 359.5 | ||||
At September 30, 2008, UGI Utilities had a non-affiliate storage contract administrative agreement pursuant to which UGI Utilities has, among other things, released certain storage and transportation contracts for the term of the storage agreement. UGI Utilities also transferred certain associated storage inventories upon commencement of the storage agreement, will receive a transfer of storage inventories at the end of the storage agreement (October 31, 2008), and makes payments associated with refilling storage inventories during the term of such agreement. The historical cost of natural gas storage inventories released under this agreement, 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 and LPG inventories” in the table above. The carrying value of gas storage inventories released under this agreement at September 30, 2008 comprising 1.4 billion cubic feet of natural gas was $10.3.
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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)
Earnings Per Common Share.Basic earnings per share reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2008, Fiscal 2007 and Fiscal 2006:
| (Millions of shares) | 2008 | 2007 | 2006 | |||||||||
| Average common shares outstanding for basic computation | 107.396 | 106.451 | 105.455 | |||||||||
| Incremental shares issuable for stock options and common stock awards | 1.125 | 1.490 | 1.272 | |||||||||
| Average common shares outstanding for diluted computation | 108.521 | 107.941 | 106.727 | |||||||||
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 partnerships’ 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 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.
We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income.
Effective October 1, 2007, we adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). For a more detailed discussion of the effects of FIN 48 and related disclosures, see “Newly Adopted Accounting Standards” below and related disclosures in Note 4.
Property, Plant and Equipment and Related Depreciation.The amounts we assign to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition. When 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. When our other businesses retire or dispose of plant and equipment, we eliminate the associated cost and accumulated depreciation and recognize any resulting gain or loss in “Other income, net.”
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)
Property, plant and equipment comprise the following at September 30:
| September 30, | 2008 | 2007 | ||||||
| Utilities: | ||||||||
| Distribution | $ | 1,520.3 | $ | 1,465.9 | ||||
| Transmission | 28.5 | 27.6 | ||||||
| General and other | 120.2 | 126.3 | ||||||
| Total Utilities | 1,669.0 | 1,619.8 | ||||||
| Non-utility: | ||||||||
| Land | 81.8 | 84.3 | ||||||
| Buildings and improvements | 160.6 | 158.7 | ||||||
| Transportation equipment | 94.5 | 91.4 | ||||||
| Equipment, primarily cylinders and tanks | 1,762.7 | 1,648.3 | ||||||
| Electric generation | 84.9 | 65.2 | ||||||
| Other | 111.1 | 116.9 | ||||||
| Total Non-utility | 2,295.6 | 2,164.8 | ||||||
| Total property, plant and equipment | $ | 3,964.6 | $ | 3,784.6 | ||||
We record depreciation expense for plant and equipment over estimated economic useful lives. We record depreciation expense for Utilities’ plant and equipment on a straight-line method over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.4% in Fiscal 2008, 2.7% in Fiscal 2007 and 2.5% in Fiscal 2006. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.6% in Fiscal 2008, 2.7% in Fiscal 2007 and 2.8% in Fiscal 2006. We compute depreciation expense on other property, plant and equipment using the straight-line method over estimated service lives generally ranging from 15 to 40 years for buildings and improvements; 7 to 40 years for storage and customer tanks and cylinders; and 2 to 12 years for vehicles, equipment, and office furniture and fixtures. Depreciation expense was $163.8 in Fiscal 2008, $150.6 in Fiscal 2007 and $130.9 in Fiscal 2006. No depreciation expense is included in cost of sales in the Consolidated Statements of Income.
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 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.
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 2008, Fiscal 2007 or Fiscal 2006.
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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)
Intangible Assets.Intangible assets comprise the following at September 30:
| 2008 | 2007 | |||||||
| Goodwill (not subject to amortization) | $ | 1,489.7 | $ | 1,498.8 | ||||
| Other intangible assets: | ||||||||
| Customer relationships, noncompete agreements and other | $ | 197.3 | $ | 208.9 | ||||
| Trademark (not subject to amortization) | 47.8 | 48.4 | ||||||
| Gross carrying amount | 245.1 | 257.3 | ||||||
| Accumulated amortization | (90.1 | ) | (84.2 | ) | ||||
| Net carrying amount | $ | 155.0 | $ | 173.1 | ||||
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 $18.8 in Fiscal 2008, $16.9 in Fiscal 2007 and $16.5 in Fiscal 2006. No amortization expense is included in cost of sales in the Consolidated Statements of Income. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2009 — $17.2; Fiscal 2010 — $15.5; Fiscal 2011 — $15.1; Fiscal 2012 — $15.0; Fiscal 2013 — $14.4.
In accordance with the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), we amortize intangible assets over their estimated useful lives unless we determined their lives to be indefinite. Goodwill and other intangible assets with indefinite lives are not amortized but are subject to tests for impairment at least annually. SFAS 142 requires that we perform impairment tests more frequently than annually if events or circumstances indicate that the value of goodwill or intangible assets with indefinite lives might be impaired. When performing our impairment tests, we use quoted market prices or, in the absence of quoted market prices, discounted estimates of future cash flows. No provisions for goodwill or other intangible asset impairments were recorded during Fiscal 2008, Fiscal 2007 or Fiscal 2006.
Stock-Based Compensation.We adopted SFAS No. 123 (Revised 2004), “Share-Based Payment” (“SFAS 123R”), effective October 1, 2005. Among other things, SFAS 123R requires expensing the fair value of stock options, a previously optional accounting method. We chose the modified prospective approach which requires that the new guidance be applied to the unvested portion of all outstanding option grants as of October 1, 2005 and to new grants after that date. SFAS 123R also requires the calculation of an accumulated pool of tax windfalls using historical data from the effective date of SFAS No. 123 (prior to its revision). We have calculated a tax windfall pool using the shortcut method and any future tax shortfalls related to equity-based compensation will be charged against common stock up to the amount of the tax windfall pool.
In accordance with SFAS 123R, all of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (“Units”) is measured at fair value on the grant date, date of modification, or end of the period, as applicable, and recognized in earnings over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of the awards may be presented as a liability or as equity in our Consolidated Balance Sheets. We use a Black-Scholes option-pricing model to estimate the fair value of UGI stock options. We use a Monte Carlo valuation approach to estimate the fair value of our UGI and AmeriGas Partners Unit awards. Equity-based compensation costs associated with the portion of Unit awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Equity-based compensation costs associated with the portion of UGI and AmeriGas Partners 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 recognized total pre-tax equity-based compensation expense of $11.8 ($7.7 after-tax), $12.4 ($8.5 after-tax) and $9.0 ($6.0 after-tax) in Fiscal 2008, Fiscal 2007 and Fiscal 2006, respectively.
For a description of our equity-based compensation plans and related disclosures, see Note 8.
F-16
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Deferred Debt Issuance Costs.Included in “Other assets” on our Consolidated Balance Sheets are net deferred debt issuance costs of $15.7 at September 30, 2008 and $19.1 at September 30, 2007. We are amortizing these costs over the terms of the related debt.
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 $223.4 and $228.5 at September 30, 2008 and 2007, respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms.
Environmental and Other Legal Matters.We accrue environmental investigation and cleanup costs when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Amounts accrued generally reflect our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental response costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. In accordance with the terms of the PNG Gas base rate case order which became effective on December 2, 2006, site-specific environmental investigation and remediation costs associated with PNG Gas incurred prior to December 2, 2006 are amortized as removal costs over five-year periods. Such costs incurred after December 1, 2006 are expensed as incurred. At September 30, 2008 and 2007, neither the Company’s undiscounted amount nor its accrued liability for environmental investigation and cleanup costs was material.
Similar to environmental issues, we accrue investigation and other legal costs for other pending and potential claims when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated (see Note 10).
Foreign Currency Translation.Balance sheets of international subsidiaries and our investments in international LPG joint ventures are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income. Where the local currency is not the functional currency, translation adjustments are recorded in net income.
Employee Retirement Plans.We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on our pension plans’ and other postretirement plans’ assets. The market-related value of plan assets, other than equity investments, is based upon market prices. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 5).
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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)
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 subsequent to the adoption of SFAS 158, and foreign currency translation adjustments. Fiscal 2007 other comprehensive income also includes an after-tax charge of $11.2 associated with the initial adoption of SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (“SFAS 158”) (see “Newly Adopted Accounting Standards” below).
The components of accumulated other comprehensive income (loss) at September 30, 2008 and 2007 follow:
| Foreign | ||||||||||||
| Derivative | Currency | |||||||||||
| Postretirement | Instruments Net | Translation | ||||||||||
| Benefit Plans | Losses | Adjustments | ||||||||||
| Balance, September 30, 2008 | $ | (39.4 | ) | $ | (42.5 | ) | $ | 66.7 | ||||
| Balance, September 30, 2007 | $ | (11.2 | ) | $ | (4.4 | ) | $ | 73.3 | ||||
Newly Adopted Accounting Standards.Effective October 1, 2007, we adopted FIN 48, “Accounting for Uncertainty in Income Taxes,” which provides a comprehensive model for the recognition, measurement and disclosure in financial statements of uncertain income tax positions that a company has taken or expects to take on a tax return. Under FIN 48, a company can recognize the benefit of an income tax position only if it is more likely than not (likelihood greater than 50%) that the tax position will be sustained upon tax examination, based solely on the technical merits of the tax position. Otherwise, no benefit can be recognized. Additionally, companies are required to accrue interest and related penalties, if applicable, on all tax exposures for which reserves have been established consistent with jurisdictional tax laws. Any cumulative effect from the adoption of FIN 48 is recorded as an adjustment to opening retained earnings. As a result of the adoption of FIN 48, effective October 1, 2007 we recorded a non-cash reduction to retained earnings of $1.2.
SFAS 158 became effective for us as of September 30, 2007 and requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and postretirement benefit plans such as retiree health and life, with current year changes recognized in shareholders’ equity. SFAS 158 did not change the existing criteria for measurement of periodic benefit costs, plan assets or benefit obligations. The incremental effect of the initial adoption of SFAS 158 reduced stockholders’ equity at September 30, 2007 by $11.2.
Recently Issued Accounting Standards Not Yet Adopted.In April 2008, the FASB issued FASB Staff Position (“FSP”) No. SFAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP SFAS 142-3”). FSP SFAS 142-3 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 SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of FSP SFAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”), and other applicable accounting literature. FSP SFAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 (Fiscal 2010) and must be applied prospectively to intangible assets acquired after the effective date. We are currently evaluating the provisions of FSP SFAS 142-3.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 requires enhanced disclosures in the following areas: (1) qualitative disclosures about the overall objectives and strategies for using derivatives; (2) quantitative disclosures on the fair value of the derivative instruments and related gains and losses in a tabular format; and (3) credit-risk-related contingent features in derivative instruments. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008 (second quarter of Fiscal 2009). We are currently evaluating the impact of the provisions of SFAS 161 on our future disclosures.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
In December 2007, the FASB issued SFAS 141R, “Business Combinations.” SFAS 141R applies to all transactions or other events in which an entity obtains control of one or more businesses. SFAS 141R 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. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008 (Fiscal 2010). Among the more significant changes in accounting for acquisitions are (1) transaction costs will generally be expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, will generally be 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 will be recognized in operations (rather than decreases in goodwill). Generally, the effects of SFAS 141R will depend on future acquisitions.
Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 is effective for us on October 1, 2009 (Fiscal 2010). This standard will significantly change the accounting and reporting relating to noncontrolling interests in a consolidated subsidiary. After adoption, noncontrolling interests ($159.2 and $192.2 at September 30, 2008 and 2007, respectively) will be classified as stockholders’ equity, a change from its current classification between liabilities and stockholders’ equity. Earnings attributable to minority interests ($89.8, $106.9 and $48.7 in Fiscal 2008, Fiscal 2007 and Fiscal 2006, respectively) will be included in net income, although such income will continue to be deducted to measure earnings per share. In addition, changes in a parent’s ownership interest while retaining control will be accounted for as equity transactions and any retained noncontrolling equity investments in a former subsidiary will be initially measured at fair value.
In April 2007, the FASB issued FSP No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP 39-1”). FSP 39-1 permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. In addition, upon the adoption, companies are permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements. FSP 39-1 requires retrospective application for all periods presented. FSP 39-1 was effective for us on October 1, 2008 (Fiscal 2009). The adoption of FSP 39-1 did not have a material effect on our earnings or financial position and will have no effect on our future cash flows.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). Under SFAS 159, we may elect to report individual financial instruments and certain items at fair value with changes in fair value reported in earnings. Once made, this election is irrevocable for those items. SFAS 159 was effective for us on October 1, 2008 (Fiscal 2009). The adoption of SFAS 159 did not impact our financial statements.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. In February 2008, the FASB issued two FSPs amending SFAS 157. FSP SFAS 157-1 amends SFAS 157 to exclude SFAS No. 13, “Accounting for Leases,” and its related interpretive accounting pronouncements that address leasing transactions. FSP SFAS 157-2 delays the effective date of SFAS 157 until fiscal years beginning after November 15, 2008 for non-financial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a non-recurring basis. The standard, as amended, applies prospectively to new fair value measurements for the Company as follows: on October 1, 2008 (Fiscal 2009) the standard applies to our measurements of fair values of financial instruments and recurring fair value measurements of non-financial assets and liabilities; on October 1, 2009 (Fiscal 2010), the standard will apply to all remaining fair value measurements including nonrecurring measurements of non-financial assets and liabilities such as measurement of potential impairments of goodwill, other intangible assets and other long-lived assets. It will also apply to non-financial assets acquired and liabilities assumed that are initially measured at fair value in a business combination but that are not subject to remeasurement at fair value in subsequent periods. SFAS 157 is not expected to have a material effect on our earnings or financial position and will have no effect on our future cash flows.
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 2 — Acquisitions and Divestitures
On August 24, 2006, UGI Utilities acquired certain assets and assumed certain liabilities of Southern Union Company’s (“SU’s”) PG Energy Division, a natural gas distribution utility located in northeastern Pennsylvania, and all of the issued and outstanding stock of SU’s wholly owned subsidiary, PG Energy Services, Inc., pursuant to a Purchase and Sale Agreement, as amended, between SU and UGI dated January 26, 2006 (the “Agreement”). UGI subsequently assigned its rights under the Agreement to UGI Utilities. On August 24, 2006, and in accordance with the terms of the Agreement, UGI Utilities paid SU $580 in cash. The cash payment of $580 was funded with net proceeds from the issuance of $275 of UGI Utilities’ bank loans under a Credit Agreement dated as of August 18, 2006 (the “Bridge Loan”), cash capital contributions from UGI of $265 and borrowings under UGI Utilities’ revolving credit agreement for working capital. In September 2006, UGI Utilities repaid the Bridge Loan with proceeds from the issuance of $175 of 5.75% Senior Notes due 2016 and $100 of 6.21% Senior Notes due 2036. Pursuant to the terms of the Agreement, the initial purchase price was subject to a working capital adjustment equal to the difference between $68.1 and the actual working capital as of the closing date agreed to by both UGI Utilities and SU. In March 2007, UGI Utilities and SU reached an agreement on the working capital adjustment pursuant to which SU paid UGI Utilities approximately $23.7 in cash.
During Fiscal 2007, UGI Utilities completed its review and determination of the fair value of the assets acquired and liabilities assumed. The purchase price of the PG Energy Acquisition, including transaction fees and expenses of approximately $11.0, has been allocated to the assets acquired and liabilities assumed as follows:
| Working capital | $ | 47.3 | ||
| Property, plant, and equipment | 362.3 | |||
| Goodwill | 162.3 | |||
| Regulatory assets | 15.0 | |||
| Other assets | 4.0 | |||
| Noncurrent liabilities | (23.6 | ) | ||
| Total | $ | 567.3 | ||
Substantially all of the goodwill is deductible for income tax purposes over a fifteen-year period.
The operating results of PNG Gas are included in our consolidated results beginning August 24, 2006. The following table presents unaudited pro forma income statement and basic and diluted per share data for Fiscal 2006 as if the acquisition of PNG Gas had occurred as of the beginning of Fiscal 2006:
| 2006 | ||||
| (pro forma) | ||||
| Revenues | $ | 5,545.7 | ||
| Net income | $ | 88.5 | ||
| Earnings per share: | ||||
| Basic | $ | 0.84 | ||
| Diluted | $ | 0.83 | ||
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)
The pro forma results of operations reflect PNG Gas’ historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The pro forma amounts are not necessarily indicative of the operating results that would have occurred had the PG Energy Acquisition been completed as of the date indicated, nor are they necessarily indicative of future operating results. The unaudited pro forma net income and earnings per share for Fiscal 2006 include the effects of a writedown of goodwill of $98 recorded by SU during the three months ended December 31, 2005.
In July 2007, AmeriGas OLP sold its 3.5 million barrel liquefied petroleum gas storage terminal located near Phoenix, Arizona to Plains LPG Services, L.P. The Partnership recorded a pre-tax gain of $46.1 which is included in “Other income, net” in the Fiscal 2007 Consolidated Statement of Income. The gain increased Fiscal 2007 net income by $12.5 or $0.12 per diluted share.
In March 2006, UGID sold its 50% ownership interest in Hunlock Creek Energy Ventures (“Energy Ventures”) to Allegheny Energy Supply Hunlock Creek, LLC. Energy Ventures’ assets primarily comprised a 44-megawatt gas-fired combustion turbine electric generator and a 48-megawatt coal-fired electric generation facility. As part of the transaction, Energy Ventures transferred its ownership in the 48-megawatt coal-fired electric generation station to UGID. UGID recorded a netpre-tax gain of $9.1 associated with this transaction, which is reflected in “Other income, net” in the Fiscal 2006 Consolidated Statement of Income. The gain increased Fiscal 2006 net income by $5.3 or $0.05 per diluted share.
On February 15, 2006, Flaga entered into an agreement with a subsidiary of Progas GmbH & Co KG (“Progas”) to form a joint venture company, ZLH, an Austrian limited liability company, which, through subsidiaries, distributes LPG in the Czech Republic, Hungary, Poland, Slovakia and Romania. ZLH is owned and controlled equally by Flaga and Progas. Progas, headquartered in Dortmund, Germany, is controlled by Thyssen’sche Handelsgesellschaft m.b.H. As part of the joint venture formation, Flaga contributed the shares of its LPG subsidiaries which operate in the Czech Republic and Slovakia to ZLH and paid€9.2 cash to Progas. Progas contributed the shares of its LPG subsidiaries operating in the Czech Republic, Hungary, Poland, Romania and Slovakia to ZLH. The operating subsidiaries distributed a combined approximately 77 million gallons of LPG in these five countries in 2005. In a related transaction, Flaga purchased Progas’ retail LPG business in Austria. The cash consideration for this business was not material.
During Fiscal 2008, AmeriGas OLP acquired several retail propane distribution businesses for total cash consideration of $2.5. During Fiscal 2007, AmeriGas OLP acquired several retail propane distribution businesses, including the retail distribution businesses of All Star Gas Corporation and Shell Gas (LPG) USA and several cylinder refurbishing businesses, for total cash consideration of $79.6 and the issuance of 166,205 Common Units to the General Partner having a fair value of $5.7. During Fiscal 2006, AmeriGas OLP acquired two retail propane distribution businesses and a cylinder refurbishing business for total cash consideration of $3.3. The operating results of these businesses have been included in our consolidated operating results from their respective dates of acquisition. The pro forma effects of these transactions and Flaga’s Fiscal 2006 transactions with Progas are not material.
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)
Note 3 — Debt
Long-term debt comprises the following at September 30:
| 2008 | 2007 | |||||||
AmeriGas Propane: | ||||||||
| AmeriGas Partners Senior Notes: | ||||||||
| 8.875%, due May 2011 (including unamortized premium of $0.1 and $0.2, respectively, effective rate — 8.46%) | $ | 14.7 | $ | 14.8 | ||||
| 7.25%, due May 2015 | 415.0 | 415.0 | ||||||
| 7.125%, due May 2016 | 350.0 | 350.0 | ||||||
| AmeriGas OLP First Mortgage Notes: | ||||||||
| Series D, 7.11%, due March 2009 (including unamortized premium of $0.2 and $0.6, respectively, effective rate — 6.52%) | 70.2 | 70.6 | ||||||
| Series E, 8.50%, due July 2010 (including unamortized premium of $0.1, effective rate — 8.47%) | 80.1 | 80.1 | ||||||
| Other | 3.4 | 2.6 | ||||||
| Total AmeriGas Propane | 933.4 | 933.1 | ||||||
International Propane: | ||||||||
| Antargaz Senior Facilities term loan, due March 2011 | 534.9 | 541.8 | ||||||
| Flaga term loan, due through September 2011 | 50.7 | 59.9 | ||||||
| Other | 3.9 | 3.5 | ||||||
| Total International Propane | 589.5 | 605.2 | ||||||
UGI Utilities: | ||||||||
| Senior Notes: | ||||||||
| 5.75% Notes, due October 2016 | 175.0 | 175.0 | ||||||
| 6.21% Notes, due October 2036 | 100.0 | 100.0 | ||||||
| Medium-Term Notes: | ||||||||
| 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 | — | ||||||
| 6.50% Notes, due August 2033 | 20.0 | 20.0 | ||||||
| 6.13% Notes, due October 2034 | 20.0 | 20.0 | ||||||
| Total UGI Utilities | 532.0 | 512.0 | ||||||
Other | 14.2 | 3.2 | ||||||
| Total long-term debt | 2,069.1 | 2,053.5 | ||||||
| Less current maturities (including net unamortized premium of $0.3 and $0.5, respectively) | (81.8 | ) | (14.7 | ) | ||||
| Total long-term debt due after one year | $ | 1,987.3 | $ | 2,038.8 | ||||
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)
Scheduled principal repayments of long-term debt due in fiscal years 2009 to 2013 follows:
| 2009 | 2010 | 2011 | 2012 | 2013 | ||||||||||||||||
| AmeriGas Propane | $ | 71.2 | $ | 80.7 | $ | 15.2 | $ | 0.5 | $ | 0.4 | ||||||||||
| UGI Utilities | — | — | — | 40.0 | 25.0 | |||||||||||||||
| International Propane and Other | 10.4 | 10.6 | 569.6 | 0.8 | 0.4 | |||||||||||||||
| Total | $ | 81.6 | $ | 91.3 | $ | 584.8 | $ | 41.3 | $ | 25.8 | ||||||||||
AmeriGas Propane
AmeriGas Partners Senior Notes.The 8.875% Senior Notes may be redeemed at our option; a redemption premium applies through May 19, 2009. The 7.25% and 7.125% Senior Notes generally cannot be redeemed at our option prior to May 20, 2010 and 2011, respectively. In January 2006, the Partnership refinanced its Series A and Series C First Mortgage Notes totaling $228.8; $59.6 of the Partnership’s 10% Senior Notes; and an AmeriGas OLP $35 term loan, with proceeds from the issuance of $350 of AmeriGas Partners 7.125% Senior Notes due 2016. The Partnership recognized a loss of $17.1 associated with this refinancing which amount is reflected in “Loss on extinguishments of debt” in the Fiscal 2006 Consolidated Statement of Income. 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 First Mortgage Notes.The General Partner is co-obligor of the Series D and E First Mortgage Notes. AmeriGas OLP may prepay the First Mortgage Notes, in whole or in part. These prepayments include a make whole premium. AmeriGas OLP 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 the First Mortgage Notes, in whole or in part.
AmeriGas OLP Credit Agreements.AmeriGas OLP has a credit agreement (“AmeriGas Credit Agreement”) consisting of (1) a Revolving Credit Facility and (2) an Acquisition Facility. The General Partner and Petrolane are guarantors of amounts outstanding under the AmeriGas Credit Agreement.
Under the Revolving Credit Facility, AmeriGas OLP may borrow up to $125 (including a $100 sublimit for letters of credit) which is subject to restrictions in the AmeriGas OLP First Mortgage Notes (see “Restrictive Covenants” below). The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The Revolving Credit Facility expires on October 15, 2011, but may be extended for additional one-year periods with the consent of the participating banks representing at least 80% of the commitments thereunder. There were no borrowings outstanding under AmeriGas OLP’s Revolving Credit Facility at September 30, 2008 and 2007. Issued and outstanding letters of credit, which reduce available borrowings under the AmeriGas OLP Revolving Credit Facility, totaled $42.9 and $58.0 at September 30, 2008 and 2007, respectively.
The Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 to finance the purchase of propane businesses or propane business assets or, to the extent it is not so used, for working capital and general purposes, subject to restrictions in the Senior Notes indentures. The Acquisition Facility operates as a revolving facility through October 15, 2011, at which time amounts then outstanding will be immediately due and payable. There were no amounts outstanding under the Acquisition Facility at September 30, 2008 and 2007.
The Revolving Credit Facility and the Acquisition Facility permit AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate (5.00% at September 30, 2008), 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.
In October 2008, UGI agreed to provide guarantees of up to $50 to AmeriGas OLP for propane suppliers through September 30, 2009. In addition, on November 14, 2008, AmeriGas OLP entered into a revolving credit agreement with two major banks (“Supplemental Credit Agreement”). The Supplemental Credit Agreement expires on May 14, 2009, and permits AmeriGas OLP to borrow up to $50 for working capital and general purposes. Except for more restrictive covenants regarding the incurrence of additional indebtedness by AmeriGas OLP, the Supplemental Credit Agreement has restrictive covenants substantially similar to the existing AmeriGas Credit Agreement.
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)
AmeriGas OLP Term Loan.In April 2005, AmeriGas OLP entered into a $35 variable-rate term loan due October 1, 2006 (“AmeriGas OLP Term Loan”), which bore interest plus margin at the same rates as the AmeriGas Credit Agreement. Proceeds from the AmeriGas OLP Term Loan were used to repay a portion of the $53.8 maturing AmeriGas OLP First Mortgage Notes. As previously mentioned, the Partnership used a portion of the proceeds from the issuance of the 7.125% Senior Notes due 2016 to repay the AmeriGas OLP Term Loan in January 2006.
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, 2008, these restrictions did not limit the amount of Available Cash AmeriGas Partners could distribute pursuant to the Partnership Agreement (see Note 9).
The AmeriGas OLP credit agreements and First Mortgage Notes restrict the incurrence of additional indebtedness and also restrict certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas OLP credit agreements and First Mortgage Notes require that AmeriGas OLP maintain a maximum ratio of total indebtedness to EBITDA, as defined. In addition, the AmeriGas OLP credit agreements require that AmeriGas OLP maintain a minimum ratio of EBITDA to interest expense, as defined, and 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
On December 7, 2005, Antargaz executed a five-year, floating rate Senior Facilities Agreement with a major French bank comprising a€380 term loan and a€50 revolving credit facility. The proceeds of the€380 term loan were used in December 2005 to repay the then-existing€175 Senior Facilities term loan, to fund the redemption of the€165 High Yield Bonds in January 2006 (including a premium) and for general corporate purposes. As a result of this refinancing, we incurred a pre-tax loss on extinguishment of debt of $1.4 ($0.9 after-tax).
Antargaz’ term loan 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. AGZ has executed interest rate swap agreements with 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 11). The effective interest rate on Antargaz’ term loan at September 30, 2008 and 2007 was 4.40% and 4.05%, respectively. Antargaz’ revolving credit facility permits Antargaz to borrow up to€50 for working capital or general corporate purposes. Borrowings under its revolving credit facility are classified as bank loans. 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. In order to minmize the interest margin it pays on its Senior Facilities Agreement borrowings, in September 2008 Antargaz borrowed€50 ($70.4), the total amount available under its revolving credit facility, which amount remained outstanding at September 30, 2008. This amount was repaid by Antargaz on October 27, 2008. The weighted-average interest rate on Antargaz’ bank loans was 6.0% at September 30, 2008. There were no revolving credit facility borrowings outstanding at September 30, 2007. During October 2008, the Senior Facilities Agreement was amended to, among other things, provide Antargaz a€50 letter of credit guarantee facility. The Senior Facilities Agreement debt is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivable.
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)
Effective in July 2006, Flaga entered into a euro-based, variable-rate term loan facility in an original amount of€48 (€36 of which is outstanding at September 30, 2008) and a working capital facility of up to€8 both of which expire in September 2011. The term loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin. The margin on such borrowings ranges from 0.52% to 1.45%. Generally, semi-annual principal payments of€3 on the term loan are due on March 31 and September 30 each year through Fiscal 2010 with final payments totaling€6.0,€6.4 and€14.6 in March, August and September 2011, respectively. In November 2006, Flaga effectively fixed the euribor component of its interest rate on a substantial portion of the term loan through September 2011 at 3.91% by entering into an interest rate swap agreement. The effective interest rates on Flaga’s term loan at September 30, 2008 and 2007 were 4.80% and 4.43%, respectively. Flaga may prepay the term loan, in whole or in part, without incurring any premium. Flaga repaid its multi-currency acquisition note in July 2006 with the proceeds from the term loan.
Flaga’s borrowings under its working capital facility at September 30, 2008 and 2007 totaled€6.4 ($9.0) and€6.3 ($8.9), respectively. Issued and outstanding guarantees, which reduce available borrowings under the working capital facility, totaled€0.7 ($1.0) at September 30, 2008. Amounts outstanding under the working capital facility are classified as bank loans. Borrowings under the working capital facility bear interest at market rates (a daily euro-based rate) plus a margin. The weighted-average interest rates on Flaga’s bank loans were 4.52% at September 30, 2008 and 5.42% at September 30, 2007.
Restrictive Covenants and Guarantees.The Senior Facilities Agreement restricts the ability of AGZ and its subsidiaries, including Antargaz, to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets. Under this agreement, 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 loan and working capital facility are guaranteed by UGI. In addition, under certain conditions regarding changes in certain financial ratios of UGI, the lending bank may accelerate repayment of the debt.
Flaga’s joint venture, ZLH, has multi-currency working capital facilities that provide for borrowings of up to€16, half of which is guaranteed by UGI. At September 30, 2008, the total amount outstanding under the ZLH facility was€14.2 ($20.0).
UGI Utilities
Revolving Credit Agreement.UGI Utilities has a revolving credit agreement (“UGI Utilities Revolving Credit Agreement”) with 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 Utilities Revolving Credit Agreement, which we classify as bank loans, totaling $57 at September 30, 2008 and $190 at September 30, 2007. In February and March 2006, UGI Utilities repaid two $35 short-term borrowings outstanding under uncommitted arrangements with major banks. There were no amounts borrowed under uncommitted arrangements during Fiscal 2008 or Fiscal 2007. The weighted-average interest rates on UGI Utilities’ Revolving Credit Agreement borrowings at September 30, 2008 and 2007 were 4.36% and 5.24%, respectively. In conjunction with the October 1, 2008 acquisition of PPL Gas Utilities Corporation, UGI made a $120 cash contribution to UGI Utilities on September 25, 2008. This cash contribution was used by UGI Utilities to reduce borrowings under the UGI Utilities Revolving Credit Agreement. On October 1, 2008 UGI Utilities borrowed under the UGI Utilities Revolving Credit Agreement to fund a portion of the PPL Gas Utilities Corporation acquisition (see Note 15).
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)
Restrictive Covenants.UGI Utilities Revolving Credit Agreement requires UGI Utilities to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.
Restricted Net Assets
At September 30, 2008, 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 $1,200.
Note 4 — Income Taxes
Income before income taxes comprises the following:
| 2008 | 2007 | 2006 | ||||||||||
| Domestic | $ | 290.7 | $ | 278.4 | $ | 193.6 | ||||||
| Foreign | 59.3 | 52.6 | 81.1 | |||||||||
| Total income before income taxes | $ | 350.0 | $ | 331.0 | $ | 274.7 | ||||||
The provisions for income taxes consist of the following:
| 2008 | 2007 | 2006 | ||||||||||
| Current expense: | ||||||||||||
| Federal | $ | 92.4 | $ | 65.6 | $ | 54.2 | ||||||
| State | 26.1 | 17.4 | 12.0 | |||||||||
| Foreign | 16.9 | 16.6 | 24.9 | |||||||||
| Total current expense | 135.4 | 99.6 | 91.1 | |||||||||
| Deferred (benefit) expense: | ||||||||||||
| Federal | (1.6 | ) | 24.8 | 2.3 | ||||||||
| State | (3.0 | ) | 1.9 | 1.3 | ||||||||
| Foreign | 4.1 | 0.8 | 4.2 | |||||||||
| Investment tax credit amortization | (0.4 | ) | (0.4 | ) | (0.4 | ) | ||||||
| Total deferred (benefit) expense | (0.9 | ) | 27.1 | 7.4 | ||||||||
| Total income tax expense | $ | 134.5 | $ | 126.7 | $ | 98.5 | ||||||
Federal income taxes for Fiscal 2008, Fiscal 2007 and Fiscal 2006 are net of foreign tax credits of $4.3, $14.1 and $21.2, respectively.
A reconciliation from the statutory federal tax rate to our effective tax rate is as follows:
| 2008 | 2007 | 2006 | ||||||||||
| Statutory federal tax rate | 35.0 | % | 35.0 | % | 35.0 | % | ||||||
| Difference in tax rate due to: | ||||||||||||
| State income taxes, net of federal | 4.4 | 3.8 | 3.4 | |||||||||
| Effects of international operations | (1.4 | ) | (1.4 | ) | (3.3 | ) | ||||||
| Other, net | 0.4 | 0.9 | 0.8 | |||||||||
| Effective tax rate | 38.4 | % | 38.3 | % | 35.9 | % | ||||||
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)
Deferred tax liabilities (assets) comprise the following at September 30:
| 2008 | 2007 | |||||||
| Excess book basis over tax basis of property, plant and equipment | $ | 313.0 | $ | 298.0 | ||||
| Investment in AmeriGas Partners | 172.6 | 181.2 | ||||||
| Intangible assets and goodwill | 49.1 | 50.3 | ||||||
| Utility regulatory assets | 34.0 | 43.2 | ||||||
| Derivative financial instruments | 6.3 | 2.0 | ||||||
| Unrepatriated foreign earnings | 0.8 | 3.9 | ||||||
| Foreign currency translation adjustment | 13.0 | 14.2 | ||||||
| Other | 7.6 | 7.8 | ||||||
| Gross deferred tax liabilities | 596.4 | 600.6 | ||||||
| Pension plan liabilities | (21.7 | ) | (2.5 | ) | ||||
| Employee-related benefits | (31.7 | ) | (29.7 | ) | ||||
| Deferred investment tax credits | (2.5 | ) | (2.7 | ) | ||||
| Utility regulatory liabilities | (3.7 | ) | (3.1 | ) | ||||
| Operating loss carryforwards | (22.1 | ) | (22.8 | ) | ||||
| Allowances for doubtful accounts | (5.9 | ) | (6.8 | ) | ||||
| Foreign tax credit carryforwards | (43.6 | ) | (50.1 | ) | ||||
| Derivative financial instruments | (33.6 | ) | (6.2 | ) | ||||
| Other | (24.6 | ) | (23.1 | ) | ||||
| Gross deferred tax assets | (189.4 | ) | (147.0 | ) | ||||
| Deferred tax assets valuation allowance | 56.5 | 62.2 | ||||||
| Net deferred tax liabilities | $ | 463.5 | $ | 515.8 | ||||
UGI Utilities had recorded deferred tax liabilities of approximately $45.6 as of September 30, 2008 and $42.1 as of September 30, 2007, pertaining to utility temporary differences, principally a result of accelerated tax depreciation for state income tax purposes, the tax benefits of which previously were or will be flowed through to ratepayers. These deferred tax liabilities have been reduced by deferred tax assets of $2.5 at September 30, 2008 and $2.7 at September 30, 2007, pertaining to utility deferred investment tax credits. UGI Utilities had recorded regulatory income tax assets related to these net deferred taxes of $73.7 as of September 30, 2008 and $72.0 as of September 30, 2007. These regulatory income tax assets represent future revenues expected to be recovered through the ratemaking process. We will recognize this regulatory income tax asset in deferred tax expense as the corresponding temporary differences reverse and additional income taxes are incurred.
At September 30, 2008, foreign net operating loss carryforwards of Flaga and certain operations of AGZ totaled $36.1 and $2.3, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to five non-operating subsidiaries which approximate $95 and expire through 2028. We also have operating loss carryforwards of $7.1 for certain operations of AmeriGas Propane and expire through 2028. At September 30, 2008, deferred tax assets relating to operating loss carryforwards include $9.0 for Flaga, $0.8 for AGZ, $1.1 for UGI International (BV), $2.5 for AmeriGas Propane and $8.7 for certain other subsidiaries. A valuation allowance of $11.1 has been provided for all deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries because, on a state reportable basis, it is more likely than not that these assets will expire unused. A valuation allowance of $1.8 was also provided for deferred tax assets related to certain operations of AGZ and UGI International (BV). 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 ofnon-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 stockholders’ equity.
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)
We have foreign tax credit carryforwards of approximately $43.6 expiring through 2019 resulting from the actual and planned repatriation of AGZ’s accumulated earnings since acquisition 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 $5.7 in Fiscal 2008, due primarily to a decrease in the foreign tax credit carryforward of $6.5.
As discussed in Note 1, on October 1, 2007, we adopted FIN 48, “Accounting for Uncertainty in Income Taxes.” The adoption of FIN 48 resulted in a non-cash reduction to retained earnings of $1.2.
The Company conducts business and files tax returns in the U.S., numerous states, local jurisdictions and in certain European countries, principally France and Austria. Our U.S. federal income tax returns and our French tax returns are settled through the 2004 tax year. Our Austrian tax returns are effectively settled through the 2006 tax year. UGI Corporation’s federal income tax returns for Fiscal 2005 and Fiscal 2006 are currently under audit. Although it is not possible to predict with certainty the timing of the conclusion of the pending U.S. federal tax audits in progress, we anticipate that the Internal Revenue Service’s audit of our Fiscal 2005 and Fiscal 2006 U.S. federal income tax returns will likely be completed during Fiscal 2009. 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. The state impact of any amended U.S. federal income tax return remains subject to examination by various states for a period of up to one year after formal notification to the states of such U.S. federal tax return amendments.
We record interest on tax deficiencies and income tax penalties in income taxes. For Fiscal 2008, $0.2 related to interest was recognized in income taxes in the Consolidated Statement of Income.
As of September 30, 2008, we have unrecognized income tax benefits totaling $4.9 including related accrued interest of $0.6. If these unrecognized tax benefits were subsequently recognized, $4.7 would be recorded as a benefit to income taxes on the consolidated statement of income and, therefore, would impact the reported effective tax rate. The amount of reasonably possible changes in unrecognized tax benefits and related interest in the next twelve months is a net reduction of approximately $2.2 as a result of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
| 2008 | ||||
| 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 | ||
Note 5 — Employee Retirement Plans
Defined Benefit Pension and Other Postretirement Plans.We sponsor two defined benefit pension plans for employees of UGI, UGI Utilities, UGIPNG, and certain of UGI’s other domestic wholly owned subsidiaries (“Pension Plans”). We also provide postretirement health care benefits to certain retirees and 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-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)
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, 2008 and 2007. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation.
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
Change in benefit obligations: | ||||||||||||||||
| Benefit obligations — beginning of year | $ | 310.4 | $ | 316.7 | $ | 20.1 | $ | 23.9 | ||||||||
| Service cost | 6.1 | 6.5 | 0.5 | 0.5 | ||||||||||||
| Interest cost | 19.6 | 18.8 | 1.2 | 1.2 | ||||||||||||
| Actuarial gain | (10.0 | ) | (18.4 | ) | (2.5 | ) | (1.9 | ) | ||||||||
| Plan amendments | — | 0.3 | (0.4 | ) | (2.3 | ) | ||||||||||
| Plan settlement or curtailment | — | (0.1 | ) | (2.2 | ) | (0.2 | ) | |||||||||
| Foreign currency | (0.1 | ) | 1.2 | — | 0.3 | |||||||||||
| Benefits paid | (15.1 | ) | (14.6 | ) | (1.1 | ) | (1.4 | ) | ||||||||
| Benefit obligations — end of year | $ | 310.9 | $ | 310.4 | $ | 15.6 | $ | 20.1 | ||||||||
Change in plan assets: | ||||||||||||||||
| Fair value of plan assets — beginning of year | $ | 294.0 | $ | 278.4 | $ | 12.2 | $ | 11.3 | ||||||||
| Actual (loss) gain on plan assets | (34.7 | ) | 29.4 | (1.8 | ) | 1.2 | ||||||||||
| Foreign currency | — | 0.4 | — | — | ||||||||||||
| Employer contributions | 0.5 | 0.4 | 0.7 | 1.1 | ||||||||||||
| Benefits paid | (15.1 | ) | (14.6 | ) | (1.1 | ) | (1.4 | ) | ||||||||
| Fair value of plan assets — end of year | $ | 244.7 | $ | 294.0 | $ | 10.0 | $ | 12.2 | ||||||||
Funded status of the plans — end of year | $ | (66.2 | ) | $ | (16.4 | ) | $ | (5.6 | ) | $ | (7.9 | ) | ||||
Assets (liabilities) recorded in the balance sheet: | ||||||||||||||||
| Prepaid assets (included in other assets) | $ | 1.1 | $ | 1.1 | $ | 0.7 | $ | 0.8 | ||||||||
| Unfunded liabilities (included in other noncurrent liabilities) | (67.3 | ) | (17.5 | ) | (6.3 | ) | (8.7 | ) | ||||||||
| Net amount recognized | $ | (66.2 | ) | $ | (16.4 | ) | $ | (5.6 | ) | $ | (7.9 | ) | ||||
Amounts recorded in stockholders’ equity: | ||||||||||||||||
| Net actuarial loss (gain) | $ | 64.6 | $ | 19.8 | $ | (1.2 | ) | $ | (0.7 | ) | ||||||
| Prior service credit | (0.2 | ) | (0.2 | ) | — | — | ||||||||||
| Total | $ | 64.4 | $ | 19.6 | $ | (1.2 | ) | $ | (0.7 | ) | ||||||
In Fiscal 2009, we estimate that we will amortize $0.9 of net actuarial losses and $0.4 of prior service cost from stockholders’ equity into retiree benefit cost. Comparable amounts in Fiscal 2008 were not material.
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 correspond to the 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.
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)
| Pension Plans | Other Postretirement Benefits | |||||||||||||||||||||||||||||||
| Weighted-average assumptions: | 2008 | 2007 | 2006 | 2005 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||||||||||||
| Discount rate | 6.8 | % | 6.4 | % | 6.0 | % | 5.7 | % | 6.8 | % | 6.4 | % | 6.0 | % | 5.7 | % | ||||||||||||||||
| Expected return on plan assets | 8.5 | % | 8.5 | % | 8.5 | % | 9.0 | % | 5.5 | % | 5.5 | % | 5.6 | % | 5.8 | % | ||||||||||||||||
| Rate of increase in salary levels | 3.8 | % | 3.8 | % | 3.8 | % | 4.0 | % | 3.8 | % | 3.8 | % | 3.8 | % | 4.0 | % | ||||||||||||||||
The ABO for the Pension Plans was $272.4 and $269.3 as of September 30, 2008 and 2007, respectively.
Net periodic pension expense and other postretirement benefit costs include the following components:
| Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||
| 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | |||||||||||||||||||
| Service cost | $ | 6.1 | $ | 6.5 | $ | 6.1 | $ | 0.5 | $ | 0.5 | $ | 0.4 | ||||||||||||
| Interest cost | 19.6 | 18.8 | 14.3 | 1.2 | 1.2 | 1.3 | ||||||||||||||||||
| Expected return on assets | (24.5 | ) | (23.5 | ) | (19.3 | ) | (0.7 | ) | (0.6 | ) | (0.6 | ) | ||||||||||||
| Curtailment gain | — | — | — | (2.2 | ) | — | — | |||||||||||||||||
| Amortization of: | ||||||||||||||||||||||||
| Transition obligation | — | — | — | 0.2 | 0.2 | 0.2 | ||||||||||||||||||
| Prior service cost (benefit) | — | 0.2 | 0.8 | (0.4 | ) | (0.3 | ) | (0.2 | ) | |||||||||||||||
| Actuarial loss (gain) | 0.1 | 1.1 | 2.0 | (0.1 | ) | — | 0.2 | |||||||||||||||||
| Net benefit cost (income) | 1.3 | 3.1 | 3.9 | (1.5 | ) | 1.0 | 1.3 | |||||||||||||||||
| Change in associated regulatory liabilities | — | — | — | 3.4 | 3.1 | 2.7 | ||||||||||||||||||
| Net benefit cost after change in regulatory liabilities | $ | 1.3 | $ | 3.1 | $ | 3.9 | $ | 1.9 | $ | 4.1 | $ | 4.0 | ||||||||||||
Pension Plans assets are held in trust. The Company did not make any contributions to the Pension Plans in Fiscal 2008, Fiscal 2007 or Fiscal 2006 and does not believe it will be required to make any contributions to the Pension Plans during Fiscal 2009 for ERISA funding purposes. In conjunction with the settlement of obligations under a subsidiary retirement benefit plan, Antargaz expects to make a payment of approximately €4.0 during Fiscal 2009.
UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs determined under SFAS No. 106, “Employers Accounting for Postretirement Benefits Other than Pensions” (“SFAS 106”). 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 contribution to the VEBA during Fiscal 2009 is not expected to be material.
Expected payments for pension benefits and for other postretirement welfare benefits are as follows:
| Other | ||||||||
| Pension | Postretirement | |||||||
| Benefits | Benefits | |||||||
| Fiscal 2009 | $ | 15.9 | $ | 1.3 | ||||
| Fiscal 2010 | 16.6 | 1.4 | ||||||
| Fiscal 2011 | 17.3 | 1.4 | ||||||
| Fiscal 2012 | 18.3 | 1.4 | ||||||
| Fiscal 2013 | 18.8 | 1.4 | ||||||
| Fiscal 2014 — 2018 | 108.7 | 6.9 | ||||||
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)
In accordance with our investment strategy to obtain long-term growth, our target asset allocations are to maintain a mix of 65% equities and the remainder in fixed income funds or cash equivalents in the Pension Plans. The targets and actual allocations for the Pension Plans’ and VEBA trust assets at September 30 are as follows:
| Target | Pension Plans | VEBA | ||||||||||||||||||||||
| Pension Plans | VEBA | 2008 | 2007 | 2008 | 2007 | |||||||||||||||||||
| Equities | 65 | % | 60 | % | 63 | % | 63 | % | 57 | % | 66 | % | ||||||||||||
| Fixed income funds | 35 | % | 30 | % | 37 | % | 37 | % | 34 | % | 29 | % | ||||||||||||
| Cash equivalents | N/A | 10 | % | N/A | N/A | 9 | % | 5 | % | |||||||||||||||
UGI Common Stock comprised approximately 9% and 7% of Pension Plans’ assets at September 30, 2008 and 2007, respectively.
The assumed domestic health care cost trend rates are 9.0% for Fiscal 2009, decreasing to 5.5% in Fiscal 2014. A one percentage point change in the assumed health care cost trend rate would increase (decrease) the Fiscal 2008 postretirement benefit cost and obligation as follows:
| 1% Increase | 1% Decrease | |||||||
| Service and interest costs in Fiscal 2008 | $ | 0.1 | $ | (0.1 | ) | |||
| ABO at September 30, 2008 | $ | 0.8 | $ | (0.7 | ) | |||
We also sponsor unfunded and non-qualified supplemental executive retirement plans. At September 30, 2008 and 2007, the PBOs of these plans were $17.5 and $17.3, respectively. We recorded net benefit costs for these plans of $3.0 in Fiscal 2008, $2.4 in Fiscal 2007 and $2.4 in Fiscal 2006. These costs are not included in the tables above. Amounts recorded in stockholders’ equity for these plans were after-tax losses of $2.6 and $3.0 at September 30, 2008 and 2007, respectively, principally representing actuarial losses and prior service costs.
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 $9.4 in Fiscal 2008, $9.2 in Fiscal 2007 and $7.8 in Fiscal 2006.
We also sponsor unfunded and nonqualified supplemental executive savings and deferred compensation plans that provide benefits for executives and certain key employees in excess of benefits that otherwise would have been provided except for the limits imposed by the Internal Revenue Code. The costs associated with these plans were not material.
F-31
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Note 6 — 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:
| 2008 | 2007 | |||||||
| Regulatory assets: | ||||||||
| Income taxes recoverable | $ | 73.7 | $ | 72.0 | ||||
| Postretirement benefits | 4.3 | 4.9 | ||||||
| Environmental costs | 9.0 | 8.3 | ||||||
| Deferred fuel costs | 16.0 | 14.8 | ||||||
| Other | 4.4 | 3.8 | ||||||
| Total regulatory assets | $ | 107.4 | $ | 103.8 | ||||
| Regulatory liabilities: | ||||||||
| Postretirement benefits | $ | 8.9 | $ | 7.5 | ||||
| Total regulatory liabilities | $ | 8.9 | $ | 7.5 | ||||
Income taxes recoverable.This regulatory asset is the result of recording, as required by SFAS No. 109, “Accounting for Income Taxes,” 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 expected to be recovered through the ratemaking process. Based upon current regulatory ratemaking and income tax laws, at September 30, 2008, UGI Utilities expects to recover deferred income taxes associated with these temporary differences over the average remaining lives of the associated property ranging from 1 to approximately 50 years.
Postretirement benefits.The PUC has authorized UGI Utilities to recover certain early retirement benefit costs as well as other postretirement benefit costs incurred subsequent to the adoption of SFAS 106 but prior to such amounts being reflected in tariff rates. These costs are reflected as regulatory assets in the table above. At September 30, 2008, UGI Utilities expects to recover these costs over periods ranging from 1 to 11 years.
Gas Utility and Electric Utility are also recovering ongoing SFAS 106 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 SFAS 106 are being deferred for future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities in the table above. In addition, as a result of the adoption of SFAS 158, UGI Utilities’ postretirement regulatory liability is adjusted annually to reflect changes in the funded status of UGI Gas’ and Electric Utility’s postretirement benefit plan.
Environmental costs.Environmental costs represent the portion of estimated probable environmental remediation and investigation costs that PNG Gas expects to incur in conjunction with the UGIPNG Multi-State Remediation Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (see Note 10). PNG Gas is currently recovering and expects to continue to recover these costs in rates. At September 30, 2008, PNG Gas expects to recover these costs over a period of 11 years.
Deferred fuel costs and refunds.Gas Utility’s tariffs contain clauses which permit recovery of certain purchased gas costs through the application of PGC rates. The clauses provide for periodic adjustments to PGC rates for differences between the total amount of purchased gas costs collected from customers and recoverable costs incurred. Net undercollected gas 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 refunds or costs. Unrealized losses on such contracts at September 30, 2008 and September 30, 2007 were $23.3 and $0.6, respectively. UGI Utilities expects to recover or refund deferred fuel costs generally over a period of 1 to 2 years.
F-32
Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Other.Other regulatory assets comprise a number of items including, among others, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2008, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 years.
UGI Utilities’ regulatory liabilities relating to postretirement benefits 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
In an order entered on November 30, 2006, the PUC approved a settlement of a PNG Gas base rate proceeding. The settlement authorized PNG Gas to increase annual base rates $12.5, or approximately 4%, effective December 2, 2006.
As a result of Pennsylvania’s Electricity Generation Customer Choice and Competition Act that became effective January 1, 1997, all of Electric Utility’s customers are permitted to acquire their electricity from entities other than Electric Utility. Electric Utility remains the provider of last resort (“POLR”) for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service 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 may 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, 2008, which increased the average cost to a residential heating customer by approximately 5.5% over such costs in effect during calendar year 2007. Electric Utility also increased its POLR rates effective January 1, 2007, which increased the average cost to a residential heating customer by approximately 35% over such costs in effect during calendar year 2006, and increased its POLR rates approximately 3% on January 1, 2006.
On July 17, 2008, the PUC approved Electric Utility’s default service procurement, implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with the PUC’s default service regulations. These plans do not affect Electric Utility’s existing POLR settlement effective through December 31, 2009. The approved plans specify how Electric Utility will solicit and acquire default service 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. Under applicable statutory standards, Electric Utility is entitled to fully recover its default service costs.
Note 7 — Series Preferred Stock
UGI has 10,000,000 shares of UGI Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, authorized for issuance. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2008 or 2007.
UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock, including both series subject to and series not subject to mandatory redemption, authorized for issuance. At September 30, 2008 and 2007, there were no shares of UGI Utilities Series Preferred Stock outstanding.
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)
Note 8 — Common Stock and Incentive Stock Award Plans
UGI Common Stock share activity for Fiscal 2006, Fiscal 2007 and Fiscal 2008 follows:
| Issued | Treasury | Outstanding | ||||||||||
| Balance September 30, 2005 | 115,152,994 | (10,303,536 | ) | 104,849,458 | ||||||||
| Issued: | ||||||||||||
| Employee and director plans | — | 498,642 | 498,642 | |||||||||
| Dividend reinvestment plan | — | 106,262 | 106,262 | |||||||||
| Balance September 30, 2006 | 115,152,994 | (9,698,632 | ) | 105,454,362 | ||||||||
| Issued: | ||||||||||||
| Employee and director plans | — | 1,104,824 | 1,104,824 | |||||||||
| Dividend reinvestment plan | — | 87,700 | 87,700 | |||||||||
| Balance September 30, 2007 | 115,152,994 | (8,506,108 | ) | 106,646,886 | ||||||||
| 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 | ||||||||
UGI Stock Option and Incentive Plans.Under UGI Corporation’s 2004 Omnibus Equity Compensation Plan, as Amended and Restated on December 5, 2006 (the “OECP”), we may grant options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”) and other equity-based 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.
Under the OECP, awards representing up to 15,000,000 shares of UGI Common Stock may be granted. The maximum number of shares that may be issued pursuant to grants other than stock options or SARs is 3,200,000. Dividend equivalents on UGI Unit awards to employees will be paid in cash. Dividend equivalents on non-employee director awards are paid in additional Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of Common Stock and cash. Beginning with Fiscal 2006 grants, UGI Unit awards granted to Antargaz employees are settled in shares of Common Stock. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance goals and service conditions. It is the Company’s practice to issue treasury shares to satisfy substantially all option exercises and UGI Unit awards. The Company does not expect to repurchase shares for such purposes during Fiscal 2009.
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. During Fiscal 2006, the Company modified the settlement terms of certain UGI Unit awards previously granted to 28 key employees on January 1, 2006, and the General Partner modified the settlement terms of certain of its AmeriGas Partner Unit awards. The modifications did not affect the number of Units awarded to employees. As a result of the January 1, 2006 modifications, a portion of the fair value of these Unit awards is reflected as equity rather than as a liability in accordance with SFAS 123R. We did not record any incremental equity-based compensation expense as a result of these modifications. Also during Fiscal 2006, we modified the settlement terms of UGI Unit awards granted to non-employee directors. Such awards are now settled 65% in shares of UGI Common Stock and 35% in cash. Prior to this modification, these awards were settled 100% in shares of UGI Common Stock. As a result of this modification, during Fiscal 2006 we recorded additional pre-tax equity-based compensation expense of $1.0.
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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)
UGI Stock Option Awards. Stock option transactions under the OECP and predecessor plans for Fiscal 2006, Fiscal 2007 and Fiscal 2008 follow:
| Weighted | ||||||||||||||||
| Weighted | Total | Average | ||||||||||||||
| Average | Intrinsic | Contract Term | ||||||||||||||
| Shares | Option Price | Value | (Years) | |||||||||||||
| Shares under option — September 30, 2005 | 4,953,018 | $ | 15.95 | |||||||||||||
| Granted | 1,159,100 | $ | 20.67 | |||||||||||||
| Exercised | (232,766 | ) | $ | 11.09 | $ | 2.7 | ||||||||||
| Forfeited | (35,500 | ) | $ | 19.26 | ||||||||||||
| Shares under option — September 30, 2006 | 5,843,852 | $ | 17.06 | |||||||||||||
| Granted | 1,326,800 | $ | 27.12 | |||||||||||||
| Exercised | (812,573 | ) | $ | 13.20 | $ | 11.8 | ||||||||||
| Shares under option — September 30, 2007 | 6,358,079 | $ | 19.65 | |||||||||||||
| 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 | ||||||||||
| Options exercisable — September 30, 2006 | 3,146,952 | $ | 14.56 | |||||||||||||
| Options exercisable — September 30, 2007 | 3,568,746 | $ | 16.75 | |||||||||||||
| Options exercisable — September 30, 2008 | 3,960,778 | $ | 18.93 | $ | 27.9 | 5.6 | ||||||||||
| Non-vested options — September 30, 2008 | 2,691,467 | $ | 25.79 | $ | 3.0 | 8.2 | ||||||||||
Cash received from stock option exercises and associated tax benefits was $15.4 and $3.7, $10.7 and $4.0, and $2.6 and $0.9 in Fiscal 2008, Fiscal 2007 and Fiscal 2006, respectively. As of September 30, 2008, there was $4.0 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 1.9 years.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2008:
| Range of exercise prices | ||||||||||||
| $6.88 - | $15.65 - | $21.73 - | ||||||||||
| $12.81 | $20.48 | $28.02 | ||||||||||
| Options outstanding at September 30, 2008: | ||||||||||||
| Number of options | 775,875 | 2,821,670 | 3,054,700 | |||||||||
| Weighted average remaining contractual life (in years) | 3.6 | 5.7 | 8.2 | |||||||||
| Weighted average exercise price | $ | 11.12 | $ | 19.29 | $ | 26.63 | ||||||
| Options exercisable at September 30, 2008 | ||||||||||||
| Number of options | 775,875 | 2,260,003 | 924,900 | |||||||||
| Weighted average exercise price | $ | 11.12 | $ | 18.99 | $ | 25.33 | ||||||
UGI Stock Option Fair Value Information.The per share weighted-average fair value of stock options granted under our option plans was $5.06 in Fiscal 2008, $5.71 in Fiscal 2007 and $3.88 in Fiscal 2006. 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 2008, Fiscal 2007 and Fiscal 2006 are as follows:
| 2008 | 2007 | 2006 | ||||||||||
| Expected life of option | 5.75 - 6.75 years | 6 - 6.75 years | 6 years | |||||||||
| Weighted average volatility | 20.9% | 21.5% | 21.3% | |||||||||
| Weighted average dividend yield | 2.8% | 2.9% | 3.4% | |||||||||
| Expected volatility | 20.3% - 20.9% | 20.8% - 21.5% | 21.2% - 22.6% | |||||||||
| Expected dividend yield | 2.8% - 2.9% | 2.8% - 2.9% | 2.8% - 3.4% | |||||||||
| Risk free rate | 3.4% - 3.6% | 4.3% - 4.7% | 4.3% - 4.9% | |||||||||
UGI Unit Awards. UGI Stock and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. The number of UGI Performance Units ultimately paid at the end of the performance period (generally three-year periods) may be higher or lower than the target amount, or even zero, based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to companies in the Standard & Poor’s Utilities Index (“UGI comparator group”). Based on the TSR percentile rank, grantees may receive 0% to 200% of the target award granted. If UGI’s TSR ranks below the 40th percentile compared to the UGI comparator group, the employee will not receive an award. At the 40th percentile, the employee will be paid an award equal to 50% of the target award; at the 50th percentile, 100%; and at the 100th percentile, 200%. The actual amount of the award is interpolated between these percentile rankings. Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest.
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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)
The fair value of UGI Stock Units on the grant date is equal to the market price of UGI Stock on the grant date. Under SFAS 123R, UGI Performance Units are equity awards with a market-based condition which, if settled in shares, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of UGI Performance Units awarded after Fiscal 2005 are estimated using a Monte Carlo valuation model. The fair value associated with the target award is accounted for as equity and the fair value of the award over the target, as well as all dividend equivalents, are accounted for as liabilities. The expected term of the UGI Performance Unit awards is three years based on the performance period. Expected volatility is based upon the historical volatility of UGI Common Stock over a three-year period. The risk-free interest rate is based on the yields on U.S. Treasury bonds at the time of grant. Volatility for all comparator companies is based on historical volatility.
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 | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Risk-free rate | 2.7 | % | 4.7 | % | 5.2 | % | ||||||
| Expected life | 3 years | 3 years | 3 years | |||||||||
| Expected volatility | 20.5 | % | 19.6 | % | 19.8 | % | ||||||
| Dividend yield | 3.1 | % | 2.6 | % | 2.8 | % | ||||||
The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $29.70 for Units granted in Fiscal 2008, $26.84 for Units granted in Fiscal 2007 and $21.08 for Units granted in Fiscal 2006.
The following table summarizes UGI Unit award activity for Fiscal 2008:
| 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, 2007 | 879,000 | $ | 19.31 | 487,231 | $ | 16.30 | 391,769 | $ | 23.04 | |||||||||||||||
| Granted | 253,325 | $ | 29.34 | — | $ | — | 253,325 | $ | 29.34 | |||||||||||||||
| Cancelled | (21,850 | ) | $ | 27.52 | — | $ | — | (21,850 | ) | $ | 27.52 | |||||||||||||
| Forfeited | (4,067 | ) | $ | 29.43 | — | $ | — | (4,067 | ) | $ | 29.43 | |||||||||||||
| Vested | — | $ | — | 264,563 | $ | 23.29 | (264,563 | ) | $ | 23.29 | ||||||||||||||
| Performance criteria not met | (184,733 | ) | $ | 20.47 | (184,733 | ) | $ | 20.47 | — | $ | — | |||||||||||||
| Shares paid | (40,000 | ) | $ | 16.63 | (40,000 | ) | $ | 16.63 | — | $ | — | |||||||||||||
| September 30, 2008 | 881,675 | $ | 21.82 | 527,061 | $ | 18.32 | 354,614 | $ | 27.01 | |||||||||||||||
Based on the Company’s TSR for the associated three-year performance periods ended December 31, (1) during Fiscal 2008 the Company did not pay any UGI Performance Unit awards associated with 184,900 awards granted in Fiscal 2005; (2) during Fiscal 2007 the Company paid 206,493 UGI Performance Unit awards comprising shares of UGI Common Stock and $2.8 in cash associated with 193,600 awards granted in Fiscal 2004; and (3) during Fiscal 2006 the Company paid 209,211 UGI Performance Unit awards comprising shares of UGI Common Stock and $2.1 in cash associated with 168,500 awards granted in Fiscal 2003. During Fiscal 2008, Fiscal 2007 and Fiscal 2006, the Company paid Stock Unit awards and cash as follows: Fiscal 2008 — 40,000 Stock Unit awards comprising shares of UGI Common Stock and $0.6 in cash; Fiscal 2007 — 86,000 Stock Unit awards comprising shares of UGI Common Stock and $1.1 in cash; Fiscal 2006 — 20,000 Stock Unit awards comprising shares of UGI Common Stock and $0.2 in cash.
During Fiscal 2008, Fiscal 2007 and Fiscal 2006, we granted UGI Unit awards representing 253,325, 242,371 and 187,326 shares, respectively, having weighted-average grant date fair values per Unit of $29.34, $26.78 and $21.13, respectively. At September 30, 2008, UGI Unit awards representing 881,675 shares of Common Stock were outstanding under the OECP and predecessor equity-based compensation plans.
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)
As of September 30, 2008, there was a total of approximately $5.9 of unrecognized compensation cost associated with 881,675 UGI Unit awards outstanding that is expected to be recognized over a weighted average period of 1.9 years. The total fair values of UGI Units that vested during Fiscal 2008, Fiscal 2007, and Fiscal 2006 were $7.1, $6.9, and $7.2, respectively. As of September 30, 2008 and 2007, total liabilities of $6.3 and $7.9, respectively, associated with UGI Unit awards are reflected in “Other current liabilities” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.
At September 30, 2008, 7,075,400 shares of Common Stock were available for future grants under the OECP, of which up to 2,030,560 may be issued pursuant to grants other than stock options or SARs.
AmeriGas Partners Equity-Based Compensation Plans and Awards.Under the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan (“2000 Propane Plan”), the General Partner may award to key employees the right to receive a total of 500,000 AmeriGas Partners Common Units (“AmeriGas Performance Units”), or cash equivalent to the fair market value of such Common Units. In addition, the 2000 Propane Plan authorizes the crediting of Common Unit distribution equivalents to participants’ accounts. AmeriGas Performance Unit grant recipients are awarded a target number of AmeriGas Performance Units. The number of AmeriGas Performance Units ultimately paid at the end of the performance period (generally three years) may be higher or lower than the target amount based upon the performance of AmeriGas Partners Common Units as compared with a peer group. Percentile rankings and payout percentages are generally the same as those used for the UGI Performance Unit awards. Any distribution equivalents earned are paid in cash. 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 SFAS 123R, AmeriGas Performance Units are equity awards with a market-based condition which, if settled in Common Units, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of AmeriGas Performance Units awarded after Fiscal 2005 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 AmeriGas Units, is accounted for as equity and the fair value of all 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 upon the historical volatility of AmeriGas Partners 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 comparator limited partnerships in the peer group is based on historical volatility.
The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards and related compensation costs:
| Grants Awarded in Fiscal | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Risk-free rate | 3.1 | % | 4.7 | % | 5.2 | % | ||||||
| Expected life | 3 years | 3 years | 3 years | |||||||||
| Expected volatility | 17.7 | % | 17.6 | % | 18.1 | % | ||||||
| Dividend yield | 6.8 | % | 7.1 | % | 7.7 | % | ||||||
We also have a nonexecutive AmeriGas Partners Common Unit plan under which the General Partner may grant awards of up to a total of 200,000 Common Units (comprising “AmeriGas Units”) to key employees who do not participate in the 2000 Propane Plan. Generally, awards under the nonexecutive plan vest at the end of a three-year period and are paid in Common Units and cash. The General Partner made awards under the 2000 Propane Plan and the nonexecutive plan representing 40,050, 49,650 and 38,350 Common Units in Fiscal 2008, Fiscal 2007 and Fiscal 2006, respectively, having weighted-average grant date fair values per Common Unit of $37.91, $33.63 and $29.62, respectively. At September 30, 2008 and 2007, awards representing 126,100 and 119,317 Common Units, respectively, were outstanding. At September 30, 2008, 281,586 and 138,800 Common Units were available for future grants under the 2000 Propane Plan and the nonexecutive plan, respectively.
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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)
The following table summarizes AmeriGas Unit and AmeriGas Performance Unit award activity for Fiscal 2008:
| Total | Vested | Non-Vested | ||||||||||||||||||||||
| Number of | Weighted | Number of | Weighted | Number of | Weighted | |||||||||||||||||||
| AmeriGas | Average | AmeriGas | Average | AmeriGas | Average | |||||||||||||||||||
| Partners | Grant Date | Partners | Grant Date | Partners | Grant Date | |||||||||||||||||||
| Common | Fair Value | Common | Fair Value | Common | Fair Value | |||||||||||||||||||
| Units | (per Unit) | Units | (per Unit) | Units | (per Unit) | |||||||||||||||||||
| September 30, 2007 | 119,317 | $ | 30.63 | 12,583 | $ | 29.87 | 106,734 | $ | 30.72 | |||||||||||||||
| Granted | 40,050 | $ | 37.91 | — | $ | — | 40,050 | $ | 37.91 | |||||||||||||||
| Forfeited | (750 | ) | $ | 32.54 | — | $ | — | (750 | ) | $ | 32.54 | |||||||||||||
| Vested | — | $ | — | 59,900 | $ | 31.10 | (59,900 | ) | $ | 31.10 | ||||||||||||||
| Units paid | (32,517 | ) | $ | 29.49 | (32,517 | ) | $ | 29.49 | — | $ | — | |||||||||||||
| September 30, 2008 | 126,100 | $ | 33.44 | 39,966 | $ | 32.03 | 86,134 | $ | 34.10 | |||||||||||||||
During Fiscal 2008, the Partnership paid 32,517 Common Unit awards comprising AmeriGas Partners Common Units and $0.8 in cash associated with 39,767 awards granted in Fiscal 2005. During Fiscal 2007, the Partnership paid 38,736 Common Unit awards comprising AmeriGas Partners Common Units and $0.6 in cash associated with 51,200 awards granted in Fiscal 2004. During Fiscal 2006, the Partnership paid 6,750 Common Unit awards comprising AmeriGas Partners Common Units and $0.1 in cash associated with 43,500 awards granted in Fiscal 2003.
As of September 30, 2008, there was a total of approximately $1.7 of unrecognized compensation cost associated with 126,100 AmeriGas Common Unit awards that is expected to be recognized over a weighted average period of 1.7 years. The total fair values of Common Units that vested during Fiscal 2008, Fiscal 2007, and Fiscal 2006 were $2.1, $1.2, and $0.6, respectively. As of September 30, 2008 and 2007, total liabilities of $1.0 and $1.8 associated with Common Unit awards are reflected in “Other current liabilities” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.
Note 9 — Partnership Distributions
The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount equal to its Available Cash for such quarter. Available Cash generally means:
| 1. | all cash on hand at the end of such quarter, | ||
| 2. | plus all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter, | ||
| 3. | less the amount of cash reserves established by the General Partner in its reasonable discretion. |
The General Partner may establish reserves for the proper conduct of the Partnership’s business and for distributions during the next four quarters. In addition, certain of the Partnership’s debt agreements require reserves be established for the payment of debt principal and interest.
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)
Distributions of Available Cash are made 98% to limited partners and 2% to the General Partner (representing a 1% General Partner interest in AmeriGas Partners and 1.01% interest in AmeriGas OLP) until Available Cash exceeds the Minimum Quarterly Distribution of $0.55 and the First Target Distribution of $0.055 per Common Unit (or a total of $0.605 per Common Unit). If Available Cash exceeds $0.605 per Common Unit in any quarter, the General Partner will receive a greater percentage of the total Partnership distribution (the “incentive distribution”) but only with respect to the amount by which the distribution per Common Unit to limited partners exceeds $0.605. Accordingly, because the Partnership made quarterly distributions to Common Unitholders in excess of $0.605 per limited partner unit 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 general partner ownership percentage interest alone totaled $3.6 in Fiscal 2008 and $6.8 in Fiscal 2007. The amount of the distributions received by the General Partner during Fiscal 2008 and Fiscal 2007 in excess of its ownership percentage totaled $0.7 and $3.7, respectively.
On July 30, 2007, the General Partner’s Board of Directors approved a distribution of $0.86 per Common Unit payable on August 18, 2007 to unitholders of record on August 10, 2007. This distribution included the regular quarterly distribution of $0.61 per Common Unit and $0.25 per Common Unit reflecting a distribution of a portion of the proceeds from the Partnership’s sale of its Arizona storage facility in July 2007.
Note 10 — Commitments and Contingencies
We lease various buildings and other facilities and transportation, computer and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such leases was $71.2 in Fiscal 2008, $68.1 in Fiscal 2007 and $60.3 in Fiscal 2006.
Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows:
| After | ||||||||||||||||||||||||
| 2009 | 2010 | 2011 | 2012 | 2013 | 2013 | |||||||||||||||||||
| AmeriGas Propane | $ | 43.7 | $ | 37.2 | $ | 31.0 | $ | 25.0 | $ | 19.7 | $ | 40.9 | ||||||||||||
| UGI Utilities | 5.2 | 4.1 | 3.2 | 2.9 | 2.5 | 6.5 | ||||||||||||||||||
| International Propane and other | 8.2 | 4.4 | 2.1 | 1.2 | 0.6 | 1.0 | ||||||||||||||||||
| Total | $ | 57.1 | $ | 45.7 | $ | 36.3 | $ | 29.1 | $ | 22.8 | $ | 48.4 | ||||||||||||
The Company’s businesses enter into contracts of varying lengths and terms to meet their supply, pipeline transportation, storage, capacity and energy needs. Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation and natural gas storage services, which Gas Utility may terminate at various dates through 2029. Gas Utility’s costs associated with transportation and storage capacity agreements are included in its annual PGC filing with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices. Electric Utility purchases its energy needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2012. Energy Services enters into fixed-price contracts with suppliers to purchase natural gas to meet its sales commitments. Generally, these contracts have terms of less than two years. The Partnership enters into fixed-price and, from time to time, variable-priced contracts to purchase a portion of its supply requirements. These contracts generally have terms of less than one year. International Propane, particularly Antargaz, enters into variable-priced contracts to purchase a portion of its supply requirements. Generally, these contracts have terms that do not exceed three years.
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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)
The following table presents contractual obligations under Gas Utility, Electric Utility, Energy Services, AmeriGas Propane and International Propane supply, storage and service contracts existing at September 30, 2008:
| After | ||||||||||||||||||||||||
| 2009 | 2010 | 2011 | 2012 | 2013 | 2013 | |||||||||||||||||||
| Gas Utility and Electric Utility supply, storage and transportation contracts | $ | 420.6 | $ | 146.4 | $ | 75.1 | $ | 68.0 | $ | 41.4 | $ | 109.0 | ||||||||||||
| Energy Services supply contracts | 589.8 | 108.1 | — | — | — | — | ||||||||||||||||||
| AmeriGas Propane supply contracts | 36.5 | — | — | — | — | — | ||||||||||||||||||
| International Propane supply contracts | 414.3 | — | — | — | — | — | ||||||||||||||||||
| Total | $ | 1,461.2 | $ | 254.5 | $ | 75.1 | $ | 68.0 | $ | 41.4 | $ | 109.0 | ||||||||||||
The Partnership and International Propane also enter into other contracts to purchase LPG to meet supply requirements. Generally, these contracts are one- to three-year agreements subject to annual review and call for payment based on either market prices at date of delivery or fixed prices.
On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired the propane distribution businesses of Columbia Energy Group (the “2001 Acquisition”) pursuant to the terms of a purchase agreement (the “2001 Acquisition Agreement”) by and among Columbia Energy Group (“CEG”), Columbia Propane Corporation (“Columbia Propane”), Columbia Propane, L.P. (“CPLP”), CP Holdings, Inc. (“CPH,” and together with Columbia Propane and CPLP, the “Company Parties”), AmeriGas Partners, AmeriGas OLP and the General Partner (together with AmeriGas Partners and AmeriGas OLP, the “Buyer Parties”). As a result of the 2001 Acquisition, AmeriGas OLP acquired all of the stock of Columbia Propane and CPH and substantially all of the partnership interests of CPLP. Under the terms of an earlier acquisition agreement (the “1999 Acquisition Agreement”), the Company Parties agreed to indemnify the former general partners of National Propane Partners, L.P. (a predecessor company of the Columbia Propane businesses) and an affiliate (collectively, “National General Partners”) against certain income tax and other losses that they may sustain as a result of the 1999 acquisition by CPLP of National Propane Partners, L.P. (the “1999 Acquisition”) or the operation of the business after the 1999 Acquisition (“National Claims”). At September 30, 2008, the potential amount payable under this indemnity by the Company Parties was approximately $58.0. These indemnity obligations will expire on the date that CPH acquires the remaining outstanding partnership interest of CPLP, which is expected to occur on or after July 19, 2009. Under the terms of the 2001 Acquisition Agreement, CEG agreed to indemnify the Buyer Parties and the Company Parties against any losses that they sustain under the 1999 Acquisition Agreement and related agreements (“Losses”), including National Claims, to the extent such claims are based on acts or omissions of CEG or the Company Parties prior to the 2001 Acquisition. The Buyer Parties agreed to indemnify CEG against Losses, including National Claims, to the extent such claims are based on acts or omissions of the Buyer Parties or the Company Parties after the 2001 Acquisition. CEG and the Buyer Parties have agreed to apportion certain losses resulting from National Claims to the extent such losses result from the 2001 Acquisition itself. We believe that liability under such indemnity agreement is remote.
Samuel and Brenda Swiger and their son (the “Swigers”) sustained personal injuries and property damage as a result of a fire that occurred when propane that leaked from an underground line ignited. In July 1998, the Swigers filed a class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of Monongalia County, West Virginia, in which they sought to recover an unspecified amount of compensatory and punitive damages and attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants had installed propane gas lines, resulting from the defendants’ alleged failure to install underground propane lines at depths required by applicable safety standards. In 2003, AmeriGas OLP settled the individual personal injury and property damage claims of the Swigers. In 2004, the court granted the plaintiffs’ motion to include customers acquired from Columbia Propane in August 2001 as additional potential class members and the plaintiffs amended their complaint to name additional parties pursuant to such ruling. Subsequently, in March 2005, AmeriGas OLP filed a crossclaim against CEG, former owner of Columbia Propane, seeking indemnification for conduct undertaken by Columbia Propane prior to AmeriGas OLP’s acquisition. Class counsel has indicated that the class is seeking compensatory damages in excess of $12 plus punitive damages, civil penalties and attorneys’ fees.
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Table of Contents
UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)
In 2005, the Swigers 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 both actions.
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 manufactured gas plant operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The Partnership is researching the history of the site and is investigating DEC’s findings. The Partnership has reviewed the preliminary site characterization study prepared by the DEC and is in the early stages of investigating the extent of contamination and the possible existence of other potentially responsible parties. Due to the early stage of such investigation, the amount of expected clean up costs cannot be reasonably estimated. When such expected clean up costs can be reasonably estimated, it is possible that the amount could be material to the Partnership’s results of operations.
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.
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. In accordance with the terms of the PNG base rate case order which became effective December 2, 2006, site-specific environmental investigation and remediation costs associated with PNG Gas incurred prior to December 2, 2006 are amortized as removal costs over five-year periods. Such costs incurred after December 1, 2006 are expensed as incurred.
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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)
As a result of the PG Energy Acquisition, UGI Utilities’ wholly-owned subsidiary, UGIPNG, UGIPNG became party to a Multi-Site Remediation Consent Order and Agreement between PG Energy and the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site Agreement”). The Multi-Site Agreement requires UGIPNG to perform annually a specified level of activities associated with environmental investigation and remediation work at 11 currently owned properties on which MGP-related facilities were operated (“Properties”). Under the Multi-Site Agreement, environmental expenditures, including costs to perform work on the Properties, are capped at $1.1 in any calendar year. The Multi-Site Agreement terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date. At September 30, 2008, our accrued liability for environmental investigation and remediation costs related to the Multi-Site Agreement was $9.0.
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 47% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 in remediation costs and $26 in third-party claims relating to the site and estimates that future remediation costs could be as high as $2.5. SCE&G further asserts that it has received a demand from the United States Justice Department for natural resource damages. UGI Utilities is defending the suit.
City of Bangor, Maine v. Citizens Communications Company.In April 2003, Citizens Communications Company (“Citizens”) served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the plaintiff, City of Bangor, Maine (“City”) sued Citizens to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Citizens’ predecessors at a site on the Penobscot River. Citizens subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Citizens may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Citizens alleges that 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. Studies conducted by the City and Citizens suggest that it could cost up to $18 to clean up the river. Citizen’s third-party claims were stayed pending trial of the City’s suit against Citizens, which took place in September 2005. On June 27, 2006, the court issued an order finding Citizens responsible for 60% of the cleanup costs. On February 14, 2007, Citizens and the City entered into a settlement agreement pursuant to which Citizens agreed to pay $7.6 in exchange for a release of its and all predecessors’ liabilities. Separately, the Maine Department of Environmental Protection has disclaimed its previously announced intention to pursue third-party defendants, including UGI Utilities, for costs incurred by the State of Maine related to contaminants at this site. UGI Utilities believes that it has good defenses to all Citizens’ claims.
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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)
Consolidated Edison Company of New York v. UGI Utilities, Inc.On September 20, 2001, Consolidated Edison Company of New York (“ConEd”) filed suit against UGI Utilities in the United States District Court for the Southern District of New York, seeking contribution from UGI Utilities for an allocated share of response costs associated with investigating and assessing gas plant related contamination at twelve former MGP sites in Westchester County, New York. The complaint alleged that UGI Utilities “owned and operated” the MGPs prior to 1904 as a result of control of subsidiaries that owned the MGPs and at three sites where UGI Utilities allegedly operated the MGPs under lease with the owner.
UGI Utilities successfully moved for summary judgment on all but the three sites where UGI Utilities allegedly operated the MGP sites under lease. On June 17, 2008, UGI Utilities and ConEd agreed to a settlement with respect to the three remaining sites. UGI Utilities’ obligations under the settlement agreement did not have a material effect on the Company’s operating results or financial condition.
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 its subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs for all of the sites would total approximately $215 and asserted that UGI Utilities is responsible for approximately $103 of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23. UGI Utilities is defending the suit. Trial is scheduled for April 2009.
In addition to these matters, there are other pending claims and legal actions arising in the normal course of our businesses. We cannot predict with certainty the final results of environmental and other matters. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows.
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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)
Note 11 — Financial Instruments
In accordance with its commodity hedging policy, the Partnership uses derivative instruments, including price swap and option contracts and contracts for the forward sale of propane, to manage the cost of a portion of its forecasted purchases of propane and to manage market risk associated with propane storage inventories. These derivative instruments have been designated by the Partnership as cash flow or fair value hedges under SFAS 133. The fair values of these derivative instruments are affected by changes in propane product prices. In addition to these derivative instruments, the Partnership may also enter into contracts for the forward purchase of propane as well as fixed-price supply agreements to manage propane market price risk. These contracts qualify for the normal purchases and normal sales exception of SFAS 133 and therefore are not adjusted to fair value. In addition, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign exchange contracts. Antargaz may also enter into other contracts that are similar to those used by the Partnership.
Flaga also uses derivative instruments, principally price swap contracts, to reduce market risk associated with purchases of LPG. These contracts may or may not qualify for hedge accounting under SFAS 133. Antargaz uses forward foreign exchange contracts and may use other derivative instruments, similar to those used by the Partnership, to manage the cost of a portion of its forecasted purchases of LPG.
Energy Services uses exchange-traded and over-the-counter natural gas futures contracts to manage market risk associated with forecasted purchases of natural gas it sells under firm commitments and forecasted sales at market prices. In addition, Energy Services uses price swap and option contracts to manage market risk associated with forecasted purchases of propane it sells under firm commitments. These derivative instruments are designated as cash flow hedges. The fair values of natural gas futures, price swap and option contracts are affected by changes in natural gas and propane prices.
In accordance with its commodity hedging policy, Gas Utility has entered into natural gas futures and call option contracts to reduce volatility in the cost of gas it purchases for its retail core-market customers and Electric Utility entered into an electric swap agreement, which expired in December 2007, in order to reduce the volatility in the cost of anticipated electricity requirements. Because the cost of Gas Utility’s natural gas futures and option contracts and any associated gains or losses are included in Gas Utility’s PGC recovery mechanism, as these contracts are recorded at fair value in accordance with SFAS 133, any gains or losses are deferred for future refund to or recovery from Gas Utility’s ratepayers (see Note 6).
We enter into interest rate protection agreements (“IRPAs”) designed to manage interest rate risk associated with planned issuances of fixed-rate long-term debt. We designate these IRPAs as cash flow hedges. Gains or losses on IRPAs are included in accumulated other comprehensive income and are reclassified to interest expense as the interest expense on the associated debt affects earnings. Antargaz has entered into interest rate swap agreements to fix the variable interest component of its Senior Facilities term loan through March 2011 and Flaga has entered into an interest rate swap agreement to fix the variable interest component of substantially all of its term loan through September 2011. We designate these interest rate swaps as cash flow hedges.
Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, from purchases through monthly PJM auctions. Energy Services purchases FTRs to economically hedge certain transmission costs associated with its fixed-price electricity sales contracts. 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. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Although FTRs are economically effective as hedges of congestion charges, they do not currently qualify for hedge accounting treatment. Accordingly, FTRs are recorded at fair value with changes in fair value reflected in cost of sales.
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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)
Certain of the Company’s over-the-counter derivative financial instruments have bilateral collateral provisions which require the transfer of cash collateral when the values of the derivative instruments reach certain threshold amounts. Although commodity propane prices increased through much of Fiscal 2008, a precipitous decline in prices in late Fiscal 2008 which continued into Fiscal 2009 has resulted in greater cash needed by the Partnership to fund counterparty collateral requirements. These collateral requirements are associated with derivative financial instruments used by the Partnership to manage market price risk associated with fixed sales price commitments to customers principally during the heating-season months of October to March. At September 30, 2008, the Partnership had made collateral deposits of $17.8 with counterparties. At November 20, 2008, such collateral deposits totaled $144.5. Additionally, our natural gas and electricity exchange-traded futures contracts which are guaranteed by the New York Mercantile Exchange (“NYMEX”) generally require cash deposits in margin accounts. At September 30, 2008, Gas Utility’s and Energy Services’ restricted cash in brokerage accounts totaled $70.3.
We are also a party to a number of contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery of natural gas, 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 are not subject to the accounting requirements of SFAS 133 because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business or the value of the contract is directly associated with the price or value of a service.
During Fiscal 2008, Fiscal 2007 and Fiscal 2006, amounts recognized in earnings representing cash flow hedge ineffectiveness were not material. Gains and losses included in accumulated other comprehensive income at September 30, 2008 relating to cash flow hedges will be reclassified into (1) cost of sales when the forecasted purchase or sale of LPG, natural gas or electricity subject to the hedges impacts net income and (2) interest expense when interest on anticipated issuances of fixed-rate long-term debt or interest expense on variable rate debt subject to interest rate swaps is reflected in net income. Included in accumulated other comprehensive income at September 30, 2008 are net after-tax losses of approximately $7.4 from settled IRPAs and IRPAs associated with forecasted issuances of debt anticipated to occur during Fiscal 2009 and Fiscal 2010. The amount of these net losses that is expected to be reclassified into net income during the next twelve months is not material. Also included in accumulated other comprehensive income at September 30, 2008 are (1) net after-tax losses of approximately $41.7 principally associated with future purchases of natural gas and propane substantially all of which is anticipated to occur during the next twelve months, (2) net after-tax gains of $9.8 associated with International Propane interest rate swaps, and (3) net after-tax gains of $1.0 associated with forecasted U.S. dollar-denominated purchases of LPG by our International Propane businesses to occur during the next three years. The amount of the losses that is expected to be reclassified into net income during the next twelve months associated with the U.S. dollar-denominated purchases is not material. The actual amount of gains or losses on unsettled derivative instruments that ultimately is reclassified into net income will depend upon the value of such derivative contracts when settled. The fair value of the long-term portion of unsettled derivative instruments is included in “Other assets” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.
The primary currency for which the Company has exchange rate risk is the euro. The U.S. dollar value of our foreign-denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investments in foreign subsidiaries. If a derivative is designated as a hedge of an investment in a foreign subsidiary and qualifies for hedge accounting, any realized gains or losses remain in other comprehensive income until such foreign operations have been liquidated. At September 30, 2008, a net after-tax loss of $4.1 is included in accumulated other comprehensive income associated with settled and unsettled net investment hedges.
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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 carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amounts and estimated fair values of our remaining financial instruments assets and (liabilities) at September 30 (including unsettled derivative instruments) are as follows:
| Asset (Liability) | ||||||||
| Carrying | Estimated | |||||||
| Amount | Fair Value | |||||||
| 2008: | ||||||||
| Natural gas futures and options contracts | $ | (52.4 | ) | $ | (52.4 | ) | ||
| Electric power contracts | (0.7 | ) | (0.7 | ) | ||||
| FTRs | 5.7 | 5.7 | ||||||
| Propane swap and option contracts | (53.7 | ) | (53.7 | ) | ||||
| Interest rate protection and swap agreements | 9.1 | 9.1 | ||||||
| Foreign currency forward contracts | 3.4 | 3.4 | ||||||
| Long-term debt | (2,069.1 | ) | (1,943.2 | ) | ||||
| 2007: | ||||||||
| Natural gas futures and options contracts | $ | (1.4 | ) | $ | (1.4 | ) | ||
| Electric supply swap | 0.8 | 0.8 | ||||||
| Propane swap and option contracts | 18.3 | 18.3 | ||||||
| Interest rate protection and swap agreements | 21.3 | 21.3 | ||||||
| Foreign currency forward contracts | (14.7 | ) | (14.7 | ) | ||||
| Long-term debt | (2,053.5 | ) | (2,037.6 | ) | ||||
We estimate the fair value of long-term debt by using current market prices and by discounting future cash flows using rates available for similar type debt. Fair values of derivative instruments reflect the estimated amounts that we would receive or (pay) to terminate the contracts at the reporting date based upon quoted market prices of comparable contracts at September 30, 2008 and 2007.
We have financial instruments, such as short-term investments and trade accounts receivable, which could expose us to concentrations of credit risk. We limit our credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds and securities guaranteed by the U.S. Government or its agencies. The credit risk from trade accounts receivable is limited because we have a large customer base, which extends across many different U.S. markets and several foreign countries. We attempt to minimize the credit risk associated with our derivative financial instruments through the application of credit policies.
Note 12 — Energy Services Accounts Receivable Securitization Facility
UGI Energy Services, Inc. (“ESI”) has a $200 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in April 2009, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility’s back-up purchasers.
Under the Receivables Facility, ESI transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special-purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of ESI and its affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables following the provisions of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” ESI continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC.
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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)
During Fiscal 2008, Fiscal 2007 and Fiscal 2006, ESI sold trade receivables totaling $1,496.2, $1,241.0 and $1,306.0, respectively, to ESFC. During Fiscal 2008, Fiscal 2007 and Fiscal 2006, ESFC sold an aggregate $251.5, $495.5 and $859.5, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At September 30, 2008, the outstanding balance of ESFC trade receivables was $28.7 which is net of $71 that was sold to the commercial paper conduit and removed from the balance sheet. At September 30, 2007, the outstanding balance of ESFC trade receivables was $65.7 which is net of $16 that was sold to the commercial paper conduit and removed from the balance sheet. Losses on sales of receivables to the commercial paper conduit that occurred during Fiscal 2008, Fiscal 2007 and Fiscal 2006, which are included in “Other income, net,” were $0.9, $1.5, and $3.3, respectively
Note 13 — Other Income, Net
Other income, net, comprises the following:
| 2008 | 2007 | 2006 | ||||||||||
| Interest and interest-related income | $ | 11.6 | $ | 11.5 | $ | 15.8 | ||||||
| Postretirement benefit plan curtailment gain | 2.2 | — | — | |||||||||
| Utility non-tariff service income | 6.2 | 5.1 | 1.0 | |||||||||
| Gain (loss) on sales of fixed assets | 0.2 | 0.5 | (0.1 | ) | ||||||||
| Gain on sale of Energy Ventures | — | — | 9.1 | |||||||||
| Gain on Partnership sale of storage facility | — | 46.1 | — | |||||||||
| Finance charges | 11.8 | 10.2 | 8.4 | |||||||||
| Other | 9.6 | 4.5 | 2.6 | |||||||||
| Total other income, net | $ | 41.6 | $ | 77.9 | $ | 36.8 | ||||||
Note 14 — Quarterly Data (unaudited)
The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments) which we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results fluctuate because of the seasonal nature of our businesses.
| December 31, | March 31, | June 30, | September 30, | |||||||||||||||||||||||||||||
| 2007 | 2006 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007(a) | |||||||||||||||||||||||||
| Revenues | $ | 1,764.7 | $ | 1,463.2 | $ | 2,361.5 | $ | 2,002.1 | $ | 1,332.8 | $ | 1,076.8 | $ | 1,189.2 | $ | 934.8 | ||||||||||||||||
| Operating income | $ | 196.2 | $ | 167.3 | $ | 317.4 | $ | 300.5 | $ | 58.2 | $ | 51.6 | $ | 13.4 | $ | 61.9 | ||||||||||||||||
| (Loss) income from equity investees | $ | (0.7 | ) | $ | — | $ | (0.7 | ) | $ | (1.3 | ) | $ | (0.7 | ) | $ | (0.9 | ) | $ | (0.8 | ) | $ | 1.6 | ||||||||||
| Net income (loss) | $ | 80.0 | $ | 61.9 | $ | 126.1 | $ | 120.2 | $ | 15.7 | $ | 11.5 | $ | (6.3 | ) | $ | 10.7 | |||||||||||||||
| Earnings (loss) per share: | ||||||||||||||||||||||||||||||||
| Basic | $ | 0.75 | $ | 0.58 | $ | 1.18 | $ | 1.13 | $ | 0.15 | $ | 0.11 | $ | (0.06 | ) | $ | 0.10 | |||||||||||||||
| Diluted | $ | 0.74 | $ | 0.58 | $ | 1.17 | $ | 1.12 | $ | 0.14 | $ | 0.11 | $ | (0.06 | ) | $ | 0.10 | |||||||||||||||
| (a) | Includes a gain from sale of the Partnership’s 3.5 million barrel underground storage terminal which increased operating income by $46.1 and net income by $12.5 or $0.12 per diluted share. |
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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)
Note 15 — Subsequent Events — Acquisition of PPL Gas Utilities Corporation and Penn Fuel Propane, LLC and Partnership Sale of Storage Facility
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 Corporation (the “CPG Acquisition”), for cash consideration of $267.6 plus estimated working capital of $35.4. 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 $32 plus estimated working capital of $1.6. 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 sells propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition with a combination of $120 cash contributed by UGI on September 25, 2008, proceeds from the issuance 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 of cash proceeds from the sale of the assets of CPP to reduce its revolving credit agreement borrowings. The acquisition of CPG and CPP will be reflected in our financial statements beginning October 1, 2008.
On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated, above-ground storage facility located on leased property in California for approximately $43.0 in cash. We expect to record an after-tax gain of approximately $11.0 associated with the sale in the first quarter of Fiscal 2009.
Note 16 — Segment Information
We have organized our business units into six reportable segments generally based upon products sold, geographic location (domestic or international) and regulatory environment. Our reportable segments are: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment comprising Flaga and our international propane equity investments (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Energy Services. We refer to both international segments collectively as “International Propane.”
AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers from locations in 46 states. Our International Propane segments’ revenues are derived principally from the distribution of LPG to retail customers in France and Austria. Gas Utility’s revenues are derived principally from the sale and distribution of natural gas to customers in eastern and northeastern Pennsylvania. Electric Utility derives its revenues principally from the distribution of electricity in two northeastern Pennsylvania counties. Energy Services revenues are derived from the sale of natural gas and, to a lesser extent, LPG, electricity and fuel oil to customers located primarily in the eastern United States.
The accounting policies of our reportable segments are the same as those described in Note 1. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. The Company’s definition of Partnership EBITDA may be different from that used by other companies. We evaluate the performance of our International Propane, Gas Utility, Electric Utility and Energy Services segments principally based upon their income 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.
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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)
| Reportable Segments | ||||||||||||||||||||||||||||||||||||
| Elim- | AmeriGas | Gas | Electric | Energy | International Propane | Corporate | ||||||||||||||||||||||||||||||
| Total | inations | Propane | Utility | Utility | Services | Antargaz | Other (b) | & Other (c) | ||||||||||||||||||||||||||||
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 | ) | ||||||||||||||||||||
| Minority interests | (89.8 | ) | (0.2 | ) | (88.4 | ) | — | — | — | (1.2 | ) | — | — | |||||||||||||||||||||||
| Income before income taxes | $ | 350.0 | $ | (0.2 | ) | $ | 73.7 | $ | 100.5 | $ | 22.4 | $ | 77.3 | $ | 72.3 | $ | 0.7 | $ | 3.3 | |||||||||||||||||
| Depreciation and amortization | $ | 184.4 | $ | — | $ | 80.4 | $ | 37.7 | $ | 3.6 | $ | 7.0 | $ | 50.5 | $ | 4.2 | $ | 1.0 | ||||||||||||||||||
| Partnership EBITDA (a) | $ | 313.0 | ||||||||||||||||||||||||||||||||||
| Total assets | $ | 5,685.0 | $ | (349.9 | ) | $ | 1,722.8 | $ | 1,582.5 | $ | 112.1 | $ | 312.3 | $ | 1,673.2 | $ | 196.8 | $ | 435.2 | |||||||||||||||||
| 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 | |||||||||||||||||
2007 | ||||||||||||||||||||||||||||||||||||
| Revenues | $ | 5,476.9 | $ | (197.3 | )(d) | $ | 2,277.4 | $ | 1,044.9 | $ | 121.9 | $ | 1,336.1 | $ | 759.2 | $ | 41.2 | $ | 93.5 | |||||||||||||||||
| Cost of sales | $ | 3,730.8 | $ | (193.8 | )(d) | $ | 1,437.2 | $ | 741.5 | $ | 67.8 | $ | 1,235.2 | $ | 366.7 | $ | 21.9 | $ | 54.3 | |||||||||||||||||
| Operating income | $ | 581.3 | $ | — | $ | 265.8 | $ | 136.6 | $ | 26.0 | $ | 57.4 | $ | 94.5 | $ | — | $ | 1.0 | ||||||||||||||||||
| Loss from equity investees | (3.8 | ) | — | — | — | — | — | (1.8 | ) | (2.0 | ) | — | ||||||||||||||||||||||||
| Interest expense | (139.6 | ) | — | (71.5 | ) | (39.9 | ) | (2.4 | ) | — | (23.1 | ) | (2.1 | ) | (0.6 | ) | ||||||||||||||||||||
| Minority interests | (106.9 | ) | (0.2 | ) | (105.3 | ) | — | — | — | (1.4 | ) | — | — | |||||||||||||||||||||||
| Income (loss) before income taxes | $ | 331.0 | $ | (0.2 | ) | $ | 89.0 | $ | 96.7 | $ | 23.6 | $ | 57.4 | $ | 68.2 | $ | (4.1 | ) | $ | 0.4 | ||||||||||||||||
| Depreciation and amortization | $ | 169.2 | $ | — | $ | 75.7 | $ | 37.4 | $ | 3.5 | $ | 6.9 | $ | 41.5 | $ | 3.4 | $ | 0.8 | ||||||||||||||||||
| Partnership EBITDA (a) | $ | 338.7 | ||||||||||||||||||||||||||||||||||
| Total assets | $ | 5,502.7 | $ | (358.1 | ) | $ | 1,708.4 | $ | 1,531.2 | $ | 102.9 | $ | 254.9 | $ | 1,648.9 | $ | 196.8 | $ | 417.7 | |||||||||||||||||
| Capital expenditures | $ | 223.1 | $ | — | $ | 73.8 | $ | 66.2 | $ | 7.2 | $ | 10.7 | $ | 61.8 | $ | 2.5 | $ | 0.9 | ||||||||||||||||||
| Investments in equity investees | $ | 63.9 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 63.9 | $ | — | ||||||||||||||||||
| Goodwill | $ | 1,498.8 | $ | (4.0 | ) | $ | 645.1 | $ | 162.3 | $ | — | $ | 11.8 | $ | 630.3 | $ | 46.3 | $ | 7.0 | |||||||||||||||||
2006 | ||||||||||||||||||||||||||||||||||||
| Revenues | $ | 5,221.0 | $ | (156.1 | )(d) | $ | 2,119.3 | $ | 724.0 | $ | 98.0 | $ | 1,414.3 | $ | 881.9 | $ | 63.6 | $ | 76.0 | |||||||||||||||||
| Cost of sales | $ | 3,657.9 | $ | (152.3 | )(d) | $ | 1,343.8 | $ | 522.9 | $ | 51.0 | $ | 1,328.2 | $ | 478.4 | $ | 38.8 | $ | 47.1 | |||||||||||||||||
| Operating income | $ | 467.7 | $ | — | $ | 184.1 | $ | 84.2 | $ | 20.7 | $ | 53.1 | $ | 115.4 | $ | 3.9 | $ | 6.3 | ||||||||||||||||||
| Loss from equity investees | (2.2 | ) | — | — | — | — | — | (1.6 | ) | (0.6 | ) | — | ||||||||||||||||||||||||
| Loss on extinguishments of debt | (18.5 | ) | — | (17.1 | ) | — | — | — | (1.4 | ) | — | — | ||||||||||||||||||||||||
| Interest expense | (123.6 | ) | — | (74.1 | ) | (21.8 | ) | (2.5 | ) | — | (23.1 | ) | (1.7 | ) | (0.4 | ) | ||||||||||||||||||||
| Minority interests | (48.7 | ) | (0.4 | ) | (51.3 | ) | — | — | — | 3.0 | — | — | ||||||||||||||||||||||||
| Income before income taxes | $ | 274.7 | $ | (0.4 | ) | $ | 41.6 | $ | 62.4 | $ | 18.2 | $ | 53.1 | $ | 92.3 | $ | 1.6 | $ | 5.9 | |||||||||||||||||
| Depreciation and amortization | $ | 148.7 | $ | — | $ | 72.5 | $ | 23.3 | $ | 3.3 | $ | 6.7 | $ | 38.2 | $ | 3.9 | $ | 0.8 | ||||||||||||||||||
| Partnership EBITDA (a) | $ | 237.9 | ||||||||||||||||||||||||||||||||||
| Total assets | $ | 5,080.5 | $ | (340.7 | ) | $ | 1,627.2 | $ | 1,504.3 | $ | 105.3 | $ | 238.5 | $ | 1,406.8 | $ | 183.4 | $ | 355.7 | |||||||||||||||||
| Capital expenditures | $ | 191.7 | $ | — | $ | 70.7 | $ | 49.2 | $ | 9.0 | $ | 7.0 | $ | 47.9 | $ | 7.6 | $ | 0.3 | ||||||||||||||||||
| Investments in equity investees | $ | 58.2 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 58.2 | $ | — | ||||||||||||||||||
| Goodwill | $ | 1,418.2 | $ | (4.0 | ) | $ | 619.1 | $ | 182.9 | $ | — | $ | 11.8 | $ | 560.7 | $ | 40.9 | $ | 6.8 | |||||||||||||||||
| (a) | The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income: |
| Year ended September 30, | 2008 | 2007 | 2006 | |||||||||
| Partnership EBITDA | $ | 313.0 | $ | 338.7 | (i) | $ | 237.9 | |||||
| Depreciation and amortization | (80.4 | ) | (75.7 | ) | (72.5 | ) | ||||||
| Minority interests (ii) | 2.4 | 2.8 | 1.6 | |||||||||
| Loss on extinguishment of debt | — | — | 17.1 | |||||||||
| Operating income | $ | 235.0 | $ | 265.8 | $ | 184.1 | ||||||
| (i) | Includes $46.1 gain on the sale of Arizona storage facility. See Note 2 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 its central and eastern European joint-venture ZLH, and our joint-venture business in China. | |
| (c) | Corporate & Other results principally comprise UGI Enterprises’ HVAC/R, net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses, interest income, and, beginning January 1, 2007, UGI Utilities’ HVAC operations. Corporate and Other’s assets principally comprise cash, short-term investments and an intercompany loan. The intercompany interest associated with the intercompany loan is removed in the segment presentation. | |
| (d) | Principally represents the elimination of intersegment transactions amoung Energy Services, Gas Utility and AmeriGas Propane. |
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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, | ||||||||
| 2008 | 2007 | |||||||
ASSETS | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 1.4 | $ | 0.7 | ||||
| Accounts and notes receivable | 5.3 | 9.1 | ||||||
| Deferred income taxes | 0.3 | 0.3 | ||||||
| Prepaid expenses and other current assets | 0.4 | 1.6 | ||||||
| Total current assets | 7.4 | 11.7 | ||||||
| Investments in subsidiaries | 1,429.4 | 1,337.3 | ||||||
| Derivative financial instruments | 1.8 | — | ||||||
| Deferred income taxes | 15.0 | 14.8 | ||||||
| Total assets | $ | 1,453.6 | $ | 1,363.8 | ||||
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY | ||||||||
| Current liabilities: | ||||||||
| Accounts and notes payable | $ | 10.6 | $ | 11.0 | ||||
| Derivative financial instruments | — | 6.5 | ||||||
| Accrued liabilities | 5.9 | 4.1 | ||||||
| Total current liabilities | 16.5 | 21.6 | ||||||
| Noncurrent liabilities | 19.4 | 20.3 | ||||||
| Commitments and contingencies | ||||||||
| Common stockholders’ equity: | ||||||||
| Common Stock, without par value (authorized — 300,000,000 shares; issued — 115,247,694 and 115,152,994 shares, respectively) | 858.3 | 831.6 | ||||||
| Retained earnings | 630.9 | 497.5 | ||||||
| Accumulated other comprehensive (loss) income | (15.2 | ) | 57.7 | |||||
| 1,474.0 | 1,386.8 | |||||||
| Less treasury stock, at cost | (56.3 | ) | (64.9 | ) | ||||
| Total common stockholders’ equity | 1,417.7 | 1,321.9 | ||||||
| Total liabilities and common stockholders’ equity | $ | 1,453.6 | $ | 1,363.8 | ||||
Commitments and Contingencies:
In addition to the guarantees of Flaga’s debt and 50% of ZLH’s working capital facility as described in Note 3 to Consolidated Financial Statements, at September 30, 2008, UGI Corporation had agreed to indemnify the issuers of $35.5 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to $485.0 of obligations to suppliers and customers of UGI Energy Services, Inc. (UESI) and subsidiaries of which $362.5 of such obligations were outstanding as of September 30, 2008.
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UGI CORPORATION AND SUBSIDIARIES
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, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
| Revenues | $ | — | $ | — | $ | — | ||||||
| Costs and expenses: | ||||||||||||
| Operating and administrative expenses | 29.3 | 27.2 | 25.4 | |||||||||
| Other income, net (1) | (29.6 | ) | (27.1 | ) | (25.7 | ) | ||||||
| (0.3 | ) | 0.1 | (0.3 | ) | ||||||||
| Operating income (loss) | 0.3 | (0.1 | ) | 0.3 | ||||||||
| Intercompany interest income (expense) | 0.1 | 0.2 | (5.6 | ) | ||||||||
| Income (loss) before income taxes | 0.4 | 0.1 | (5.3 | ) | ||||||||
| Income tax expense (benefit) | 1.3 | 0.8 | (1.1 | ) | ||||||||
| Loss before equity in income of unconsolidated subsidiaries | (0.9 | ) | (0.7 | ) | (4.2 | ) | ||||||
| Equity in income of unconsolidated subsidiaries | 216.4 | 205.0 | 180.4 | |||||||||
| Net income | $ | 215.5 | $ | 204.3 | $ | 176.2 | ||||||
| Earnings per common share: | ||||||||||||
| Basic | $ | 2.01 | $ | 1.92 | $ | 1.67 | ||||||
| Diluted | $ | 1.99 | $ | 1.89 | $ | 1.65 | ||||||
| Average common shares outstanding (millions): | ||||||||||||
| Basic | 107.396 | 106.451 | 105.455 | |||||||||
| Diluted | 108.521 | 107.941 | 106.727 | |||||||||
| (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 expenses incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to its subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed and considers each subsidiary’s relative percentage of 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. |
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UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)
STATEMENTS OF CASH FLOWS
(Millions of dollars)
(Millions of dollars)
| Year Ended | ||||||||||||
| September 30, | ||||||||||||
| 2008 | 2007 | 2006 | ||||||||||
NET CASH PROVIDED BY OPERATING ACTIVITIES (a) | $ | 155.1 | $ | 105.1 | $ | 357.6 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
| Investments in unconsolidated subsidiaries | (94.4 | ) | (44.0 | ) | (295.4 | ) | ||||||
| Net cash used by investing activities | (94.4 | ) | (44.0 | ) | (295.4 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
| Payment of dividends on Common Stock | (80.9 | ) | (76.8 | ) | (72.5 | ) | ||||||
| Issuance of Common Stock | 20.9 | 16.4 | 10.0 | |||||||||
| Net cash used by financing activities | (60.0 | ) | (60.4 | ) | (62.5 | ) | ||||||
| Cash and cash equivalents increase (decrease) | $ | 0.7 | $ | 0.7 | $ | (0.3 | ) | |||||
| Cash and cash equivalents: | ||||||||||||
| End of period | $ | 1.4 | $ | 0.7 | $ | — | ||||||
| Beginning of period | 0.7 | — | 0.3 | |||||||||
| Increase (decrease) | $ | 0.7 | $ | 0.7 | $ | (0.3 | ) | |||||
| (a) | Includes dividends received from unconsolidated subsidiaries of $196.6, $100.0, and $351.6, respectively, for the years ended September 30, 2008, 2007 and 2006. |
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UGI CORPORATION AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Millions of dollars)
(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) | |||||||||||||||
Year Ended September 30, 2007 | ||||||||||||||||
| Reserves deducted from assets in the consolidated balance sheet: | ||||||||||||||||
| Allowance for doubtful accounts | $ | 38.0 | $ | 26.7 | $ | (28.3 | )(1) | $ | 37.7 | |||||||
| 1.3 | (4) | |||||||||||||||
| Other reserves: | ||||||||||||||||
| Property and casualty liability | $ | 62.9 | $ | 16.1 | $ | (15.3 | )(3) | $ | 65.0 | (5) | ||||||
| 1.3 | (2) | |||||||||||||||
| Environmental, litigation and other | $ | 26.5 | $ | 2.0 | $ | (0.9 | )(3) | $ | 37.1 | |||||||
| 1.2 | (2) | |||||||||||||||
| 8.3 | (4) | |||||||||||||||
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UGI CORPORATION AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS (continued)
(Millions of dollars)
(Millions of dollars)
| Charged | ||||||||||||||||
| Balance at | (credited) | Balance at | ||||||||||||||
| beginning | to costs and | end of | ||||||||||||||
| of year | expenses | Other | year | |||||||||||||
Year Ended September 30, 2006 | ||||||||||||||||
| Reserves deducted from assets in the consolidated balance sheet: | ||||||||||||||||
| Allowance for doubtful accounts | $ | 29.2 | $ | 25.0 | $ | (22.4 | )(1) | $ | 38.0 | |||||||
| 6.2 | (4) | |||||||||||||||
| Other reserves: | ||||||||||||||||
| Property and casualty liability | $ | 66.0 | $ | 13.8 | $ | (17.9 | )(3) | $ | 62.9 | (5) | ||||||
| 0.1 | (2) | |||||||||||||||
| 0.9 | (4) | |||||||||||||||
| Environmental, litigation and other | $ | 19.7 | $ | 7.5 | $ | (1.2 | )(3) | $ | 26.5 | |||||||
| 0.1 | (2) | |||||||||||||||
| 0.4 | (4) | |||||||||||||||
| (1) | Uncollectible accounts written off, net of recoveries | |
| (2) | Other adjustments | |
| (3) | Payments, net | |
| (4) | Acquisition | |
| (5) | At September 30, 2008, 2007 and 2006, the Company had insurance indemnification receivables associated with its property and casualty liabilities totaling $18.5, $1.0 and $0.9, respectively. |
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Table of Contents
EXHIBIT INDEX
| Exhibit No. | Description | |||
| 10.5 | UGI Corporation 2004 Omnibus Equity Compensation Plan UGI Employees Stock Unit Grant Letter dated as of January 1, 2008 | |||
| 10.30 | Description of Oral Compensation Arrangements for Messrs. Greenberg, Varagne and Walsh | |||
| 10.67 | (a) | 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 | ||
| 10.79 | Amendment and Extension dated June 10, 2008 to and of the Working Capital Facility Agreement, dated July 26, 2006, between Flaga GmbH, as Borrower, and RZB, as Lender | |||
| 10.91 | (a) | Amendment and Extension dated July 10, 2008 to and of the Multi-Currency Facility Offer dated May 21, 2007 between Zentraleuropa LPG Holding GmbH and Raiffeisen Zentralbank Österreich Akteingesellschaft | ||
| 21 | Subsidiaries of the Registrant | |||
| 23 | Consent of PricewaterhouseCoopers LLP | |||
| 31.1 | Certification by the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act | |||
| 31.2 | Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act | |||
| 32 | Certification by the Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act | |||
74