UNITED STATES
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

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2008

UGI CORPORATION

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)

(610) 337-1000
(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. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes o No þ

The aggregate market value of UGI Corporation Common Stock held by non-affiliates of the registrant on March 31, 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.

 

 

TABLE OF CONTENTS

		Page
PART I:			3
Items 1. and 2. Business and Properties			3
Item 1A. Risk Factors			19
Item 1B. Unresolved Staff Comments			23
Item 3. Legal Proceedings			23
Item 4. Submission of Matters to a Vote of Security Holders			24
PART II:			24
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			24
Item 6. Selected Financial Data			26
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			27
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			59
Item 8. Financial Statements and Supplementary Data			59
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			59
Item 9A. Controls and Procedures			59
Item 9B. Other Information			59
PART III:			60
Item 10. Directors, Executive Officers and Corporate Governance			60
Item 11. Executive Compensation			60
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			60
Item 13. Certain Relationships and Related Transactions and Director Independence			60
Item 14. Principal Accountant Fees and Services			60
PART IV:			63
Item 15. Exhibits and Financial Statement Schedules			63
Signatures			73
Index to Financial Statements and Financial Statement Schedules			F-2
Exhibit 10.5
Exhibit 10.30
Exhibit 10.67(a)
Exhibit 10.79
Exhibit 10.91(a)
Exhibit 21
Exhibit 23
Exhibit 31.1
Exhibit 31.2
Exhibit 32

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.

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.

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.

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.

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

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.

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.

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.

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.”

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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 in The Wall Street Journal 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

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.

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	%

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.

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.

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

																		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	%			—				—

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.

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	%			—				—

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.

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	%			—				—

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.

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	)%

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	%

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.

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

																		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.

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	%			—				—

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.

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	%			—				—

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.

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	%			—				—

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.

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	%

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	%

Notwithstanding the effects of a 4% increase in natural gas volumes sold and higher electric generation kilowatt-hour sales, Energy Services revenues decreased to $1,336.1 million in Fiscal 2007 from $1,414.3 million in Fiscal 2006 principally reflecting the revenue effects of lower natural gas prices.

Total margin increased to $100.9 million in Fiscal 2007 from $86.1 million in Fiscal 2006. The increase in total margin is primarily attributable to higher natural gas unit margins, the previously mentioned increase in natural gas volumes sold, and improved results from storage management and peaking supply services.

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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