UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

Commission file number 1-11071

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)

		Name of each Exchange
Title of Each Class		on Which Registered
Common Stock, without par value		New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes þ No o

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

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

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

The aggregate market value of UGI Corporation Common Stock held by non-affiliates of the registrant on March 31, 2009 was $2,516,319,164.

At November 16, 2009 there were 108,782,302 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 26, 2010 are incorporated by reference into Part III of this Form 10-K.

 

 

TABLE OF CONTENTS

		Page
Forward-Looking Information			2
PART I:
Items 1. and 2. Business and Properties			2
Item 1A. Risk Factors			20
Item 1B. Unresolved Staff Comments			25
Item 3. Legal Proceedings			25
Item 4. Submission of Matters to a Vote of Security Holders			25
PART II:
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			25
Item 6. Selected Financial Data			27
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			53
Item 8. Financial Statements and Supplementary Data			53
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			53
Item 9A. Controls and Procedures			54
Item 9B. Other Information			54
PART III:
Item 10. Directors, Executive Officers and Corporate Governance			55
Item 11. Executive Compensation			55
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			55
Item 13. Certain Relationships and Related Transactions and Director Independence			55
Item 14. Principal Accountant Fees and Services			55
PART IV:
Item 15. Exhibits and Financial Statement Schedules			58
Signatures			70
Index to Financial Statements and Financial Statement Schedules			F-2
Exhibit 10.2
Exhibit 10.5
Exhibit 10.11
Exhibit 10.20
Exhibit 10.23
Exhibit 10.31
Exhibit 21
Exhibit 23
Exhibit 31.1
Exhibit 31.2
Exhibit 32

FORWARD-LOOKING INFORMATION

Information contained in this Annual Report on Form 10-K may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other LPG, oil, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) large customer, counter-party or supplier defaults; (12) liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and 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 our acquisitions and investments to grow our businesses.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

PART I:

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

CORPORATE OVERVIEW

UGI Corporation is a holding company that, through subsidiaries and a joint venture, 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 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 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 corporation (“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 one of the largest retail LPG distributors in the Czech Republic and 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 Utilities”) and UGI Utilities’ subsidiaries, UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). Gas Utility serves approximately 563,000 customers in eastern, northeastern and central Pennsylvania. UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” The Electric Utility segment (“Electric Utility”) consists of the regulated electric distribution business of UGI Utilities, serving approximately 62,000 customers in northeastern Pennsylvania. Gas Utility is regulated by the Pennsylvania Public Utility Commission (“PUC”) and the Maryland Public Service Commission. Electric Utility is regulated by the 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 is now known as CPG. Beginning in the 2009 fiscal year, CPG was included in the Company’s Gas Utility segment and Penn Fuel Propane was included in the Company’s AmeriGas Propane segment. See Note 4 to 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 name GASMARK^®, (ii) operating 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 utilizing our core competencies from our existing businesses and our national scope, international experience, extensive asset base and access to customers to accelerate both internal growth and growth through acquisitions in our existing businesses, as well as in related and complementary businesses. During fiscal year 2009, we completed a number of transactions in pursuit of this strategy and commenced construction on a number of larger internally generated capital projects.

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 2009” and “Fiscal 2008” refer to the fiscal years ended September 30, 2009 and September 30, 2008, 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

Products, Services and Marketing

Our domestic propane distribution business is conducted through AmeriGas Partners. AmeriGas Propane is responsible for managing the Partnership. The Partnership serves approximately 1.3 million customers in all 50 states from approximately 1,200 propane distribution locations. In addition to distributing propane, the Partnership also sells, installs and services propane appliances, including heating systems. In certain areas, the Partnership also installs and services propane fuel systems for motor vehicles. Typically, district locations are found in suburban and rural areas where natural gas is not readily available. Districts generally consist of an office, appliance showroom, warehouse, and service facilities, with one or more 18,000 to 30,000 gallon storage tanks on the premises. As part of its overall transportation and distribution infrastructure, the Partnership operates as an interstate carrier in 48 states throughout the continental United States. It is also licensed as a carrier in the Canadian Provinces of Ontario and Quebec.

The Partnership sells propane primarily to residential, commercial/industrial, motor fuel, agricultural and wholesale customers. The Partnership distributed over one billion gallons of propane in Fiscal 2009. Approximately 89% of the Partnership’s Fiscal 2009 sales (based on gallons sold) were to retail accounts and approximately 11% were to wholesale customers. Sales to residential customers in Fiscal 2009 represented approximately 41% of retail gallons sold; commercial/industrial customers 36%; motor fuel customers 13%; and agricultural customers 5%. Transport gallons, which are large-scale deliveries to retail customers other than residential, accounted for 5% of Fiscal 2009 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, 2009, ACE cylinders were available at approximately 27,600 retail locations throughout the United States, an increase of more than 10% compared to Fiscal 2008. Sales of our ACE grill cylinders to retailers are included in commercial/industrial sales. The ACE program enables consumers to purchase or exchange their empty propane grill cylinders at various retail locations such as home centers, gas stations, mass merchandisers and grocery and convenience stores. We also supply retailers with large propane tanks to enable retailers to replenish customers’ propane grill cylinders directly at the retailer’s location.

Residential customers use propane primarily for home heating, water heating and cooking purposes. Commercial users, which include motels, hotels, restaurants and retail stores, generally use propane for the same purposes as residential customers. Industrial customers use propane to fire furnaces, as a cutting gas and in other process applications. Other industrial customers are large-scale heating accounts and local gas utility customers who use propane as a supplemental fuel to meet peak load deliverability requirements. As a motor fuel, propane is burned in internal combustion engines that power over-the-road vehicles, forklifts and stationary engines. Agricultural uses include tobacco curing, chicken brooding and crop drying. In its wholesale operations, the Partnership principally sells propane to large industrial end-users and other propane distributors.

Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from the bobtail truck, which generally holds 2,400 to 3,000 gallons of propane, into a stationary storage tank on the customer’s premises. The Partnership owns most of these storage tanks and leases them to its customers. The capacity of these tanks ranges from approximately 120 gallons to approximately 1,200 gallons. The Partnership also delivers propane to retail customers in portable cylinders (including ACE propane grill cylinders) which contain 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 or replenished in place.

Propane Supply and Storage

The Partnership has over 250 domestic and international sources of supply, including the spot market. Supplies of propane from the Partnership’s sources historically have been readily available. During the year ended September 30, 2009, 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 2010. 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 46% of the Partnership’s Fiscal 2009 propane supply. No other single supplier provided more than 10% of the Partnership’s total propane supply in Fiscal 2009. In certain 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 various storage facilities and terminals located in strategic areas across the United States.

Because the Partnership’s profitability is sensitive to changes in wholesale propane costs, the Partnership generally seeks to pass on increases in the cost of propane to customers. There is no assurance, however, that the Partnership will always be able to pass on product cost increases fully, particularly when product costs rise rapidly. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude oil and natural gas, or other unforeseen events. In Fiscal 2009, the Partnership experienced significant product cost reductions over Fiscal 2008 due to sharp declines in the price of crude oil. 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

General Industry Information

Propane is separated from crude oil during the refining process and also extracted from natural gas or oil wellhead gas at processing plants. Propane is normally transported and stored in a liquid state under moderate pressure or refrigeration for economy and ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable gas. Propane is colorless and odorless; an odorant is added to allow for its detection. Propane is clean burning, producing negligible amounts of pollutants when properly consumed.

Competition

Propane competes with other sources of energy, some of which are less costly for equivalent energy value. Propane distributors compete for customers with suppliers of electricity, fuel oil and natural gas, principally on the basis of price, service, availability and portability. Electricity is a major competitor of propane, but propane generally enjoys a competitive price advantage over electricity for space heating, water heating, and cooking. In some areas electricity may have a competitive price advantage or be relatively equivalent in price to propane due to government regulated rate caps on electricity. Additionally, high efficiency electric heat pumps have led to a decrease in the cost of electricity for heating. Fuel oil is also a major competitor of propane and is generally less expensive than propane. Furnaces and appliances that burn propane will not operate on fuel oil, and vice versa, and, therefore, a conversion from one fuel to the other requires the installation of new equipment. Propane serves as an alternative to natural gas in rural and suburban areas where natural gas is unavailable or portability of product is required. Natural gas is generally a less expensive source of energy than propane, although in areas where natural gas is available, propane is used for certain industrial and commercial applications and as a standby fuel during interruptions in natural gas service. The gradual expansion of the nation’s natural gas distribution systems has resulted in the availability of natural gas in some areas that previously depended upon propane. However, natural gas pipelines are not present in many regions of the country where propane is sold for heating and cooking purposes.

For motor fuel customers, propane competes with gasoline and diesel fuel as well as electric batteries and fuel cells. Wholesale propane distribution is a highly competitive, low margin business. Propane sales to other retail distributors and large-volume, direct-shipment industrial end-users are price sensitive and frequently involve a competitive bidding process.

The retail propane industry is mature, with 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. The Partnership also offers customers various payment and service options, including fixed price and guaranteed price programs.

In Fiscal 2009, the Partnership’s retail propane sales totaled approximately 928 million gallons. Based on the most recent annual survey by the American Petroleum Institute, 2007 domestic retail propane sales (annual sales for other than chemical uses) in the United States totaled approximately 9.6 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.

Properties

As of September 30, 2009, the Partnership owned approximately 84% 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 4 to 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, 2009, the Partnership operated a transportation fleet with the following assets:

Approximate Quantity & Equipment Type						% Owned				% Leased
	1,610			Trailers			90	%			10	%
	300			Tractors			15	%			85	%
	180			Railroad tank cars			0	%			100	%
	2,480			Bobtail trucks			13	%			87	%
	270			Rack trucks			1	%			99	%
	2,300			Service and delivery trucks			15	%			85	%

Other assets owned at September 30, 2009 included approximately 858,000 stationary storage tanks with typical capacities ranging from 121 to 2,000 gallons and approximately 3.1 million portable propane cylinders with typical capacities of 1 to 120 gallons. The Partnership also owned approximately 6,000 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 65% to 70% of the Partnership’s retail sales volume occurs, and substantially all of the Partnership’s operating income is earned, during the peak heating season from October through March. As a result of this seasonality, sales are higher in the Partnership’s first and second fiscal quarters (October 1 through March 31). Cash receipts are generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the winter heating season.

Sales volume for the Partnership traditionally fluctuates from year-to-year in response to variations in weather, prices, competition, customer mix and other factors, such as conservation efforts and general economic conditions. For historical information on national weather statistics, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Government Regulation

The Partnership is subject to various federal, state and local environmental, safety and transportation laws and regulations governing the storage, distribution and transportation of propane and the operation of bulk storage LPG terminals. These laws include, among others, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health Act, the Homeland Security Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA imposes joint and several liability on certain classes of persons considered to have contributed to the release or threatened release of a “hazardous substance” into the environment without regard to fault or the legality of the original conduct. Propane is not a hazardous substance within the meaning of federal and most state environmental laws.

All states in which the Partnership operates have adopted fire safety codes that regulate the storage and distribution of propane. In some states these laws are administered by state agencies, and in others they are administered on a municipal level. The Partnership conducts training programs to help ensure that its operations are in compliance with applicable governmental regulations. With respect to general operations, National Fire Protection Association (“NFPA”) Pamphlets No. 54 and No. 58, which establish a set of rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted by all states in which the Partnership operates. 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 employees who provide information to their employers or to the federal government as to pipeline safety from adverse employment actions.

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, 2009, the General Partner had approximately 5,950 employees, including approximately 465 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. In January 2009, Flaga purchased the 50% equity interest in Zentraleuropa LPG Holdings GmbH (“ZLH”) it did not already own from its joint-venture partner, Progas GmbH & Co. KG (“Progas”), pursuant to a purchase agreement dated December 18, 2008.

Antargaz operates in France and Flaga operates in Austria, Switzerland, Czech Republic, Slovakia, Poland, Hungary and Romania. During Fiscal 2009, Antargaz sold approximately 290 million gallons of LPG and Flaga sold approximately 68.5 million gallons of LPG. Our joint venture in China sold approximately 11.3 million gallons of LPG during Fiscal 2009.

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 19,000 retail outlets, such as supermarkets, individually owned stores and gas stations. At September 30, 2009, Antargaz had approximately 228,500 bulk customers and approximately 5.5 million cylinders in circulation. Approximately 64% of Antargaz’ Fiscal 2009 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 cylinders accounted for approximately 61% of all LPG cylinders sold in Fiscal 2009, with propane cylinders accounting for the remainder. Propane cylinders are also used to supply fuel for forklift trucks. The market demand for cylinders has been declining, due primarily to customers gradually changing to other household energy sources for heating and cooking, such as natural gas. Antargaz is seeking to increase demand for butane and propane cylinders through marketing and product innovations.

Medium bulk customers use propane only, and consist mainly of large residential developments such as housing projects, hospitals, municipalities and medium-sized industrial 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 September 2012 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 2009, 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, STASCO (Shell Trading) and VITOL. In addition, purchases are made on the spot market from international oil and gas companies such as Tengiz Chevron Oil 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 26 secondary storage facilities. It also manages an extensive logistics and transportation network. Access to seaborne facilities allows Antargaz to diversify its LPG supplies through imports. LPG stored in primary storage facilities is transported to smaller storage facilities by rail, sea and road. At secondary storage facilities, LPG is filled into cylinders or trucks equipped with tanks and then delivered to customers.

Competition

The LPG market in France is mature, with 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 cost increases fully when product costs rise rapidly. Increased LPG prices may result in slower than expected growth due to customer conservation and customers seeking less expensive alternative energy sources. France derives a significant portion of its electricity from nuclear power plants. Due to the nuclear power plants as well as the regulation of electricity prices by the French government, electricity prices in France are generally less expensive than LPG. As a result, electricity has increasingly become a more significant competitor to LPG in France than in other countries where we operate. In addition, government policies and incentives that favor alternative energy sources can result in customers migrating to energy sources other than LPG.

Antargaz competes in all of its product markets on a national level principally with three LPG distribution companies, Totalgaz (owned by Total France), Butagaz (owned by Societe des Petroles Shell, “Shell”) and Compagnie des Gaz de Petrole Primagaz (an independent supplier owned by SHV Holding NV), as well as with regional competitors, Vitogaz and Repsol. 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. Antargaz’ competitors are generally affiliates of its LPG suppliers. As a result, its competitors may obtain product at more competitive prices.

On October 21, 2009, Antargaz responded to a Statement of Objections issued by the French competition authority, the General Division of Competition, Consumption and Fraud Punishment, in July of 2009. For more information on the inquiry, see Note 15 to Consolidated Financial Statements.

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 all of Antargaz’ operating income is earned, during the six months from October through March.

Sales volume for Antargaz traditionally fluctuates from year-to-year in response to variations in weather, prices and other factors, such as conservation efforts and general economic conditions. For historical information on weather statistics for Antargaz, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Government Regulation

Antargaz’ business is subject to various laws and regulations at the national and European levels with respect to matters such as protection of the environment, the storage and handling of hazardous materials and flammable substances, the discharge of contaminants into the environment and the safety of persons and property.

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

The closing of a fifth storage facility, Geovexin, has started. Antargaz has 26 secondary storage facilities, 12 of which are wholly owned. The others are partially owned, through joint ventures.

Employees

At September 30, 2009, Antargaz had approximately 1,050 employees.

FLAGA

Products, Services, Marketing and Storage

Flaga distributes LPG for residential, commercial, industrial, and auto gas applications in the following central and eastern European countries: Austria, Switzerland, Czech Republic, Slovakia, Poland, Hungary and Romania. During Fiscal 2009, Flaga sold approximately 68.5 million gallons of LPG. Flaga is the largest distributor of LPG in Austria and one of the largest distributors of LPG in both the Czech Republic and Slovakia.

Flaga’s customers primarily use LPG for heating, cooking, construction work, industrial processing, forklifts and autogas. 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 19 sales offices throughout the countries it serves. Much of Flaga’s cylinder business in Austria is conducted through approximately 600 local resellers with whom Flaga has a long business relationship. In its other countries, Flaga sells cylinders to distributors who resell the cylinders to end users under the distributor’s pricing and terms. Flaga utilizes approximately 66 storage facilities with 22 of those storage facilities in the Czech Republic and 20 in Austria.

Seasonality and Competition

Because many of Flaga’s customers use LPG for heating, sales volumes in Flaga’s sales territories are affected principally by the severity of the weather and traditionally fluctuate from year-to-year in response to variations in weather, prices and other factors, such as conservation efforts and general economic conditions. Because Flaga’s profitability is sensitive to changes in wholesale LPG costs, Flaga generally seeks to pass on increases in the cost of LPG to customers. There is no assurance, however, that Flaga will always be able to pass on product cost increases fully. In parts of Flaga’s sales territories, it is particularly difficult to pass on rapid increases in the price of LPG due to the low per capita income of customers in several of its territories and the intensity of competition. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude oil and natural gas, or other unforeseen events. High LPG prices may result in slower than expected growth due to customer conservation and customers seeking less expensive alternative energy sources. Flaga competes with other LPG 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. In many of Flaga’s sales territories, government policies and incentives that favor alternative energy sources may result in customers migrating to energy sources other than LPG.

Government Regulation

Flaga’s business is subject to various laws and regulations at both the national and European levels with respect to matters such as protection of the environment and the storage and handling of hazardous materials and flammable substances.

Employees

At September 30, 2009, Flaga had approximately 615 employees.

GAS UTILITY

Service Area; Revenue Analysis

Gas Utility is authorized to distribute natural gas to approximately 563,000 customers in portions of 45 eastern, northeastern and central Pennsylvania counties through its distribution system of approximately 11,900 miles of gas mains. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre, Lock Haven, Pittston, Pottsville and Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas Utility’s service area are major production centers for basic industries such as specialty metals, aluminum, glass and paper product manufacturing.

System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal 2009 was approximately 150 billion cubic feet (“bcf”). System sales of gas accounted for approximately 44% of system throughput, while gas transported for residential, commercial and industrial customers (who bought their gas from others) accounted for approximately 56% 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, Dominion Transmission, ANR Pipeline and Tennessee Gas Pipeline.

Gas Supply Contracts

During Fiscal 2009, Gas Utility purchased approximately 94 bcf of natural gas for sale to retail core-market customers (principally comprised of firm- residential, commercial and industrial customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers) and off-system sales customers. Approximately 77% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 23% of gas purchased by Gas Utility was supplied by approximately 20 producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 1 year. Gas Utility also has long-term contracts with suppliers for natural gas peaking supply during the months of November through March.

Seasonality

Because many of its customers use gas for heating purposes, Gas Utility sales are seasonal. Approximately 65% to 70% of Gas Utility’s sales volume is supplied, and approximately 85% to 90% of Gas Utility’s operating income is earned, during the peak heating season from October through March.

Competition

Natural gas is a fuel that competes with electricity and oil, and to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of fuel utilization equipment. In parts of Gas Utility’s service area, electricity may have a competitive price advantage over natural gas due to government regulated rate caps on electricity. Rate caps for electric utilities serving a significant portion of Gas Utility’s service territory are currently scheduled to expire at the end of 2009 and 2010 which will likely result in electricity losing all or some of its competitive price advantage. Additionally, high efficiency electric heat pumps have led to a decrease in the cost of heating with electricity. Government subsidies currently favor ground source heat pumps over fossil fueled systems. Fuel oil dealers compete for customers in all categories, including industrial customers. Gas Utility responds to this competition with marketing efforts designed to retain and grow its customer base.

In substantially all of its service territories, Gas Utility is the only regulated gas distribution utility having the right, granted by the PUC or by law, to provide gas distribution services. Since the 1980s, larger commercial and industrial customers have been able to purchase gas supplies from entities other than natural gas distribution utility companies. As a result of Pennsylvania’s Natural Gas Choice and Competition Act, effective July 1, 1999 all of Gas Utility’s customers, including retail core-market customers, have been afforded this opportunity.

A number of Gas Utility’s commercial and industrial customers have the ability to switch to an alternate fuel at any time and, therefore, are served on an interruptible basis under rates which are competitively priced with respect to the alternate fuel. Margin from these customers, therefore, is affected by the difference or “spread” between the customers’ delivered cost of gas and the customers’ delivered cost of the alternate fuel, as well as the frequency and duration of interruptions. See “Gas Utility and Electric Utility Regulation and Rates — Gas Utility Rates.” Approximately 24% of Gas Utility’s commercial and industrial customers’ annual throughput volume, including certain customers served under interruptible rates, have locations which afford them the opportunity of seeking transportation service directly from interstate pipelines, thereby bypassing Gas Utility. The majority of customers in this group are served under transportation contracts having 3 to 20 year terms. Included in these two customer groups are 25 customers, most of which are among the 10 largest customers for each of UGI Gas, PNG and CPG in terms of annual volumes. All of these customers have contracts, 19 of which extend beyond the 2010 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 2010. 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 2009, 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 10,700 residential heating customers during Fiscal 2009. These customers consisted primarily of (i) customers converting from other energy sources, mainly oil and electricity, (ii) existing non-heating gas customers who have added gas heating systems to replace other energy sources and (iii) new home construction customers. As a result of the decline in the real estate market, customers from new home construction decreased approximately 24% compared to Fiscal 2008. If the slowdown in new home construction continues in fiscal year 2010 in Gas Utility’s service area, customer growth will be adversely affected.

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 2009, approximately 54% of sales volume came from residential customers, 34% from commercial customers, and 12% from industrial and other customers. Sales of electricity for residential heating purposes accounted for approximately 19% of total sales of electricity during Fiscal 2009.

Sources of Supply

In accordance with Electric Utility’s default service settlement with the PUC effective January 1, 2010, Electric Utility will be permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with the PUC. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures” and Note 8 to Consolidated Financial Statements. Electric Utility distributes electricity that it purchases from wholesale markets and electricity that customers purchase from other suppliers, if any. See “Gas Utility and Electric Utility Regulation and Rates — Electric Utility Rates.”

As of September 30, 2009, 17 of Electric Utility’s customers have selected an alternative electricity generation supplier. Beginning in 2010, while Electric Utility expects to see an increasing number of customers selecting alternative electricity generation suppliers, it will continue to provide energy to the majority of its distribution customers for the foreseeable future.

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. In Fiscal 2009, Electric Utility served nearly all of the electric customers within its service territory and is the only regulated electric utility having the right, granted by the PUC or by law, to distribute electricity in its service territory. 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 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.” Beginning January 1, 2010, Electric Utility will be assured recovery of prudently incurred costs and will no longer be subject to the risk that actual costs for purchased power will exceed POLR revenues, but will, however, forego the opportunity to recover revenues in excess of actual costs.

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. PJM is a regional transmission organization that regulates and coordinates generation supply and the wholesale delivery of electricity. Electric Utility receives certain revenues collected by PJM, determined under a formulary rate schedule that is adjusted in June of each year to reflect annual changes in Electric Utility’s electric transmission revenue requirements, when its transmission facilities are used by third parties.

FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy. Electric Utility has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates.

Gas Utility Rates

The most recent general base rate increase for UGI Gas became effective in 1995. In accordance with a statutory mechanism, a rate increase for Gas Utility’s retail core-market customers became effective October 1, 2000 along with a 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.

On August 27, 2009, the PUC approved PNG’s and CPG’s rate case settlement agreements, which resulted in a $19.75 million base rate operating revenue increase for PNG and a $10 million base rate operating revenue increase for CPG. The increases became effective on August 28, 2009.

The gas service tariffs for UGI Gas, PNG and CPG contain PGC rates applicable to firm retail rate schedules. These PGC rates permit recovery of substantially all of the prudently incurred costs of natural gas that UGI Gas, PNG, and CPG sell to their customers. PGC rates are reviewed and approved annually by the PUC. UGI Gas, PNG, and CPG may request quarterly or, under certain conditions, monthly adjustments to reflect the actual cost of gas. Quarterly adjustments become effective on 1 day’s notice to the PUC and are subject to review during the next annual PGC filing. Each proposed annual PGC rate is required to be filed with the PUC 6 months prior to its effective date. During this period, the PUC holds hearings to determine whether the proposed rate reflects a least-cost fuel procurement policy consistent with the obligation to provide safe, adequate and reliable service. After completion of these hearings, the PUC issues an order permitting the collection of gas costs at levels which meet that standard. The PGC mechanism also provides for an annual reconciliation.

UGI Gas has two PGC rates. 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. PNG and CPG each have one PGC rate applicable to all customers. See Note 8 to Consolidated Financial Statements.

Electric Utility Rates

The most recent general base rate increase for Electric Utility became effective in 1996. Electric Utility’s rates were unbundled into distribution, transmission and generation (POLR or “default service”) components in 1998. In accordance with the POLR Settlements, Electric Utility increased POLR rates annually from 2005 through 2009. The increase implemented January 1, 2009 raised total average residential heating customer rates by approximately 1.5% over rates in effect during calendar year 2008. 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 April 30, 2014. Electric Utility received approval from the PUC of (1) default service tariff rules applicable for service rendered on or after January 1, 2010, (2) a reconcilable default service cost rate recovery mechanism to 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. Under these rules, default service rates for most customers will be adjusted quarterly.

FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers

Both Gas Utility and Electric Utility, and our subsidiaries UGI Energy Services, Inc. and UGI Development Company, are subject to FERC regulations governing the manner in which certain jurisdictional sales or transportation are conducted. Section 4A of the Natural Gas Act and Section 222 of the Federal Power Act prohibit the use or employment of any manipulative or deceptive devices or contrivances in connection with the purchase or sale of natural gas, electric energy, or natural gas transportation or electric transmission services subject to the jurisdiction of FERC. FERC has adopted regulations to implement these statutory provisions which apply to interstate transportation and sales by the Electric Utility, and to a much more limited extent, to certain sales and transportation by the Gas Utility that are subject to FERC’s jurisdiction. Gas Utility and Electric Utility are subject to certain other regulations and obligations for FERC-regulated activities. Under provisions of the Energy Policy Act of 2005 (“EPACT 2005”), Electric Utility is subject to certain electric reliability standards established by FERC and administered by an Electric Reliability Organization (“ERO”). Electric Utility anticipates that substantially all the costs of complying with the ERO standards will be recoverable through its PJM formulary electric transmission rate schedule.

EPACT 2005 also granted FERC authority to impose substantial civil penalties for the violation of any regulations, orders or provisions under the Federal Power Act and Natural Gas Act, and clarified FERC’s authority over certain utility or holding company mergers or acquisitions of electric utilities or electric transmitting utility property valued at $10 million or more.

State Tax Surcharge Clauses

UGI Utilities’ gas and electric service tariffs contain state tax surcharge clauses. The surcharges are recomputed whenever any of the tax rates included in their calculation are changed. These clauses protect UGI Utilities from the effects of increases in most of the Pennsylvania taxes to which it is subject.

Utility Franchises

UGI Utilities, PNG and CPG each hold certificates of public convenience issued by the PUC and certain “grandfather rights” predating the adoption of the Pennsylvania Public Utility Code and its predecessor statutes, which each of them believes are adequate to authorize them to carry on their business in substantially all of the territories to which they now render gas or electric service. Under applicable Pennsylvania law, UGI Utilities, PNG and CPG also have certain rights of eminent domain as well as the right to maintain their facilities in streets and highways in their territories.

Other Government Regulation

In addition to regulation by the PUC and FERC, the gas and electric utility operations of UGI Utilities are subject to various federal, state and local laws governing environmental matters, occupational health and safety, pipeline safety and other matters. UGI Utilities is subject to the requirements of the federal Resource Conservation and Recovery Act, CERCLA and comparable state statutes with respect to the release of hazardous substances on property owned or operated by UGI Utilities. See Note 15 to Consolidated Financial Statements.

Employees

At September 30, 2009, UGI Utilities had approximately 1,430 employees.

ENERGY SERVICES

UGI Energy Services, Inc. and its subsidiaries (collectively, “Energy Services”) operate the energy-related businesses described below.

Retail Energy Marketing

Energy Services conducts its energy marketing business under the trade name GASMARK^®. Energy Services sells natural gas, liquid fuels and electricity to approximately 8,000 commercial and industrial customers at approximately 25,000 locations. Energy Services serves customers in all or portions of Pennsylvania, New Jersey, Delaware, New York, Ohio, Maryland, Virginia, West Virginia, North Carolina and the District of Columbia. Energy Services distributes natural gas through the use of the transportation systems of 33 utility systems.

The gas marketing business is a high-revenue, low-margin business. A majority of Energy Services’ commodity sales are made under fixed-price agreements. Energy Services manages supply cost volatility related to these agreements by (i) entering into fixed-price supply arrangements with a diverse group of natural gas producers and holders of interstate pipeline capacity, (ii) entering into exchange-traded natural gas futures contracts which are guaranteed by the New York Mercantile Exchange and have nominal credit risk, (iii) entering into over-the-counter natural gas derivative arrangements with major international banks, and (iv) utilizing supply assets that it owns or manages. Energy Services 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

Energy Services operates a natural gas liquefaction, storage and vaporization facility in Temple, Pennsylvania (“Temple Facility”), and propane storage and propane-air mixing stations in Bethlehem, Reading and Hunlock Creek, Pennsylvania. It also operates propane storage, rail transshipment terminals and propane-air mixing stations in Steelton and Williamsport, Pennsylvania. These assets are used in Energy Services’ energy peaking business that provides supplemental energy, primarily liquefied natural gas and propane-air mixtures, to gas utilities at times of peak demand.

In Fiscal 2009, Energy Services began construction of a propane air plant in White Deer, Pennsylvania to increase its storage and peak capacities. The White Deer propane air plant is expected to be in service in December of 2009. During Fiscal 2009, Energy Services obtained FERC authorizations and began construction on the expansion of its Temple Facility which will increase storage capacity fourfold. The Temple Facility expansion is scheduled to be completed during calendar year 2012. Energy Services also manages natural gas pipeline and storage contracts for UGI Utilities, subject to a competitive bid process.

Energy Services 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 transshipment facility located in Chesapeake, Virginia.

Electric Generation

We have an approximate 6% (102 megawatt) ownership interest in the Conemaugh generation station (“Conemaugh”), a 1,711 megawatt, coal-fired generation station located near Johnstown, Pennsylvania. Conemaugh is owned by a consortium of energy companies and operated by a unit of Reliant Resources, Inc. Energy Services also owns the Hunlock Station located near Wilkes-Barre, Pennsylvania, which is a 44-megawatt coal-fired facility. The output from these generation assets is sold under fixed-term contracts and on the spot market through PJM. Energy Services is in the process of building a 130-megawatt natural gas fueled power plant to replace the Hunlock facility. This transition from a coal-fired to a natural gas-fueled facility is expected to be completed in fiscal year 2011. The Hunlock Station is expected to be closed during the third quarter of fiscal year 2010.

During Fiscal 2009, Energy Services completed the construction of a landfill gas-fueled electricity generation plant in Hegins, Pennsylvania with gross generating capacity of 11 megawatts of electricity. Energy Services owns and operates the plant which is expected to qualify for renewable energy credits. Energy Services is partnering with Binney & Smith, Inc. and PPL to develop a 15-acre solar panel park to supply 2 megawatts of electrical power to Binney & Smith’s Crayola facility in Easton, Pennsylvania. This solar project is expected to be completed during fiscal year 2010.

Competition

Energy Services competes with other marketers and local utilities to sell natural gas, liquid fuels and related services to customers in its service area principally on the basis of price, customer service and reliability. For electricity generation, Conemaugh and Hunlock Station compete with other generation stations on the PJM interface where sales are based on bid pricing.

Government Regulation

FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy, as well as the sales for resale of natural gas and related storage and transportation services. Energy Services has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates. Energy Services also has market-based rate authority for power sales to wholesale customers to the extent that Energy Services purchases power in excess of its retail customer needs. Energy Services also owns electric generation facilities that are within the control area of PJM and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM. Energy Services receives certain revenues collected by PJM, determined under a formulary rate schedule. Energy Services is also subject to FERC market manipulation rules and enforcement and regulatory powers. See “Gas Utility and Electric Utility Regulation and Rates — FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers.”

The operation of Hunlock Station generally 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. Energy Services is currently assessing the operational impact of compliance with pending environmental regulations related to mercury emission standards for Conemaugh and Hunlock Station.

Energy Services is subject to various federal, state and local environmental, safety and transportation laws and regulations governing the storage, distribution and transportation of propane and the operation of bulk storage LPG terminals. These laws include, among others, the Resource Conservation and Recovery Act, CERCLA, the Clean Air Act, the Occupational Safety and Health Act, the Homeland Security Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA imposes joint and several liability on certain classes of persons considered to have contributed to the release or threatened release of a “hazardous substance” into the environment without regard to fault or the legality of the original conduct. Propane is not a hazardous substance within the meaning of federal and most state environmental laws.

Employees

At September 30, 2009, Energy Services 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 2009, HVAC/R generated approximately $85 million in revenues and employed approximately 450 people.

GLOBAL CLIMATE CHANGE

There is a growing concern, both nationally and internationally, about climate change and the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global warming. While some states have adopted laws regulating the emission of GHGs for some industry sectors, there is currently no federal regulation mandating the reduction of GHG emissions in the United States. In June of 2009, the United States House of Representatives passed the American Clean Energy and Security Act (“ACES Act”). The ACES Act would establish an economy-wide GHG cap-and-trade system to reduce GHG emissions over time. Subsequently, the United States Senate offered a draft of its own climate change bill, the Clean Energy Jobs and American Power Act. While the Senate’s bill is based on the ACES Act, there are differences between the bills and no legislation can be enacted until a final combined bill is approved by both the House of Representatives and the Senate.

In September of 2009, the Environmental Protection Agency issued a final rule establishing an economy-wide system for mandatory reporting of GHG emissions. Facilities subject to the rule, which include our natural gas distribution businesses and our electricity generation facilities, are required to begin emissions monitoring in January of 2010 and to submit detailed annual reports beginning in March of 2011. The rule does not require affected facilities to implement GHG emission controls or reductions.

Two of the commodities we sell, namely LPG and natural gas, are considered clean alternative fuels under the federal Clean Air Act Amendments of 1990. We anticipate that this will provide us with a competitive advantage over other sources of energy, such as fuel oil and coal, when new climate change regulations become effective. In addition, we are in the process of refining and implementing our strategy to identify both our GHG emissions and our energy consumption in order to be in a position to comply with new regulations and to take advantage of any opportunities that may arise from the regulation of such emissions.

BUSINESS SEGMENT INFORMATION

The table stating the amounts of revenues, operating income (loss) and identifiable assets attributable to each of UGI’s reportable business segments, and to the geographic areas in which we operate, for the 2009, 2008 and 2007 fiscal years appears in Note 21 to Consolidated Financial Statements included in Item 8 of this Report and is incorporated herein by reference.

EMPLOYEES

At September 30, 2009, UGI and its subsidiaries had approximately 9,700 employees.

ITEM 1A.		RISK FACTORS

There are many factors that may affect our business and results of operations. Additional discussion regarding factors that may affect our business and operating results is included elsewhere in this Report.

Decreases in the demand for our energy products and services because of warmer-than-normal heating season weather may adversely affect our results of operations.

Because many of our customers rely on our energy products and services to heat their homes and businesses, our results of operations are adversely affected by warmer-than-normal heating season weather. Weather conditions have a significant impact on the demand for our energy products and services for both heating and agricultural purposes. Accordingly, the volume of our energy products sold is at its highest during the peak heating season of October through March and is directly affected by the severity of the winter weather. For example, historically, approximately 65% to 70% of AmeriGas Partners’ annual retail propane volume, Gas Utility’s natural gas throughput (the total volume of gas sold to or transported for customers within our distribution system) and Antargaz’ annual retail LPG volume has been sold during these months. There can be no assurance that normal winter weather in our market areas will occur in the future.

Our holding company structure could limit our ability to pay dividends or debt service.

We are a holding company whose material assets are the stock of our subsidiaries. Our ability to pay dividends on our common stock and to pay principal and accrued interest on our debt, if any, depends on the payment of dividends to us by our principal subsidiaries, AmeriGas, Inc., UGI Utilities, Inc. and UGI Enterprises, Inc. (including Antargaz). Payments to us by those subsidiaries, in turn, depend upon their consolidated results of operations and cash flows 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 LPG pricing and inventory risk.

The retail LPG business is a “margin-based” business in which gross profits are dependent upon the excess of the sales price over the LPG supply costs. LPG is a commodity, and, as such, its unit price is subject to volatile fluctuations in response to changes in supply or other market conditions. We have no control over these market conditions. Consequently, the unit price of the LPG that our subsidiaries and other marketers purchase can change rapidly over a short period of time. Most of our domestic LPG product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major U.S. storage points such as Mont Belvieu, Texas or Conway, Kansas. Most of our international LPG supply contracts are based on internationally quoted market prices. Because our subsidiaries’ profitability is sensitive to changes in wholesale supply costs, it will be adversely affected if we cannot pass on increases in cost to our customers. Due to competitive pricing in the industry, our subsidiaries may not be able to pass on product cost increases to our customers when product costs rise rapidly, or when our competitors do not raise their product prices. Finally, market volatility may cause our subsidiaries to sell LPG at less than the price at which they purchased it, which would adversely affect our operating results.

Energy efficiency and technology advances, as well as price induced customer conservation, may result in reduced demand for our energy products and services.

The trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, may reduce the demand for energy products. Prices for LPG and natural gas are subject to volatile fluctuations in response to changes in supply and other market conditions. During periods of high energy commodity costs, our prices generally increase which may lead to customer conservation. A reduction in demand could lower our revenues, and therefore, lower our net income and adversely affect our cash flows. State and/or federal regulation may require mandatory conservation measures which would reduce the demand for our energy products. We cannot predict the materiality of the effect of future conservation measures or the effect that any technological advances in heating, conservation, energy generation or other devices might have on our operations.

Volatility in credit and capital markets may restrict our ability to grow, increase the likelihood of defaults by our customers and counterparties and adversely affect our operating results.

The recent volatility in credit and capital markets may create additional risks to our businesses in the future. We are exposed to financial market risk (including refinancing risk) resulting from, among other things, changes in interest rates, foreign currency exchange rates and conditions in the credit and capital markets. Recent developments in the credit markets increase our possible exposure to the liquidity, default and credit risks of our suppliers, counterparties associated with derivative financial instruments and our customers. Although we believe that recent financial market conditions, if they were to continue for the foreseeable future, will not have a significant impact on our ability to fund our existing operations, such market conditions could restrict our ability to grow through acquisitions, limit the scope of major capital projects if access to credit and capital markets is limited, or could otherwise adversely affect our operating results.

The economic recession, volatility in the stock market and the low interest rate environment may negatively impact our pension liability.

The economic recession, the recent decline in the stock market and the low interest rate environment have had a significant impact on our pension liability and funded status. Additional declines in the stock market and valuation of stocks, combined with continued low interest rates, could further impact our pension liability and increase the amount of required contributions to our pension plans.

Supplier defaults may have a negative effect on our operating results.

When the Company enters into fixed-price sales contracts with customers, it typically enters into fixed-price purchase contracts with suppliers. Depending on changes in the market prices of products compared to the prices secured in our contracts with suppliers of LPG and natural gas, a default of one or more of our suppliers under such contracts could cause us to purchase LPG and natural gas at higher prices which would have a negative impact on our operating results.

We are dependent on our principal propane suppliers, which increases the risks from an interruption in supply and transportation.

During Fiscal 2009, AmeriGas Propane purchased approximately 80% of its propane needs from ten suppliers. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, our earnings could be affected. Additionally, in certain areas, some of AmeriGas Propane’s suppliers provide more than 50% of its propane requirements. Disruptions in supply in these areas could also have an adverse impact on our earnings. Antargaz is similarly dependent upon its suppliers. LPG must be imported to meet demand in France. There is no assurance that Antargaz will be able to continue to acquire sufficient supplies of LPG to meet demand at prices or within time periods that would allow it to remain competitive.

Changes in commodity market prices may have a negative effect on our liquidity.

Depending on the terms of our contracts with suppliers and some large customers, as well as our use of financial instruments to reduce volatility in the cost of LPG, electricity or natural gas, and for all of our contracts with the NYMEX, changes in the market price of LPG, electricity and natural gas can create margin payment obligations for the Company or one of its subsidiaries and expose us to an increased liquidity risk.

Our operations may be adversely affected by competition from other energy sources.

Our energy products and services face competition from other energy sources, some of which are less costly for equivalent energy value. In addition, we cannot predict the effect that the development of alternative energy sources might have on our operations.

Our propane businesses compete for customers against suppliers of electricity, fuel oil and natural gas. Electricity is a major competitor of propane. In the United States, propane generally enjoys a competitive price advantage over electricity for space heating, water heating and cooking. Fuel oil is also a major competitor of propane and is generally less expensive than propane. Furnaces and appliances that burn propane will not operate on fuel oil and vice versa, and, therefore, a conversion from one fuel to the other requires the installation of new equipment. Our customers generally have an incentive to switch to fuel oil only if fuel oil becomes significantly less expensive than propane. Except for certain industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is generally a less expensive source of energy than propane. The gradual expansion of natural gas distribution systems in our service areas has resulted, and may continue to result, in the availability of natural gas in some areas that previously depended upon propane. As long as natural gas remains a less expensive energy source than propane, our propane business will lose customers in each region into which natural gas distribution systems are expanded. In France, the state-owned natural gas monopoly, Gaz de France, has in the past extended France’s natural gas grid.

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 ACE 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 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 may charge their utility customers, thus impacting the returns that UGI Utilities may earn on the assets that are dedicated to those operations. We expect that PNG and CPG will periodically file requests with the PUC to increase base rates that each company charges customers. If UGI Utilities is required in a rate proceeding to reduce the rates they charge their utility customers, or if UGI Utilities is unable to obtain approval for timely rate increases from the PUC, particularly when necessary to cover increased costs, UGI Utilities’ revenue growth will be limited and earnings may decrease.

Our operations, capital expenditures and financial results may be affected by regulatory changes and/or market responses to global climate change.

There is a growing concern, both nationally and internationally, about climate change and the contribution of GHG emissions, most notably carbon dioxide, to global warming. In response to this concern, the United States House of Representatives passed the American Clean Energy and Security Act (“ACES Act”) in June of 2009 to establish an economy-wide GHG cap-and-trade system to reduce GHG emissions over time. Subsequently, the United States Senate offered a draft climate change bill, the Clean Energy Jobs and American Power Act, based on the ACES Act. The proposed legislation includes a cap-and-trade policy structure in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. The legislation establishes mechanisms for GHG sources to obtain allowances to emit GHGs during the course of a year which may be used to cover their own emissions or they can be sold to other sources that do not hold enough allowances for their own operations.

It is expected that climate change legislation will continue to be a priority in the foreseeable future and it is anticipated that federal legislation mandating the reduction of GHG emissions on an economy-wide basis may be enacted during calendar year 2010. Increased regulation of GHG emissions, especially in the electric generation and transportation sectors, could impose significant additional costs on UGI and our customers. The impact of legislation and regulations on us will depend on a number of factors, including (i) what industry sectors would be impacted, (ii) the timing of required compliance, (iii) the overall GHG emissions cap level, (iv) the allocation of emission allowances to specific sources and (v) the costs and opportunities associated with compliance. At this time, we cannot predict the effect that 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. There can be no assurance that our insurance will be adequate to protect us from all material expenses related to pending and future claims or that such levels of insurance will be available in the future at economical prices.

We may be unable to respond effectively to competition, which may adversely affect our operating results.

We may be unable to timely respond to changes within the energy and utility sectors that may result from regulatory initiatives to further increase competition within our industry. Such regulatory initiatives may create opportunities for additional competitors to enter our markets and, as a result, we may be unable to maintain our revenues or continue to pursue our current business strategy.

Our net income will decrease if we are required to incur additional costs to comply with new governmental safety, health, transportation, tax and environmental regulations.

We are subject to extensive and changing international, federal, state and local safety, health, transportation, tax and environmental laws and regulations governing the storage, distribution and transportation of our energy products.

New regulations, or a change in the interpretation of existing regulations, could result in increased expenditures. In addition, for many of our operations, we are required to obtain permits from regulatory authorities. Failure to obtain or comply with these permits or applicable laws could result in civil and criminal fines or the cessation of the operations in violation. Governmental regulations and policies in the United States and Europe may provide for subsidies or incentives to customers who use alternative fuels instead of carbon fuels. These subsidies and incentives may result in reduced demand for our energy products and services.

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.

Our international operations could result in increased risks which may negatively affect our business results.

We currently operate LPG distribution businesses in Europe through our subsidiaries, Antargaz and Flaga and we continue to explore the expansion of our international businesses. As a result, we face risks in doing business abroad that we do not face domestically. Certain aspects inherent in transacting business internationally could negatively impact our operating results, including:

	•		costs and difficulties in staffing and managing international operations;
	•		tariffs and other trade barriers;
	•		difficulties in enforcing contractual rights;
	•		longer payment cycles;
	•		local political and economic conditions;
	•		potentially adverse tax consequences, including restrictions on repatriating earnings and the threat of “double taxation”;
	•		fluctuations in currency exchange rates, which can affect demand and increase our costs;
	•		internal control and risk management practices and policies; and
	•		regulatory requirements and changes in regulatory requirements, including French, Austrian 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 Note 15 to Consolidated Financial Statements.

ITEM 1B.		UNRESOLVED STAFF COMMENTS

None.

ITEM 3.		LEGAL PROCEEDINGS

With the exception of those matters set forth in Note 15 to 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.

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 2009.

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:

2009 Fiscal Year		High				Low
4th Quarter		$	26.99			$	24.32
3rd Quarter			26.04				22.11
2nd Quarter			27.38				21.135
1st Quarter			26.68				18.69

2008 Fiscal Year		High				Low
4th Quarter		$	28.64			$	24.35
3rd Quarter			28.87				25.02
2nd Quarter			27.43				23.99
1st Quarter			28.18				24.79

Dividends

Quarterly dividends on our Common Stock were paid in Fiscal 2009 and Fiscal 2008 as follows:

2009 Fiscal Year		Amount
4th Quarter		$	0.20000
3rd Quarter			0.19250
2nd Quarter			0.19250
1st Quarter			0.19250

2008 Fiscal Year		Amount
4th Quarter		$	0.19250
3rd Quarter			0.18500
2nd Quarter			0.18500
1st Quarter			0.18500

Record Holders

On November 16, 2009, UGI had 8,053 holders of record of Common Stock.

ITEM 6.		SELECTED FINANCIAL DATA

		Year Ended September 30,
(Millions of dollars, except per share amounts)		2009				2008				2007				2006				2005
FOR THE PERIOD:
Income statement data:
Revenues		$	5,737.8			$	6,648.2			$	5,476.9			$	5,221.0			$	4,888.7
Net income		$	258.5			$	215.5			$	204.3			$	176.2			$	187.5
Earnings per common share:
Basic		$	2.38			$	2.01			$	1.92			$	1.67			$	1.81
Diluted		$	2.36			$	1.99			$	1.89			$	1.65			$	1.77
Cash dividend declared per common share		$	0.785			$	0.755			$	0.723			$	0.690			$	0.650
AT PERIOD END:
Balance sheet data:
Total assets		$	6,042.6			$	5,685.0			$	5,502.7			$	5,080.5			$	4,571.5
Capitalization:
Debt:
Bank loans — UGI Utilities		$	154.0			$	57.0			$	190.0			$	216.0			$	81.2
Bank loans — Antargaz			—				70.4				—				—				—
Bank loans — other			9.1				9.0				8.9				9.4				16.2
Long-term debt (including current maturities):
AmeriGas Propane			865.6				933.4				933.1				933.7				913.5
Antargaz			557.7				537.4				544.9				483.5				431.1
UGI Utilities			640.0				532.0				512.0				512.0				237.0
Other			69.8				66.3				63.5				67.7				62.9
Total debt			2,296.2				2,205.5				2,252.4				2,222.3				1,741.9
Minority interests, principally in AmeriGas Partners			225.4				159.2				192.2				139.5				206.3
Common stockholders’ equity			1,591.4				1,417.7				1,321.9				1,099.6				997.6
Total capitalization		$	4,113.0			$	3,782.4			$	3,766.5			$	3,461.4			$	2,945.8
Ratio of capitalization:
Total debt			55.8	%			58.3	%			59.8	%			64.2	%			59.1	%
Minority interests, principally in AmeriGas Partners			5.5	%			4.2	%			5.1	%			4.0	%			7.0	%
Common stockholders’ equity			38.7	%			37.5	%			35.1	%			31.8	%			33.9	%
			100.0	%			100.0	%			100.0	%			100.0	%			100.0	%

ITEM 7.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) discusses our results of operations and our financial condition. MD&A should be read in conjunction with our Items 1 & 2, “Business and Properties,” our Item 1A, “Risk Factors” and our Consolidated Financial Statements in Item 8 below including “Segment Information” included in Note 21 to Consolidated Financial Statements.

Executive Overview

Our net income in Fiscal 2009 was $258.5 million, an increase of 20% over Fiscal 2008 net income of $215.5 million. A number of factors contributed to this improved performance. The most significant contributor to the improved performance was a substantial year-over-year decline in LPG commodity costs both in the U.S. and in our International Propane operations. Commodity prices for LPG declined precipitously as we entered our critical winter heating season in the first quarter of Fiscal 2009 following a significant increase in LPG prices during most of the second half of Fiscal 2008. As a result of the declines in LPG commodity prices, our AmeriGas Propane and International Propane businesses realized higher than normal retail unit margins. Although LPG commodity prices rose modestly later in Fiscal 2009 from earlier Fiscal 2009 low levels, U.S. propane commodity prices at the end of Fiscal 2009 were approximately 35% lower than at September 30, 2008, and propane prices in Europe at the end of Fiscal 2009 were approximately 29% lower than at the end of Fiscal 2008. Also contributing to improved performance during Fiscal 2009, most of our domestic and international business units experienced weather that was, to varying degrees, colder than in Fiscal 2008. Our Gas Utility results in Fiscal 2009 were better than in Fiscal 2008 in large part reflecting accretive income from the operations of CPG Gas acquired on October 1, 2008. During Fiscal 2009, CPG Gas and PNG Gas filed separate requests with the PUC to increase base operating revenues. We received PUC approval of increased rates that went into effect in late August 2009. The combined increases in annual base rate revenues approved totaled $29.8 million. Due to the timing of the new rates, they did not have a material impact on our Fiscal 2009 results. Results in Fiscal 2009 also benefited from the Partnership’s November 2008 sale of its California LPG storage facility which increased UGI’s net income by $10.4 million.

Partially offsetting the previously-mentioned contributions to our net income in Fiscal 2009 were lower results from Energy Services and Electric Utility, a charge associated with the Antargaz Competition Authority Matter and the global recession’s effects on general economic activity in all of our business units. Lower and less volatile commodity prices for natural gas and a general decline in demand for electricity due in large part to the economic recession resulted in lower electricity prices in Fiscal 2009. These lower prices resulted in reduced margins from spot sales of electricity. In addition, Energy Services’ electricity generation volumes were reduced by higher production outages and electric generation expenses were higher in Fiscal 2009 due in part to charges related to obligations associated with its ongoing Hunlock Station repowering project. Electric Utility results declined in Fiscal 2009 reflecting the impact of the recession on volumes sold and higher purchased power costs. Our Fiscal 2009 net income was also reduced by a $10.0 million charge at Antargaz based on our initial assessment of a Statement of Objections received from France’s Competition Authority.

The U.S. dollar was stronger versus the euro in Fiscal 2009 compared to Fiscal 2008. Although the stronger dollar generally resulted in lower translated International Propane operating results, the effects of the stronger dollar on reported International Propane net income were substantially offset by gains on forward currency contracts used to hedge purchases of dollar-denominated LPG.

Looking ahead, our results in Fiscal 2010 will be influenced by a number of factors including heating-season temperatures in our business units, the length and severity of the global recession on economic activity, and the level and volatility of commodity prices for natural gas, LPG and electricity. As previously mentioned, the precipitous decline in LPG commodity prices principally during the first quarter of Fiscal 2009 resulted in higher than normal unit margins in our AmeriGas Propane and International Propane businesses. We expect that average retail unit margins in Fiscal 2010 in our International Propane business will be lower than the average unit margins realized in Fiscal 2009 when LPG commodity prices declined significantly entering our critical winter heating season. At Energy Services, sustained low prices for electricity sales would continue to negatively impact results. At UGI Utilities, our Electric Utility’s default service settlement with the PUC, which becomes effective January 1, 2010, allows for the recovery of prudently incurred electricity costs but eliminates the opportunity for Electric Utility to realize revenue in excess of such costs on electricity sales. This will result in a reduction in Electric Utility’s Fiscal 2010 operating income.

We believe that each of our business units has sufficient liquidity in the form of revolving credit facilities, letters of credit and guarantee agreements to fund business operations for the foreseeable future. Due in large part to declining commodity prices for LPG and natural gas, Fiscal 2009 cash flow was stronger than Fiscal 2008 as our total investment in working capital, principally accounts receivable and inventories, declined. We do not have significant amounts of long-term debt maturing or revolving credit agreements terminating at our major business units until late in Fiscal 2011.

Results of Operations

The following analyses compare the Company’s results of operations for (1) Fiscal 2009 with Fiscal 2008 and (2) Fiscal 2008 with the year ended September 30, 2007 (“Fiscal 2007”).

Fiscal 2009 Compared with Fiscal 2008
Consolidated Results

																		Variance- Favorable
		2009								2008								(Unfavorable)
						% of								% of
		Net				Total								Total
		Income				Net				Net				Net				Net				%
(Millions of dollars)		(Loss)				Income				Income				Income				Income				Change
AmeriGas Propane		$	65.0				25.1	%		$	43.9				20.4	%		$	21.1				48.1	%
International Propane			78.3				30.3	%			52.3				24.3	%			26.0				49.7	%
Gas Utility			70.3				27.2	%			60.3				28.0	%			10.0				16.6	%
Electric Utility			8.0				3.1	%			13.1				6.1	%			(5.1	)			(38.9	)%
Energy Services			38.1				14.7	%			45.3				21.0	%			(7.2	)			(15.9	)%
Corporate & Other			(1.2	)			(0.4	)%			0.6				0.2	%			(1.8	)			N.M.
Total		$	258.5				100.0	%		$	215.5				100.0	%		$	43.0				20.0	%

N.M. — Variance is not meaningful.

Highlights — Fiscal 2009 versus Fiscal 2008

•

Higher unit margins at AmeriGas Propane and Antargaz reflect significant declines in LPG commodity prices entering our critical heating season.

•

Most of our business units experienced Fiscal 2009 heating-season temperatures that were to varying degrees colder than in Fiscal 2008.

•

Fiscal 2009 Gas Utility results include the benefit of the CPG Acquisition on October 1, 2008.

•

AmeriGas Partners’ sale of its California LPG storage terminal generated net income of $10.4 million.

•

The global economic recession reduced overall business activity in all of our business units.

•

International Propane results reflect a $10.0 million charge for the Antargaz Competition Authority Matter.

•

Energy Services’ results were adversely impacted by lower income from electricity generation.

•

Electric Utility results were lower reflecting the effects of higher cost of sales and lower demand as a result of the recession.

										Increase
AmeriGas Propane		2009				2008				(Decrease)
(Millions of dollars)
Revenues		$	2,260.1			$	2,815.2			$	(555.1	)			(19.7	)%
Total margin (a)		$	943.6			$	906.9			$	36.7				4.0	%
Partnership EBITDA (b)		$	381.4			$	313.0			$	68.4				21.9	%
Operating income		$	300.5			$	235.0			$	65.5				27.9	%
Retail gallons sold (millions)			928.2				993.2				(65.0	)			(6.5	)%
Degree days — % (warmer) than normal (c)			(2.5	)%			(3.0	)%			—				—

Based upon heating degree-day data, average temperatures in our service territories during Fiscal 2009 were 2.5% warmer than normal compared with temperatures in the prior year that were 3.0% warmer than normal. Fiscal 2009 retail gallons sold were 6.5% lower than Fiscal 2008 reflecting, among other things, the adverse effects of the significant deterioration in general economic activity which has occurred over the last year and continued customer conservation. During Fiscal 2009, average wholesale propane commodity prices at Mont Belvieu, Texas, one of the major supply points in the U.S., were more than 50% lower than such prices in Fiscal 2008. The decrease in the average wholesale commodity prices in Fiscal 2009 reflects the effects of a precipitous decline in commodity propane prices principally during the first quarter of Fiscal 2009 following a substantial increase in prices during most of the second half of Fiscal 2008. Although wholesale propane prices in Fiscal 2009 rebounded modestly from prices experienced earlier in the year, at September 30, 2009 such prices remained approximately 35% lower than at September 30, 2008.

Retail propane revenues declined $463.2 million in Fiscal 2009 reflecting a $303.6 million decrease as a result of the lower retail volumes sold and a $159.6 million decrease due to lower average selling prices. Wholesale propane revenues declined $69.5 million reflecting an $83.7 million decrease from lower wholesale selling prices partially offset by a $14.2 million increase from higher wholesale volumes sold. Total cost of sales decreased $591.8 million to $1,316.5 million principally reflecting the effects of the previously mentioned lower propane commodity prices and the lower volumes sold.

Total margin was $36.7 million greater in Fiscal 2009 reflecting the beneficial impact of higher than normal retail unit margins resulting from the previously mentioned rapid decline in propane commodity costs that occurred primarily as we entered the critical winter heating season in the first quarter of Fiscal 2009. The increase in total propane margin was partially offset by lower terminal revenue and ancillary sales and fee income.

The $68.4 million increase in Fiscal 2009 Partnership EBITDA reflects the effects of a $39.9 million pre-tax gain from the November 2008 sale of the Partnership’s California LPG storage facility and the previously mentioned $36.7 million increase in total margin. These increases were partially offset by slightly higher operating and administrative expenses and slightly lower other income. The slightly higher operating and administrative expenses reflects, in large part, higher compensation and benefit expenses, higher costs associated with facility maintenance projects and higher litigation and self insured liability and casualty charges offset principally by lower vehicle fuel expenses (due to lower propane, diesel and gasoline prices) and lower Fiscal 2009 uncollectible accounts expense.

Operating income increased $65.5 million in Fiscal 2009 reflecting the previously mentioned $68.4 million increase in EBITDA partially offset by slightly higher depreciation and amortization expense associated with acquisitions and plant and equipment expenditures made since the prior year.

										Increase
International Propane		2009 (a)				2008				(Decrease)
(Millions of euros)
Revenues		€	712.7			€	749.8			€	(37.1	)			(4.9	)%
Total margin (b)		€	392.7			€	314.9			€	77.8				24.7	%
Operating income		€	116.3			€	70.4			€	45.9				65.2	%
Income before income taxes		€	95.3			€	48.8			€	46.5				95.3	%
(Millions of dollars)
Revenues		$	955.3			$	1,124.8			$	(169.5	)			(15.1	)%
Total margin (b)		$	525.8			$	472.9			$	52.9				11.2	%
Operating income		$	151.4			$	106.8			$	44.6				41.8	%
Income before income taxes		$	122.0			$	73.0			$	49.0				67.1	%
Antargaz retail gallons sold			289.3				292.6				(3.3	)			(1.1	)%
Degree days — % (warmer) than normal (c)			(2.9	)%			(4.1	)%			—				—

Based upon heating degree day data, temperatures in Antargaz’ service territory were approximately 2.9% warmer than normal during Fiscal 2009 compared with temperatures that were approximately 4.1% warmer than normal during Fiscal 2008. Temperatures in Flaga’s service territory were warmer than normal and warmer than Fiscal 2008. Wholesale propane product costs declined significantly during late Fiscal 2008 and the first quarter of Fiscal 2009 as we entered the critical winter heating season. As a result, the average wholesale commodity price for propane in northwest Europe in Fiscal 2009 was approximately 41% lower than such price in Fiscal 2008. Similar declines in average wholesale butane prices were experienced in Fiscal 2009. Antargaz’ Fiscal 2009 retail LPG volumes were slightly lower than in Fiscal 2008 reflecting the colder Fiscal 2009 weather offset by the effects of the deterioration of general economic conditions in France, customer conservation and competition from alternate energy sources.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. During Fiscal 2009, the average currency translation rate was $1.35 per euro compared to a rate of $1.51 per euro during Fiscal 2008. Although the stronger dollar resulted in lower translated International Propane operating results, the effects of the stronger dollar on reported International Propane net income were substantially offset by gains on forward currency contracts used to hedge purchases of dollar-denominated LPG.

International Propane euro-based revenues decreased €37.1 million or 4.9% in Fiscal 2009 reflecting lower average selling prices partially offset by an increase in revenues from the consolidation of ZLH. The lower average selling prices reflect the previously mentioned year-over-year decrease in wholesale LPG product costs. In U.S. dollars, revenues declined $169.5 million or 15.1% reflecting the previously mentioned total lower euro-based revenues and the effects of the stronger U.S. dollar. International Propane’s total cost of sales decreased to €320.0 million in Fiscal 2009 from €434.9 million in Fiscal 2008, a 26.4% decline, principally reflecting the lower per-unit LPG commodity costs and, to a much lesser extent, the effects of gains on forward currency contracts used to hedge purchases of dollar-denominated LPG. On a U.S. dollar basis, cost of sales decreased $222.4 million or 34.1%.

International Propane euro-based total margin increased €77.8 million or 24.7% in Fiscal 2009 largely reflecting the beneficial impact of higher than normal retail unit margins at Antargaz resulting from the rapid and sharp decline in LPG commodity costs that occurred as we entered the winter heating season in the first quarter of Fiscal 2009 and, to a lesser extent, incremental total margin from the consolidation of ZLH beginning in January 2009. Also affecting the year-over-year comparison was the fact that Antargaz was adversely affected by lower unit margins in Fiscal 2008 as a result of the rapid increase in LPG product costs which occurred in Fiscal 2008. In U.S. dollars, total margin increased $52.9 million or 11.2% reflecting the effects of the stronger dollar on translated euro base-currency revenues and cost of sales.

International Propane euro-based operating income increased €45.9 million or 65.2% in Fiscal 2009 principally reflecting the previously mentioned increase in total margin reduced by a €7.1 million charge related to a French Competition Authority Matter (as further described below under “Antargaz Competition Authority Matter”) and higher operating and administrative costs. The higher operating and administrative costs principally resulted from the consolidation of the operations of ZLH and, to a much lesser extent, higher operating expenses at Antargaz. On a U.S. dollar basis, operating income increased $44.6 million or 41.8% reflecting the previously-mentioned increase in U.S. dollar-denominated total margin and lower U.S. dollar-denominated operating and administrative expenses and depreciation and amortization partially offset by the $10.0 million charge related to the Antargaz Competition Authority Matter. Euro-based income before income taxes was €46.5 million (95.3%) greater than in the prior year principally reflecting the higher operating income and lower average effective interest rates on Antargaz’ term loan. In U.S. dollars, income before income taxes increased $49.0 million (67.1%) reflecting the benefit of the higher dollar-denominated operating income and lower Antargaz interest expense including the effects of the stronger dollar. Loss from International Propane equity investees was higher in Fiscal 2009 due to expenditures associated with the anticipated closure of an LPG storage facility.

Gas Utility		2009				2008				Increase
(Millions of dollars)
Revenues		$	1,241.0			$	1,138.3			$	102.7				9.0	%
Total margin (a)		$	387.8			$	307.2			$	80.6				26.2	%
Operating income		$	153.5			$	137.6			$	15.9				11.6	%
Income before income taxes		$	111.3			$	100.5			$	10.8				10.7	%
System throughput — billions of cubic feet (“bcf”)			149.7				133.7				16.0				12.0	%
Degree days — % colder (warmer) than normal (b)			4.1	%			(2.7	)%			—				—

Temperatures in the Gas Utility service territory based upon heating degree days were 4.1% colder than normal in Fiscal 2009 compared with temperatures that were 2.7% warmer than normal in Fiscal 2008. In Fiscal 2009, Gas Utility began calculating normal degree days using the 15-year period 1990-2004. Previously, normal degree days were based upon recent 30-year periods. For comparison purposes, the Fiscal 2008 weather variance has been recalculated using the new 15-year period. Total distribution throughput increased 16.0 bcf in Fiscal 2009 principally reflecting the effects of the October 1, 2008 CPG Acquisition and increases in core-market volumes resulting from the colder Fiscal 2009 weather and year-over-year customer growth. 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 customers who purchase their gas from alternate suppliers. These increases in system throughput were partially offset by the effects on volumes sold and transported due to lower demand from commercial and industrial customers as a result of the deterioration in general economic activity and customer conservation.

Gas Utility revenues increased $102.7 million in Fiscal 2009 principally reflecting $187.4 million of incremental revenues from CPG Gas largely offset by lower revenues from low-margin off-system sales. Increases or decreases in retail core-market revenues and cost of sales principally result from changes in retail core-market volumes and the level of gas costs collected through the PGC recovery mechanism. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $853.2 million in Fiscal 2009 compared with $831.1 million in Fiscal 2008 principally reflecting incremental cost of sales of $117.0 million associated with CPG Gas partially offset principally by the cost of sales effect of the lower off-system sales.

Gas Utility total margin increased $80.6 million in Fiscal 2009 principally reflecting incremental margin from CPG Gas and higher total core-market margin resulting from the higher core-market volumes sold.

The increase in Gas Utility operating income during Fiscal 2009 principally reflects the previously mentioned greater total margin partially offset by higher operating and administrative and depreciation expenses, principally incremental expenses associated with CPG Gas, and, to a lesser extent, higher pension expense, costs associated with environmental matters and greater distribution system maintenance expenses. Income before income taxes also increased reflecting the previously mentioned higher operating income partially offset by higher interest expense associated with $108 million Senior Notes issued to finance a portion of the CPG Acquisition.

Electric Utility		2009				2008				Decrease
(Millions of dollars)
Revenues		$	138.5			$	139.2			$	(0.7	)			(0.5	)%
Total margin (a)		$	39.3			$	47.0			$	(7.7	)			(16.4	)%
Operating income		$	15.4			$	24.4			$	(9.0	)			(36.9	)%
Income before income taxes		$	13.7			$	22.4			$	(8.7	)			(38.8	)%
Distribution sales — millions of kilowatt hours (“gwh”)			965.7				1,004.4				(38.7	)			(3.9	)%

Electric Utility’s kilowatt-hour sales in Fiscal 2009 were lower than in Fiscal 2008. Temperatures based upon heating degree days in Electric Utility’s service territory were approximately 5.0% colder than last year resulting in greater sales to Electric Utility’s residential heating customers. These greater sales were more than offset, however, by lower sales to commercial and industrial customers as a result of the deterioration in general economic activity and lower weather-related air-conditioning sales during the summer of Fiscal 2009. Notwithstanding the lower sales, Electric Utility revenues were about equal with last year as a result of higher POLR rates and greater revenues from spot market sales of electricity. Electric Utility cost of sales increased to $91.6 million in Fiscal 2009 from $84.3 million in Fiscal 2008 principally reflecting greater purchased power costs.

Electric Utility total margin decreased $7.7 million during Fiscal 2009 principally reflecting the higher cost of sales and the effects of the lower sales volumes.

Electric Utility operating income and income before income taxes in Fiscal 2009 were $9.0 million and $8.7 million lower than in Fiscal 2008, respectively, reflecting the previously mentioned lower total margin and higher operating and administrative costs including higher customer assistance expenses and greater pension expense.

										Increase
Energy Services		2009				2008				(Decrease)
(Millions of dollars)
Revenues		$	1,224.7			$	1,619.5			$	(394.8	)			(24.4	)%
Total margin (a)		$	126.2			$	124.1			$	2.1				1.7	%
Operating income		$	64.8			$	77.3			$	(12.5	)			(16.2	)%
Income before income taxes		$	64.8			$	77.3			$	(12.5	)			(16.2	)%

Energy Services total revenues declined $394.8 million or 24.4% in Fiscal 2009 principally reflecting the effects on revenues of lower unit prices for natural gas, electricity and propane due to year-over-year declines in such energy commodity prices.

Total margin from Energy Services increased $2.1 million in Fiscal 2009 reflecting greater total margin principally from peaking supply services and retail electricity sales partially offset by lower electric generation total margin. The decrease in electric generation total margin reflects lower spot-market prices for electricity and lower volumes generated due in large part to electricity generation facility outages. The decrease in Energy Service’s operating income and income before income taxes in Fiscal 2009 largely reflects the previously mentioned increase in total margin more than offset by higher electric generation operating and maintenance costs and charges related to obligations associated with its ongoing Hunlock Station repowering project, and higher asset management costs. The decrease in operating income and income before income taxes also reflects greater costs associated with Energy Service’s receivables securitization facility as a result of higher amounts needed to fund futures brokerage account margin calls and greater facility fees subsequent to the renewal of the securitization facility in April 2009.

Interest Expense and Income Taxes. Consolidated interest expense decreased slightly to $141.1 million in Fiscal 2009 from $142.5 million in Fiscal 2008 principally due to lower International Propane interest expense, attributable to lower effective interest rates and the stronger U.S. dollar, lower interest on UGI Utilities revolving credit agreement borrowings and lower interest expense on AmeriGas Propane long-term debt largely offset by incremental interest expense on CPG Acquisition debt. Our effective income tax rate in Fiscal 2009 was comparable to our rate in Fiscal 2008.

Fiscal 2008 Compared with Fiscal 2007
Consolidated Results

																		Variance- Favorable
		2008								2007								(Unfavorable)
						% of								% of
						Total				Net				Total
		Net				Net				Income				Net				Net				%
(Millions of dollars)		Income				Income				(Loss)				Income				Income				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)			(3.0	)%			(6.5	)%			—				—

Based upon heating degree-day data, average temperatures in AmeriGas Propane’s service territories were 3.0% 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 product cost at Mont Belvieu, Texas, increased nearly 50% during Fiscal 2008 over the average cost during Fiscal 2007.

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				.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)			(2.7	)%			(2.4	)%			—				—

Temperatures in the Gas Utility service territory based upon heating degree days were 2.7% warmer than normal in Fiscal 2008 compared with temperatures that were 2.4% 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 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 PGC rates on retail core-market revenues. 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 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 Service’s 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.

Financial Condition and Liquidity

We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with proceeds from credit facilities or, in the case of Energy Services, a receivables securitization facility. These facilities are further described below. Long-term cash needs are generally met through issuance of long-term debt or equity securities.

Our cash and cash equivalents, excluding cash included in commodity futures brokerage accounts that are restricted from withdrawal, totaled $280.1 million at September 30, 2009 compared with $245.2 million of such cash and cash equivalents at September 30, 2008. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30, 2009 and 2008 UGI had $102.7 million and $97.2 million, respectively, of cash and cash equivalents. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.

The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its corporate subsidiaries by its principal business units.

AmeriGas Propane’s ability to pay dividends to UGI is dependent upon distributions it receives from AmeriGas Partners. At September 30, 2009, our 44% effective ownership interest in the Partnership consisted of approximately 24.7 million Common Units and combined 2% general partner interests. Approximately 45 days after the end of each fiscal quarter, the Partnership distributes all of its Available Cash (as defined in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, the “Partnership Agreement”) relating to such fiscal quarter. 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 2009, Fiscal 2008 and Fiscal 2007, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:

Year Ended September 30,		2009				2008				2007
(Millions of dollars)
AmeriGas Propane		$	39.3			$	38.6			$	53.8
UGI Utilities			61.2				68.8				40.0
International Propane			39.0				45.8				53.5
Energy Services			—				18.4				6.1
Total		$	139.5			$	171.6			$	153.4

Dividends from AmeriGas Propane in Fiscal 2009 and Fiscal 2007 include the benefit of one-time $0.17 and $0.25 per Common Unit increases in the August 2009 and August 2007 quarterly distributions resulting from Fiscal 2009 and Fiscal 2007 sales of Partnership storage facilities, respectively (see below and Note 4 to Consolidated Financial Statements). Due to greater cash required for capital project expenditures, Energy Services did not pay dividends to UGI in Fiscal 2009 and received capital contributions from UGI totaling $46.8 million.

On April 29, 2009, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.20 per common share or $0.80 per common share on an annual basis. This quarterly dividend reflects an approximate 4% increase from the previous quarterly dividend rate of $0.1925. The new quarterly dividend rate was effective with the dividend paid on July 1, 2009 to shareholders of record on June 15, 2009. On April 28, 2009, the General Partner’s Board of Directors approved a Partnership distribution of $0.67 per Common Unit equal to an annual rate of $2.68 per Common Unit. This quarterly distribution reflects an increase of approximately 5% from the previous quarterly distribution rate of $0.64 per Common Unit. The new quarterly rate was effective with the distribution paid on May 18, 2009 to unitholders of record on May 8, 2009. On July 27, 2009, the General Partner’s Board of Directors approved a distribution of $0.84 per Common Unit payable on August 18, 2009 to unitholders of record on August 10, 2009. This distribution included the regular quarterly distribution of $0.67 per Common Unit and an additional $0.17 per Common Unit reflecting a one-time distribution of a portion of the proceeds from the Partnership’s November 2008 sale of its California storage facility.

Long-term Debt and Credit Facilities

The Company’s debt outstanding at September 30, 2009 totaled $2,296.2 million (including current maturities of long-term debt of $94.5 million) compared to $2,205.5 million of debt outstanding (including current maturities of long-term debt of $81.8 million) at September 30, 2008. Total debt outstanding at September 30, 2009 reflects the issuance of $108 million of UGI Utilities Senior Notes in conjunction with the CPG Acquisition. Total debt outstanding at September 30, 2009 principally consists of $865.6 million of Partnership debt, $622.9 million (€425.6 million) of International Propane debt, $794 million of UGI Utilities’ debt, and $13.7 million of other debt.

Due to the seasonal nature of the Company’s businesses, operating cash flows are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest. AmeriGas Propane and UGI Utilities primarily use bank loans to satisfy their seasonal operating cash flow needs. Energy Services uses its Receivables Facility to satisfy its operating cash flow needs. During Fiscal 2009, Fiscal 2008 and Fiscal 2007, Antargaz generally funded its operating cash flow needs without using its revolving credit facility.

AmeriGas Partners. AmeriGas Partners’ total debt at September 30, 2009 includes long-term debt comprising $779.7 million of AmeriGas Partners’ Senior Notes, $80.0 million of AmeriGas OLP First Mortgage Notes and $5.9 million of other long-term debt. At September 30, 2009, there were no borrowings outstanding under AmeriGas OLP’s revolving credit agreements. In March 2009, AmeriGas OLP repaid $70 million of maturing First Mortgage Notes with cash generated from operations.

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.

In order to provide for increased liquidity principally for cash collateral requirements, on April 17, 2009, AmeriGas OLP entered into a $75 million unsecured revolving credit facility (“2009 AmeriGas Supplemental Credit Agreement”) with three major banks. The 2009 AmeriGas Supplemental Credit Agreement expires on July 1, 2010 and permits AmeriGas OLP to borrow up to $75 million for working capital and general purposes.

There were no borrowings outstanding under the credit agreements at September 30, 2009. Issued and outstanding letters of credit under the Revolving Credit Facility, which reduce the amount available for borrowings, totaled $37.0 million at September 30, 2009. 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 agreements in Fiscal 2009 were $43.8 million and $184.5 million, respectively. The average daily and peak bank loan borrowings outstanding under the AmeriGas OLP Credit Agreement in Fiscal 2008 were $39.1 million and $106.0 million, respectively. The higher peak bank loan borrowings in Fiscal 2009 resulted from the need to fund counterparty cash collateral obligations associated with derivative financial instruments used by the Partnership to manage market price risk associated with fixed sales price commitments to customers. These collateral obligations resulted from the precipitous decline in propane commodity prices that occurred early in Fiscal 2009. At September 30, 2009, the Partnership’s available borrowing capacity under the credit agreements was $238.0 million.

Based upon existing cash balances, cash expected to be generated from operations and borrowings available under AmeriGas OLP’s credit agreements, the Partnership’s management believes that the Partnership will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2010. For a more detailed discussion of the Partnership’s credit facilities, see Note 5 to Consolidated Financial Statements.

International Propane. International Propane’s total debt at September 30, 2009 includes long-term debt principally comprising $556.1 million (€380 million) outstanding under Antargaz’ Senior Facilities term loan and $54.1 million (€37.0 million) outstanding under Flaga’s term loans. International Propane debt outstanding at September 30, 2009 also includes combined borrowings of $9.1 million (€6.2 million) under Flaga’s working capital facilities and $3.6 million (€2.5 million) of other long-term debt.

Antargaz. Antargaz has a five-year, floating rate Senior Facilities Agreement that expires on March 31, 2011. The Senior Facilities Agreement consists of (1) a €380 million variable-rate term loan and (2) a €50 million revolving credit facility. Antargaz 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, 2009 was 3.94%. The Senior Facilities Agreement also includes 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 September 30, 2008 Consolidated Balance Sheet. This borrowing was repaid by Antargaz on October 27, 2008. Excluding this borrowing in September 2008, no other amounts were borrowed under Antargaz’ revolving credit facility during Fiscal 2009 or Fiscal 2008.

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 5 to Consolidated Financial Statements.

Antargaz’ management believes that it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2010 with cash generated from operations, borrowings under its revolving credit facility and guarantees under its letter of credit facility.

Flaga. Flaga has two euro-based, amortizing variable-rate term loans. The principal outstanding on the first term loan was €30 million ($43.9 million) at September 30, 2009. Flaga has effectively fixed the euribor component of its interest rate on this term loan through September 2011 at 3.91% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2009 was 4.28%. The second euro-based variable-rate term loan, executed in August 2009, had an outstanding principal balance of €7 million ($10.2 million) on September 30, 2009. This term loan matures in June 2014. Flaga has effectively fixed the euribor component of its interest rate on this term loan at 2.16% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2009 was 5.03%.

Flaga has two working capital facilities totaling €24 million. Flaga has a multi-currency working capital facility that provides for borrowings and issuances of guarantees totaling €16 million of which €2.1 million ($3.0 million) was outstanding at September 30, 2009. Flaga also has an €8 million euro-denominated working capital facility of which €4.1 million ($6.1 million) was outstanding at September 30, 2009. Issued and outstanding guarantees, which reduce available borrowings under the working capital facilities, totaled €2.7 million ($3.9 million) at September 30, 2009. Amounts outstanding under the working capital facilities are classified as bank loans. During Fiscal 2009 and Fiscal 2008, peak bank loan borrowings totaled €18.6 million and €6.9 million, respectively. Average daily bank loan borrowings during Fiscal 2009 and Fiscal 2008 were €11.5 million and €5.6 million, respectively. For a more detailed discussion of Flaga’s debt, see Note 5 to Consolidated Financial Statements.

Based upon cash generated from operations, borrowings under its working capital facilities and capital contributions from UGI, Flaga’s management believes it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2010.

UGI Utilities. UGI Utilities’ total debt at September 30, 2009 includes long-term debt comprising $383 million of Senior Notes and $257 million of Medium-Term Notes. Total debt outstanding at September 30, 2009 also includes $154 million outstanding under UGI Utilities’ Revolving Credit Agreement.

UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement. This agreement expires in August 2011. Amounts outstanding under the Revolving Credit Agreement are classified as bank loans on the Consolidated Balance Sheets. During Fiscal 2009 and Fiscal 2008, peak bank loan borrowings totaled $312 million and $267 million, respectively. Average daily bank loan borrowings were $180.0 million in Fiscal 2009 and $121.0 million in Fiscal 2008. Revolving Credit Agreement borrowings were greater in Fiscal 2009 due in large part to increases in margin deposits associated with natural gas futures contracts as a result of declines in wholesale natural gas prices. 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.

Based upon cash expected to be generated from Gas Utility and Electric Utility operations and borrowings available under its Revolving Credit Agreement, UGI Utilities’ management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2010. For a more detailed discussion of UGI Utilities’ long-term debt and Revolving Credit Agreement, see Note 5 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 2010, 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. At September 30, 2009, the outstanding balance of ESFC trade receivables was $38.2 million which is net of $31.3 million that was sold to the commercial paper conduit and removed from the balance sheet. During Fiscal 2009 and Fiscal 2008, peak sales of receivables were $139.7 million and $71.0 million, respectively. The greater peak sales in Fiscal 2009 reflect greater cash needed to fund collateral deposits on natural gas NYMEX futures accounts due to the sharp decline in natural gas prices. 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 2010. For a more detailed discussion of the Receivables Facility, see Note 18 to Consolidated Financial Statements.

Cash Flows

Operating Activities. Year-to-year variations in cash flow from operations can be significantly affected by changes in operating working capital especially during periods of volatile energy commodity prices. During Fiscal 2009, commodity prices of LPG and natural gas decreased significantly compared with significant price increases during most of the second half of Fiscal 2008. The Fiscal 2009 decline in such commodity prices resulted in reduced investments in accounts receivable and LPG inventories which had the effect of significantly increasing cash flow from operating activities as further described below. Antargaz and the Partnership ended Fiscal 2009 with no bank loans outstanding and cash balances of $79.0 million and $59.2 million, respectively.

Cash flow provided by operating activities was $665.0 million in Fiscal 2009, $464.4 million in Fiscal 2008 and $456.2 million in Fiscal 2007. Cash flow from operating activities before changes in operating working capital was $611.7 million in Fiscal 2009, $525.3 million in Fiscal 2008 and $518.4 million in Fiscal 2007. The significant increase in Fiscal 2009 cash flow from operating activities before changes in operating working capital reflects the improved operating results of Antargaz and the Partnership as well as the effects of the CPG Acquisition on October 1, 2008. Changes in operating working capital provided (used) operating cash flow of $53.3 million in Fiscal 2009, $(60.9) million in Fiscal 2008 and $(62.2) million in Fiscal 2007. Cash flow from changes in operating working capital principally reflects the impacts of changes in LPG and natural gas prices on cash receipts from customers as reflected in changes in accounts receivable and accrued utility revenues; the timing of purchases and changes in LPG and natural gas prices on our investments in inventories; the timing of natural gas cost recoveries through Gas Utility’s PGC recovery mechanism; and the effects of the timing of payments and changes in purchase price per gallon of LPG and natural gas on accounts payable. Significantly greater Fiscal 2009 cash provided by changes in the Partnership’s and Antargaz’ accounts receivable and inventories principally reflects the effects on net cash receipts from customers and cash expenditures for purchases of inventories resulting from the lower Fiscal 2009 LPG prices. The significant increase in cash used to fund changes in accounts payable in Fiscal 2009 is principally due to the timing of payments and lower purchased prices for natural gas and LPG.

Investing Activities. Investing activity cash flow is principally affected by expenditures for property, plant and equipment; cash paid for acquisitions of businesses; changes in restricted cash balances and proceeds from sales of assets. Net cash flow used in investing activities was $519.9 million in Fiscal 2009, $289.5 million in Fiscal 2008 and $223.8 million in Fiscal 2007. The primary reason for the increase in cash used by investing activities in Fiscal 2009 was business acquisitions, principally the CPG Acquisition, and greater cash expenditures for property, plant and equipment. Fiscal 2009 capital expenditures were higher due in large part to Energy Services’ capital project expenditures, increased Gas Utility capital expenditures associated with CPG Gas, and greater Partnership capital expenditures associated with a system software replacement project. Fiscal 2009 investing activity cash flows also reflect a reduction in restricted cash in natural gas futures brokerage accounts of $63.3 million compared with an increase of $57.5 million in Fiscal 2008. Changes in restricted cash in futures brokerage accounts are the result of the timing of settlement of natural gas futures contracts and changes in natural gas prices. During Fiscal 2009 and Fiscal 2007, the Partnership received $42.4 million and $49.0 million, respectively, in cash proceeds from the sales of propane storage facilities.

Financing Activities. Cash flow used by financing activities was $114.6 million, $180.1 million and $178.5 million in Fiscal 2009, Fiscal 2008 and Fiscal 2007, respectively. Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; net bank loan borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units and issuances of UGI and AmeriGas Partners equity instruments.

Fiscal 2009 issuances of long-term debt includes $108 million of Medium-Term Notes issued by UGI Utilities to finance a portion of the CPG Acquisition and a €7 million ($10.0) term loan issued by Flaga to fund a portion of the ZLH acquisition. During Fiscal 2009, AmeriGas OLP repaid $70 million of maturing First Mortgage Notes using cash generated from operations and Flaga made scheduled repayments of €6 million ($8.4) on its term loan. Changes in bank loans during Fiscal 2009 principally reflect $97 million of net borrowings by UGI Utilities offset in large part by Antargaz’ October 2008 repayment of its €50 million ($70.4 million) revolving credit facility loan borrowed in September 2008.

Capital Expenditures

In the following table, we present capital expenditures (which exclude acquisitions but include capital leases) by our business segments for Fiscal 2009, Fiscal 2008 and Fiscal 2007. We also provide amounts we expect to spend in Fiscal 2010. We expect to finance Fiscal 2010 capital expenditures principally from cash generated by operations, borrowings under credit facilities and cash on hand.

Year Ended September 30,		2010				2009				2008				2007
(Millions of dollars)		(estimate)
AmeriGas Propane		$	82.0			$	78.7			$	62.8			$	73.8
International Propane			78.6				76.3				75.0				64.3
Gas Utility			71.1				73.8				58.3				66.2
Electric Utility			12.9				5.3				6.0				7.2
Energy Services			106.6				66.2				30.7				10.7
Other			3.0				1.4				1.4				0.9
		$	354.2			$	301.7			$	234.2			$	223.1

The increases in Energy Services’ capital expenditures in Fiscal 2008, Fiscal 2009 and Fiscal 2010 principally reflect capital expenditures related to electric generation, LNG storage and peaking assets projects. The greater Electric Utility capital expenditures in Fiscal 2010 reflect increased electricity transmission capacity associated with additions to electric generating capacity in its service territory. Energy Services’ Fiscal 2009 capital expenditures were financed in large part by capital contributions from UGI. Energy Services’ expenditures in Fiscal 2010 principally relating to its Hunlock Station repowering project and an LNG storage expansion project are expected to be financed from capital contributions from UGI and bank borrowings. In addition, during Fiscal 2011 and Fiscal 2012 Energy Services expects to spend a total of approximately $90 million associated with these projects which amount is expected to be similarly financed. AmeriGas Propane capital expenditures in Fiscal 2009 and Fiscal 2010 include expenditures associated with a system software replacement.

Contractual Cash Obligations and Commitments

The Company has contractual cash obligations that extend beyond Fiscal 2009. 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, 2009:

		Payments Due by Period
						Fiscal				Fiscal				Fiscal
(Millions of dollars)		Total				2010				2011-2012				2013-2014				Thereafter
Long-term debt (a)		$	2,133.1			$	94.5			$	654.5			$	139.7			$	1,244.4
Interest on long-term fixed rate debt (b)			805.4				126.6				200.8				172.2				305.8
Operating leases			230.5				61.5				86.0				49.8				33.2
AmeriGas Propane supply contracts			50.5				50.5				—				—				—
International Propane supply contracts			238.9				238.9				—				—				—
Energy Services supply contracts			545.2				436.4				108.8				—				—
Gas Utility and Electric Utility supply, storage and transportation contracts			558.0				218.9				182.7				101.0				55.4
Derivative financial instruments (c)			31.1				25.4				5.7				—				—
Other purchase obligations (d)			48.3				43.6				4.7				—				—
Total		$	4,641.0			$	1,296.3			$	1,243.2			$	462.7			$	1,638.8

Components of other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2009 principally comprise refundable tank and cylinder deposits (as further described in Note 2 to Consolidated Financial Statements under the caption “Refundable Tank and Cylinder Deposits”); litigation, property and casualty liabilities and obligations under environmental remediation agreements (see Note 15); pension and other post-employment benefit liabilities recorded in accordance with accounting guidance relating to employee retirement plans (see Note 7); and liabilities associated with executive compensation plans (see Note 13). 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. In addition, we have committed to invest over the next several years a total of up to $25 million in a limited partnership that will focus on investments in the alternative energy sector.

Significant Acquisitions and Dispositions

On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL Gas Utilities Corporation (now named UGI Central Penn Gas, Inc., “CPG”), the natural gas distribution utility of PPL (the “CPG Acquisition”), for cash consideration of $303.0 million less a final working capital adjustment of $9.7 million. Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central Penn, LLC, “CPP”), its retail propane distributor, sold its assets to AmeriGas OLP for cash consideration of $33.6 million less a final working capital adjustment of $1.4 million (the “Penn Fuels Acquisition”). CPG distributes natural gas to approximately 76,000 customers in eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in portions of one Maryland county. CPP sold propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition with a combination of $120 million cash contributed by UGI on September 25, 2008, proceeds from the issuance of $108 million principal amount of 6.375% Senior Notes due 2013 and approximately $75.0 million of borrowings under UGI Utilities’ Revolving Credit Agreement. AmeriGas OLP funded the acquisition of the assets of CPP with borrowings under the AmeriGas Credit Agreement, and UGI Utilities used the $33.6 million of cash proceeds from the sale of the assets of CPP to reduce its revolving credit agreement borrowings.

On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated above-ground LPG storage facility located on leased property in California for net cash proceeds of $42.4 million. The Company recorded an after-tax gain on the sale of $10.4 million or $0.10 per diluted share.

On January 29, 2009, Flaga purchased the 50% equity interest in ZLH it did not already own from its joint-venture partner, Progas GmbH & Co. KG (“Progas”), pursuant to a purchase agreement dated December 18, 2008. ZLH distributes LPG in the Czech Republic, Hungary, Poland, Slovakia and Romania. The cash purchase price for the 50% equity interest was not material.

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. 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. In July 2008, France’s Autorité de la concurrence (“Competition Authority”) interviewed Mr. Varagne, as President of Antargaz and President of the industry association, Comité Français du Butane et du Propane, about competitive practices in the LPG cylinder market in France.

On July 21, 2009, Antargaz received a Statement of Objections from the Competition Authority with respect to the investigation of Antargaz by the DGCCRF. A Statement of Objections (“Statement”) is part of French competition proceedings and generally follows an investigation under French competition laws. The Statement sets forth the Competition Authority’s findings; it is not a judgment or final decision. The Statement alleges that Antargaz engaged in certain anti-competitive practices in violation of French and European Union civil competition laws related to the cylinder market during the period from 1999 through 2004. The alleged violations occurred principally during periods prior to March 31, 2004, when UGI first obtained a controlling interest in Antargaz.

We have completed our review of the Statement of Objections and the related evidence and filed our written response with the Competition Authority on October 21, 2009. The Competition Authority will undertake a review of Antargaz’ response and begin preparation of its final pleading on the claims. This process is anticipated to take several months and Antargaz will have the opportunity to prepare a response to the Competition Authority’s final pleading. Based on an assessment of the information contained in the Statement, during the quarter ended June 30, 2009 we recorded a provision of $10.0 million (€7.1 million) related to this matter which amount is reflected in other income, net on the Fiscal 2009 Consolidated Statement of Income. The final resolution could result in payment of an amount significantly different from the amount we have recorded. We are unable to predict the timing of the final resolution of this matter (see Note 15 to the Consolidated Financial Statements).

Pension Plans

As of September 30, 2009, we sponsor two defined benefit pension plans (“Pension Plans”) for employees hired prior to January 1, 2009 of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans the plans’ assets and benefit obligations of which are not material.

Effective December 31, 2008, we merged two of our domestic defined benefit pension plans. As a result of the merger, we were required under U.S. generally accepted accounting principles (“GAAP”) to remeasure the combined plan’s assets and benefit obligations as of December 31, 2008. As a result of the remeasurement, Fiscal 2009 pension expense increased approximately $4.2 million for the period subsequent to the remeasurement due to the amortization of actuarial losses resulting from the general decline in the financial markets during Fiscal 2008 and Fiscal 2009 and a lower discount rate. The fair value of Pension Plans’ assets totaled $276.4 million and $241.0 million at September 30, 2009 and 2008, respectively. At September 30, 2009 and 2008, the underfunded position of Pension Plans, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension Plans’ assets, was $145.6 million and $59.6 million, respectively.

We believe we are in compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations. We anticipate that we will be required to make contributions to the Pension Plans during Fiscal 2010 but we do not expect such contributions to be material. Pre-tax pension costs associated with Pension Plans in Fiscal 2009 was $8.1 million. Pension cost associated with Pension Plans in Fiscal 2010 is expected to be approximately $11.5 million.

GAAP guidance associated with pension and other postretirement plans generally requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and other postretirement benefit plans with current year changes recognized in shareholders’ equity unless such amounts are subject to regulatory recovery. In accordance with this guidance, through September 30, 2009 we have recorded cumulative after-tax charges to Common Stockholders’ Equity of $81.5 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 Note 7 to Consolidated Financial Statements.

Related Party Transactions

During Fiscal 2009, Fiscal 2008 and Fiscal 2007, we did not enter into any related-party transactions that had a material effect on our financial condition, results of operations or cash flows.

Off-Balance Sheet Arrangements

UGI primarily enters into guarantee arrangements on behalf of our consolidated subsidiaries. These arrangements are not subject to the recognition and measurement guidance relating to guarantees under GAAP.

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

Gas Utility

On January 28, 2009, PNG and CPG filed separate requests with the PUC to increase base operating revenues by $38.1 million annually for PNG and $19.6 million annually for CPG to fund system improvements and operations necessary to maintain safe and reliable natural gas service and energy assistance for low income customers as well as energy conservation programs for all customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on agreements with the opposing parties regarding the requested base operating revenue increases. On August 27, 2009, the PUC approved the settlement agreements which resulted in a $19.8 million base operating revenue increase for PNG Gas and a $10.0 million base operating revenue increase for CPG Gas. The increases became effective August 28, 2009 and did not have a material effect on Fiscal 2009 results.

Electric Utility

As a result of Pennsylvania’s ECC Act, all of Electric Utility’s customers are permitted to acquire their electricity from entities other than Electric Utility. Electric Utility remains the POLR for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006.

In accordance with the POLR Settlement, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. Consistent with the terms of the POLR Settlement, Electric Utility increased its POLR rates effective January 1, 2009, which increased the average cost to a residential heating customer by approximately 1.5% over such costs in effect during calendar year 2008. Effective January 1, 2008, Electric Utility increased its POLR rates which increased the average cost to a residential heating customer by approximately 5.5% over such costs in effect during calendar year 2007. Effective January 1, 2007, Electric Utility increased the average cost to a residential heating customer by approximately 35% over such costs in effect during calendar year 2006.

On July 17, 2008, the PUC approved Electric Utility’s default service procurement, implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with the PUC’s default service regulations. These plans do not affect Electric Utility’s existing POLR settlement effective through December 31, 2009. The approved plans specify how Electric Utility will solicit and acquire default service supplies for residential customers for the period January 1, 2010 through May 31, 2014, and for commercial and industrial customers for the period January 1, 2010 through May 31, 2011 (collectively, the “Settlement Term”). UGI Utilities filed a rate plan on August 29, 2008 for the Settlement Term. On January 22, 2009, the PUC approved a settlement of the rate filing that provides for Electric Utility to fully recover its default service costs. On October 1, 2009, UGI Utilities filed a default service plan to establish procurement rules applicable to the period after May 31, 2011 for its commercial and industrial customers.

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. This will result in a reduction in Electric Utility’s Fiscal 2010 operating income.

Manufactured Gas Plants

UGI Utilities

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the DEP requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (“PNG-COA”). The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 million and $1.1 million, respectively, in any calendar year. The CPG-COA terminates at the end of 2011 for the MGP Properties and at the end of 2013 for well plugging activities. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At September 30, 2009, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $25.0 million. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets totaling $25.0 million.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility.

UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. At September 30, 2009 and 2008, neither UGI Gas’ undiscounted nor its accrued liability for environmental investigation and cleanup costs was material.

UGI Utilities has been notified of several sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties are investigating the extent of environmental contamination or performing environmental remediation. UGI Utilities is currently litigating three claims against it relating to out-of-state sites.

Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.

For additional information on the MGP sites outside of Pennsylvania currently subject to third-party claims or litigation, see Note 15 to Consolidated Financial Statements.

AmeriGas OLP

By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in Saranac Lake, New York on its Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by DEC disclosed contamination related to former MGP operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The Partnership has researched the history of the site and its ownership interest in the site. The Partnership has reviewed the preliminary site characterization study prepared by the DEC, the extent of contamination and the possible existence of other potentially responsible parties. The Partnership has communicated the results of its research to DEC and is awaiting a response before doing any additional investigation. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

We cannot predict with certainty the final results of any of the MGP actions described above. However, it is reasonably possible that some of them could be resolved unfavorably to us and result in losses in excess of recorded amounts. We are unable to estimate any possible losses in excess of recorded amounts. Although we currently believe, after consultation with counsel, that damages or settlements, if any, recovered by the plaintiffs in such claims or actions will not have a material adverse effect on our financial position, damages or settlements could be material to our operating results or cash flows in future periods depending on the nature and timing of future developments with respect to these matters and the amounts of future operating results and cash flows.

Market Risk Disclosures

Our primary market risk exposures are (1) commodity price risk; (2) interest rate risk; and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.

Commodity Price Risk

The risk associated with fluctuations in the prices the Partnership and our International Propane operations pay for LPG is principally a result of market forces reflecting changes in supply and demand for propane and other energy commodities. Their profitability is sensitive to changes in LPG supply costs. Increases in supply costs are generally passed on to customers. The Partnership and International Propane may not, however, always be able to pass through product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements, and over-the-counter derivative commodity instruments including price swap and option contracts. In addition, Antargaz hedges a portion of its future U.S. dollar denominated LPG product purchases through the use of forward foreign exchange contracts. Antargaz may from time-to-time 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 LPG purchases. Over-the-counter derivative commodity instruments utilized to hedge forecasted purchases of propane are generally settled at expiration of the contract.

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for a periodic adjustment for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments comprising futures contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism.

Electric Utility purchases its electric power needs from electricity suppliers under fixed-price energy 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. Electric Utility’s fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 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. As previously mentioned, on January 22, 2009, the PUC approved a settlement of a rate filing that provides for Electric Utility to fully recover its default service costs beginning January 1, 2010. 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 over-the-counter and exchange-traded natural gas futures contracts or enters into fixed-price supply arrangements. Energy Services’ exchange-traded natural gas and electricity futures contracts are traded on the NYMEX and have nominal credit risk. 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. Energy Services has entered into and may continue to enter into fixed-price sales agreements for a portion of its propane sales. In order to manage the market price risk relating to substantially all of its fixed-price sales contracts for propane, Energy Services enters into price swap and option contracts.

UGID has entered into fixed-price sales agreements for a portion of the electricity expected to be generated by its electric generation assets. In the event that these generation assets would not be able to produce all of the electricity needed to supply electricity under these agreements, UGID would be required to purchase such electricity on the spot market or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact the Company’s results.

Because our business units have product cost management programs with contracts that include collateral and margin deposit requirement provisions, rapid declines in natural gas and LPG product costs can require our business units to post cash collateral with counterparties or make margin deposits in brokerage accounts.

Electric Utility obtains financial transmission rights (“FTRs”) through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, by purchases at monthly PJM auctions. Energy Services purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. 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. Although FTRs are economically effective as hedges of congestion charges, they do not currently qualify for hedge accounting treatment.

Interest Rate Risk

We have both fixed-rate and variable-rate debt. Changes in interest rates impact the cash flows of variable-rate debt but generally do not impact their fair value. Conversely, changes in interest rates impact the fair value of fixed-rate debt but do not impact their cash flows.

Our variable-rate debt includes borrowings under AmeriGas OLP’s credit agreements, UGI Utilities’ Revolving Credit Agreement and a substantial portion of Antargaz’ and Flaga’s debt. These debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has effectively fixed the underlying euribor interest rate on its variable-rate debt through March 2011 and Flaga has fixed the underlying euribor interest rate on a substantial portion of its term loans through their scheduled maturity dates through the use of interest rate swaps. At September 30, 2009 and 2008, combined borrowings outstanding under these agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled approximately $163.1 million and $137.8 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 2009 and Fiscal 2008, an increase in short-term interest rates of 100 basis points (1%) would have increased our Fiscal 2009 and Fiscal 2008 interest expense by $2.3 million and $1.9 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 $91.0 million and $74.0 million at September 30, 2009 and 2008, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $100.7 million and $81.4 million at September 30, 2009 and 2008, respectively.

Our long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. 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, from time to time we enter into interest rate protection agreements.

Foreign Currency Exchange Rate Risk

Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign-denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Realized gains or losses remain in accumulated other comprehensive income until such foreign operations are liquidated. At September 30, 2009, the fair value of unsettled net investment hedges was a loss of $5.7 million, which is included in foreign currency exchange rate risk in the table below. 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 $61.9 million, which amount would be reflected in other comprehensive income.

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise major energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. At September 30, 2009 and 2008, restricted cash in brokerage accounts totaled $7.0 million and $70.3 million, respectively.

The following table summarizes the fair values of unsettled market risk sensitive derivative instruments assets and (liabilities) held at September 30, 2009 and 2008. 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 LPG and gasoline; (2) the market price of natural gas; (3) the market price of electricity and electricity transmission congestion changes; (4) the three-month LIBOR and the three- and nine-month Euribor and; (5) the value of the euro versus the U.S. dollar. The fair value of Gas Utility’s exchange-traded natural gas futures contracts comprising losses $23.3 million at September 30, 2008 are excluded from the table below because any associated net gains or losses are included in Gas Utility’s PGC recovery mechanism. There were no such contracts at September 30, 2009.

		Asset (Liability)
						Change in
		Fair Value				Fair Value
(Millions of dollars)
September 30, 2009:
LPG commodity price risk		$	12.2			$	(14.4	)
FTR price risk			2.9				(0.3	)
Natural gas commodity price risk			(0.4	)			(13.6	)
Gasoline price risk			0.1				(0.2	)
Electricity commodity price risk			(3.4	)			(1.7	)
Interest rate risk			(34.4	)			(6.0	)
Foreign currency exchange rate risk			(5.7	)			(18.2	)
September 30, 2008:
LPG commodity price risk		$	(53.7	)		$	(29.2	)
FTR price risk			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	)

Because our derivative instruments, other than FTRs and gasoline futures contracts, generally qualify as hedges under GAAP, we expect that changes in the fair value of derivative instruments used to manage commodity, currency or interest rate market risk would be substantially offset by gains or losses on the associated anticipated transactions.

Critical Accounting Policies and Estimates

The preparation of financial statements and related disclosures in compliance with 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 and CPG Gas owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with accounting principles generally accepted in the United States of America, the Company establishes reserves for pending claims and legal actions or environmental remediation obligations when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Reasonable estimates involve management judgments based on a broad range of information and prior experience. These judgments are reviewed quarterly as more information is received and the amounts reserved are updated as necessary. Such estimated reserves may differ materially from the actual liability and such reserves may change materially as more information becomes available and estimated reserves are adjusted.

Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to regulation by the PUC. In accordance with accounting guidance associated with rate-regulated entities, we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. As of September 30, 2009, our regulatory assets totaled $141.5 million. See Notes 2 and 8 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, 2009, our net property, plant and equipment totaled $2,903.6 million and we recorded depreciation expense of $180.2 million during Fiscal 2009. As of September 30, 2009, our net intangible assets other than goodwill totaled $165.5 million and we recorded intangible amortization expense of $18.4 million during Fiscal 2009.

Purchase Price Allocations. From time to time, the Company enters into material business combinations. In accordance with accounting guidance associated with business combinations, the purchase price is allocated to the various assets acquired and liabilities assumed at their estimated fair value. Fair values of assets acquired and liabilities assumed are based upon available information and we may involve an independent third party to perform appraisals. Estimating fair values can be complex and subject to significant business judgment and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, if necessary, up to one year from the acquisition date to finalize the purchase price allocation.

Impairment of Goodwill. Certain of the Company’s business units have goodwill resulting from purchase business combinations. In accordance with GAAP, each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, management must determine the reporting unit’s fair value using quoted market prices or, in the absence of quoted market prices, valuation techniques which use discounted estimates of future cash flows to be generated by the reporting unit. These cash flow estimates involve management judgments based on a broad range of information and historical results. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill which would adversely impact our results of operations. As of September 30, 2009, our goodwill totaled $1,582.3 million. We did not record any impairments of goodwill in Fiscal 2009, Fiscal 2008 or Fiscal 2007.

Pension Plan Assumptions. The cost of providing benefits under our Pension Plans is dependent on historical information such as employee age, length of service, level of compensation and the actual rate of return on plan assets. In addition, certain assumptions relating to the future are used to determine pension expense including the discount rate applied to benefit obligations, the expected rate of return on plan assets and the rate of compensation increase, among others. Assets of the Pension Plans are held in trust and consist principally of equity and fixed income mutual funds. Changes in plan assumptions as well as fluctuations in actual equity or fixed income market returns could have a material impact on future pension costs. We believe the two most critical assumptions are (1) the expected rate of return on plan assets and (2) the discount rate. A decrease in the expected rate of return on Pension Plans assets of 50 basis points to a rate of 8.0% would result in an increase in pre-tax pension cost of approximately $1.5 million in Fiscal 2010. A decrease in the discount rate of 50 basis points to a rate of 5.0% would result in an increase in pre-tax pension cost of approximately $2.4 million in Fiscal 2010.

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. Prior to Fiscal 2008, we established liabilities for tax-related contingencies when we believed it was probable that a liability had been incurred and the amount could be reasonably estimated. In Fiscal 2008, we adopted new guidance which establishes standards for recognition and measurement of positions taken or expected to be taken by an entity in its tax returns. Positions taken by an entity in its tax returns must satisfy a more-likely-than-not recognition threshold assuming the position will be examined by tax authorities with full knowledge of relevant information. We use assumptions, judgments and estimates to determine our current provision for income taxes. We also use assumptions, judgments and estimates to determine our deferred tax assets and liabilities and any valuation allowance to be recorded against a deferred tax asset. Our assumptions, judgments and estimates relative to the current provision for income tax give consideration to current tax laws, our interpretation of current tax laws and possible outcomes of current and future audits conducted by foreign and domestic tax authorities. Changes in tax law or our interpretation of such and the resolution of current and future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. Our assumptions, judgments and estimates relative to the amount of deferred income taxes take into account estimates of the amount of future taxable income. Actual taxable income or future estimates of taxable income could render our current assumptions, judgments and estimates inaccurate. Changes in the assumptions, judgments and estimates mentioned above could cause our actual income tax obligations to differ significantly from our estimates. As of September 30, 2009, our net deferred tax liabilities totaled $470.4 million.

Newly Adopted and Recently Issued Accounting Pronouncements

See Note 3 to Consolidated Financial Statements for a discussion of the effects of accounting guidance we adopted in Fiscal 2009, Fiscal 2008 and Fiscal 2007 as well as recently issued accounting guidance not yet adopted.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

“Quantitative and Qualitative Disclosures About Market Risk” are contained in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations under the caption “Market Risk Disclosures” and are incorporated herein by reference.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Annual Report on Internal Control Over Financial Reporting and the financial statements and financial statement schedules referred to in the Index contained on page F-2 of this Report are incorporated herein by reference.

ITEM 9.		CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

(a)

The Company’s 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 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 December 17, 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 Fiscal 2009 with respect to compensation plans under which our equity securities are authorized for issuance.

										Number of securities
		Number of securities to be				Weighted average				remaining available for future
		issued upon exercise of				exercise price of				issuance under equity
		outstanding options,				outstanding options,				compensation plans
		warrants and rights				warrants and rights				(excluding securities reflected
Plan category		(a)				(b)				in column (a)) (c)
Equity compensation plans approved by security holders			7,287,668	(1)			$23.07
			878,427	(2)			$0				5,576,930
Equity compensation plans not approved by security holders			213,825	(3)			$11.78				0
Total			8,379,920				$22.74	(4)			5,576,930