UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTIONS 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2011

Commission file number 1-11071

UGI CORPORATION

Pennsylvania		23-2668356
(State or Other Jurisdiction of		(I.R.S. Employer Identification No.)
Incorporation or Organization)

460 North Gulph Road, King of Prussia, PA 19406
(Address of Principal Executive Offices) (Zip Code)

(610) 337-1000
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

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

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

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

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

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

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

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

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

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

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

The aggregate market value of UGI Corporation Common Stock held by non-affiliates of the registrant on March 31, 2011 was $3,670,732,242.

At November 14, 2011 there were 115,458,302 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 19, 2012 are incorporated by reference into Part III of this Form 10-K.

 

 

TABLE OF CONTENTS

		Page
Forward-Looking Information			2
PART I:			2
Items 1. and 2. Business and Properties			2
Item 1A. Risk Factors			19
Item 1B. Unresolved Staff Comments			25
Item 3. Legal Proceedings			25
Item 4. (Removed and Reserved)			25
PART II:			26
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			26
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			57
Item 8. Financial Statements and Supplementary Data			58
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			58
Item 9A. Controls and Procedures			58
Item 9B. Other Information			58
PART III:			59
Item 10. Directors, Executive Officers and Corporate Governance			59
Item 11. Executive Compensation			59
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			59
Item 13. Certain Relationships and Related Transactions and Director Independence			59
Item 14. Principal Accounting Fees and Services			59
PART IV:			62
Item 15. Exhibits and Financial Statement Schedules			62
Signatures			71
Index to Financial Statements and Financial Statement Schedules			F-2
Exhibit 10.2
Exhibit 10.25
Exhibit 10.27
Exhibit 10.28
Exhibit 10.29
Exhibit 10.30
Exhibit 10.31
Exhibit 10.32
Exhibit 10.33
Exhibit 10.34
Exhibit 10.35
Exhibit 10.47
Exhibit 21
Exhibit 23
Exhibit 31.1
Exhibit 31.2
Exhibit 32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other liquefied petroleum gases, oil, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax, consumer protection 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 and retain current customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) large customer, counter-party or supplier defaults; (12) liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and liquefied petroleum gases; (13) political, regulatory and economic conditions in the United States and in foreign countries, including foreign currency exchange rate fluctuations, particularly the euro; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (15) changes in commodity market prices resulting in significantly higher cash collateral requirements; (16) reduced distributions from subsidiaries; (17) the timing of development of Marcellus Shale gas production; (18) the timing and success of our acquisitions, commercial initiatives and investments to grow our businesses; and (19) our ability to successfully integrate acquired businesses and achieve anticipated synergies.

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

PART I:

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

CORPORATE OVERVIEW

UGI Corporation is a holding company that, through subsidiaries, distributes, stores, transports 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; an owner and manager of midstream assets; and a regional provider of heating, ventilation, air conditioning, refrigeration and electrical contracting services. Our subsidiaries and affiliates operate principally in the following six business segments:

	•		AmeriGas Propane
	•		International Propane — Antargaz
	•		International Propane — Flaga and Other
	•		Gas Utility
	•		Electric Utility
	•		Midstream & Marketing

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 and they trade on the New York Stock Exchange under the symbol “APU.” We have an effective 44% ownership interest in the Partnership; the remaining interest is publicly held. See Note 1 to Consolidated Financial Statements.

The International Propane — Antargaz segment consists of the LPG distribution business of our wholly owned subsidiary Antargaz, a French société anonyme (“Antargaz”). Antargaz is one of the largest retail distributors of LPG in France.

The International Propane — Flaga and Other segment consists of the LPG distribution businesses of Flaga GmbH, an Austrian corporation, and its subsidiaries (collectively, “Flaga”), and China Gas Partners, L.P., a majority-owned Delaware limited partnership. Flaga is the largest retail LPG distributor in Austria and Denmark and one of the largest in the Czech Republic, Slovakia and Hungary. Flaga also distributes LPG in Poland, Romania and Switzerland. China Gas Partners is an LPG distributor in the Nantong region of China. We recently expanded our international propane operations in Europe. See “Corporate Overview — Business Strategy.”

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 575,000 customers in eastern and central Pennsylvania and several hundred customers in portions of one Maryland county. UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” The Electric Utility segment (“Electric Utility”) consists of the regulated electric distribution business of UGI Utilities, serving approximately 62,000 customers in northeastern Pennsylvania. Gas Utility is regulated by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to its several hundred customers in Maryland, the Maryland Public Service Commission. Electric Utility is regulated by the PUC.

The Midstream & Marketing segment consists of energy-related businesses conducted by UGI Energy Services, Inc. and a number of its subsidiaries (collectively, “Energy Services”). These businesses include (i) energy marketing in the eastern region of the United States, (ii) generating electricity in Pennsylvania, including through solar and landfill gas facilities, (iii) operating and owning a natural gas liquefaction, storage and vaporization facility and propane-air mixing assets, (iv) managing natural gas pipeline and storage contracts, and (v) developing, owning and operating pipelines, gathering infrastructure and gas storage facilities in the Marcellus Shale region of Pennsylvania.

Through subsidiaries, UGI Corporation also operates and owns heating, ventilation, air conditioning, refrigeration and electrical contracting service businesses serving customers in the Mid-Atlantic region.

Business Strategy

Our business strategy is to grow the Company by focusing on our core competencies of distributing, storing, transporting and marketing 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 2011, we completed a number of transactions in pursuit of this strategy and moved forward on a number of larger internally generated capital projects, including infrastructure projects to support the development of natural gas in the Marcellus Shale region of Pennsylvania and renewable energy projects. A few of these transactions and projects are described below.

In late Fiscal 2010 and early Fiscal 2011, we acquired LPG distribution businesses in Denmark, Hungary and Poland, which significantly increased Flaga’s sales volumes. In October of 2011, we purchased Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Subsequent Events” and Note 22 to Consolidated Financial Statements.

On October 17, 2011, AmeriGas Partners announced that it had reached a definitive agreement to acquire the propane operations of Energy Transfer Partners, L.P. (“Energy Transfer”). Energy Transfer conducts its propane operations in 41 states through its subsidiaries, Heritage Operating, L.P. and Titan Energy Partners, L.P. (collectively, “Heritage Propane”). According to LP-Gas Magazine rankings, Heritage Propane is the third largest retail propane distributor in the United States delivering over 500 million gallons to more than one million customers. The acquisition is expected to close by March 31, 2012. The consummation of the acquisition is subject to a number of conditions, including approval under the Hart-Scott-Rodino Act and AmeriGas Partners obtaining debt financing. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Subsequent Events” and Note 22 to Consolidated Financial Statements.

During Fiscal 2011, a subsidiary of Energy Services acquired underground natural gas storage facilities formerly owned by CPG and received approval from the Federal Energy Regulatory Commission (“FERC”) to sell storage services at market-based rates. The storage facilities are located in the Marcellus Shale region of Pennsylvania. Additionally, in October of 2011, Energy Services completed a gathering project to transport locally produced natural gas from a pipeline in the Marcellus Shale region of Pennsylvania to an interstate pipeline.

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 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) 337-7000. 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 2011” and “Fiscal 2010” refer to the fiscal years ended September 30, 2011 and September 30, 2010, respectively.

The Company’s corporate website can be found at www.ugicorp.com. Information on our website is not intended to be incorporated into this report. 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 Exchange Act, including its Annual Reports on Form 10-K, its Quarterly Reports on Form 10-Q and its Current Reports on Form 8-K. The Company’s Principles of Corporate Governance, Code of Ethics for the Chief Executive Officer and Senior Financial Officers, Code of Business Conduct and Ethics for Directors, Officers and Employees, and charters of the Corporate Governance, Audit and Compensation and Management Development Committees of the Board of Directors are also available on the Company’s website, under the caption “Investor Relations and Corporate Governance — Corporate Governance.” All of these documents are also available free of charge by writing to Hugh J. Gallagher, 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 nearly 1,200 propane distribution locations. In addition to distributing propane, the Partnership also sells, installs and services propane appliances, including heating systems. Typically, the Partnership’s locations are in suburban and rural areas where natural gas is not readily available. Our district offices generally consist of a business 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, British Columbia and Quebec.

The Partnership sells propane primarily to residential, commercial/industrial, motor fuel, agricultural and wholesale customers. The Partnership distributed approximately one billion gallons of propane in Fiscal 2011. Approximately 88% of the Partnership’s Fiscal 2011 sales (based on gallons sold) were to retail accounts and approximately 12% were to wholesale customers. Sales to residential customers in Fiscal 2011 represented approximately 39% of retail gallons sold; commercial/industrial customers 38%; motor fuel customers 14%; and agricultural customers 4%. Transport gallons, which are large-scale deliveries to retail customers other than residential, accounted for 5% of Fiscal 2011 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, 2011, ACE cylinders were available at over 38,000 retail locations throughout the United States. Sales of our ACE cylinders to retailers are included in commercial/industrial sales. The ACE program enables consumers to purchase propane cylinders or exchange their empty propane 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 cylinders directly at the retailer’s location.

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

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

Propane Supply and Storage

The Partnership has over 250 domestic and international sources of supply, including the spot market. Supplies of propane from the Partnership’s sources historically have been readily available. During Fiscal 2011, approximately 90% of the Partnership’s propane supply was purchased under supply agreements with terms of 1 to 3 years. The availability of propane supply is dependent upon, among other things, the severity of winter weather, the price and availability of competing fuels such as natural gas and crude oil, and the amount and availability of imported supply. Although no assurance can be given that supplies of propane will be readily available in the future, management currently expects to be able to secure adequate supplies during fiscal year 2012. 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 adversely affected. BP Products North America Inc., Enterprise Products Partners L.P. and Targa Midstream Services LP supplied approximately 43% of the Partnership’s Fiscal 2011 propane supply. No other single supplier provided more than 10% of the Partnership’s total propane supply in Fiscal 2011. In certain areas, however, a single supplier provides more than 50% of the Partnership’s requirements. Disruptions in supply in these areas could also have an adverse impact on the Partnership’s margins.

The Partnership’s supply contracts typically provide for pricing based upon (i) index formulas using the current prices established at a major storage point such as Mont Belvieu, Texas, or Conway, Kansas, or (ii) posted prices at the time of delivery. In addition, some agreements provide maximum and minimum seasonal purchase volume guidelines. The percentage of contract purchases, and the amount of supply contracted for at fixed prices, will vary from year to year as determined by the General Partner. The Partnership uses a number of interstate pipelines, as well as railroad tank cars, delivery trucks and barges, to transport propane from suppliers to storage and distribution facilities. The Partnership stores propane at various storage facilities and terminals located in strategic areas across the United States.

Because the Partnership’s profitability is sensitive to changes in wholesale propane costs, the Partnership generally seeks to pass on increases in the cost of propane to customers. There is no assurance, however, that the Partnership will always be able to pass on product cost increases fully, particularly when product costs rise rapidly. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude oil and natural gas, or other unforeseen events. The General Partner has adopted supply acquisition and product cost risk management practices to reduce the effect of volatility on selling prices. These practices currently include the use of summer storage, forward purchases and derivative commodity instruments, such as options and propane price swaps. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures.”

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 the lower cost of 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, diesel fuel, electric batteries, fuel cells and, in certain applications, liquefied natural gas and compressed natural gas. 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.

Volume in the retail propane industry has been slowly declining for several years, and no or modest negative growth in total demand is foreseen in the next several years. Therefore, the Partnership’s ability to grow within the industry is dependent on its ability to acquire other retail distributors and to achieve internal growth, which includes expansion of the ACE program and the Strategic Accounts program (through which the Partnership encourages multi-location propane users to enter into a supply agreement with it rather than with many 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 2011, the Partnership’s retail propane sales totaled approximately 874 million gallons. Based on the most recent annual survey by the American Petroleum Institute, 2009 domestic retail propane sales (annual sales for other than chemical uses) in the United States totaled approximately 9.1 billion gallons. Based on LP-GAS magazine rankings, 2009 sales volume of the ten largest propane companies (including AmeriGas Partners) represented approximately 41% of domestic retail sales.

Properties

As of September 30, 2011, the Partnership owned approximately 500 of its district offices throughout the country. 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, 2011, the Partnership operated a transportation fleet with the following assets:

Approximate Quantity & Equipment Type						% Owned				% Leased
	1,370			Trailers			87	%			13	%
	310			Tractors			11	%			89	%
	350			Railroad tank cars			0	%			100	%
	2,540			Bobtail trucks			14	%			86	%
	300			Rack trucks			12	%			88	%
	2,190			Service and delivery trucks			16	%			84	%

Other assets owned at September 30, 2011 included approximately 793,000 stationary storage tanks with typical capacities ranging from 121 to 2,000 gallons and approximately 3.4 million portable propane cylinders with typical capacities of 1 to 120 gallons. The Partnership also owned approximately 4,800 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 in the U.S. UGI and the General Partner each have the option to terminate its respective license agreement (on 12 months prior notice in the case of UGI), without penalty, if the General Partner is removed as general partner of the Partnership other than for cause. If the General Partner ceases to serve as the general partner of the Partnership for cause, the General Partner has the option to terminate its license agreement upon payment of a fee to UGI equal to the fair market value of the licensed trade names. UGI has a similar termination option; however, UGI must provide 12 months prior notice in addition to paying the fee to the General Partner.

Seasonality

Because many customers use propane for heating purposes, the Partnership’s retail sales volume is seasonal. Approximately 65% to 70% of the Partnership’s retail sales volume occurs, and substantially all of the Partnership’s operating income is earned, during the peak heating season from October through March. As a result of this seasonality, sales are higher in the Partnership’s first and second fiscal quarters (October 1 through March 31). Cash receipts are generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the winter heating season.

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

Government Regulation

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

All states in which the Partnership operates have adopted fire safety codes that regulate the storage and distribution of propane. In some states these laws are administered by state agencies, and in others they are administered on a municipal level. The Partnership conducts training programs to help ensure that its operations are in compliance with applicable governmental regulations. With respect to general operations, National Fire Protection Association (“NFPA”) Pamphlets No. 54 and No. 58, which establish a set of rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted by all states in which the Partnership operates. Management believes that the policies and procedures currently in effect at all of its facilities for the handling, storage and distribution of propane are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safety laws.

With respect to the transportation of propane by truck, the Partnership is subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the United States Department of Transportation (“DOT”). The Natural Gas Safety Act of 1968 required the DOT to develop and enforce minimum safety regulations for the transportation of gases by pipeline. The DOT’s pipeline safety regulations apply to, among other things, a propane gas system which supplies 10 or more residential customers or 2 or more commercial customers from a single source and to 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.

There continues to be concern, both nationally and internationally, about climate change and the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global warming. While some states have adopted laws and regulations regulating the emission of GHGs for some industry sectors, there is currently no federal or regional legislation mandating the reduction of GHG emissions in the United States. Because propane is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, we anticipate that this will provide us with a competitive advantage over other sources of energy, such as fuel oil and coal, if new climate change regulations become effective.

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, 2011, the General Partner had approximately 5,800 employees, including approximately 340 part-time, seasonal and temporary employees, working on behalf of the Partnership. UGI also performs certain financial and administrative services for the General Partner on behalf of the Partnership and is reimbursed by the Partnership.

INTERNATIONAL PROPANE — ANTARGAZ

Our International Propane — Antargaz LPG distribution business is conducted in France through our wholly owned subsidiary, Antargaz. Antargaz is one of the largest LPG distributors in France. During Fiscal 2011, Antargaz sold approximately 270 million gallons of LPG.

ANTARGAZ

Products, Services and Marketing

Antargaz’ customer base consists of residential, commercial, agricultural and motor fuel customer accounts that use LPG for space heating, cooking, water heating, process heat and transportation. Antargaz sells LPG in cylinders, and in small, medium and large tanks. Sales of LPG are also made to service stations to accommodate vehicles that run on LPG. Antargaz sells LPG in cylinders to approximately 16,400 retail outlets, such as supermarkets, individually owned stores and gas stations. Supermarket sales represented approximately 58% of cylinder sales volume in Fiscal 2011. At September 30, 2011, Antargaz had approximately 190,000 bulk customers and approximately 6.5 million cylinders in circulation. Approximately 60% of Antargaz’ Fiscal 2011 sales (based on volumes) were cylinder and small bulk, 14% medium bulk, 19% large bulk, 4% to service stations for automobiles, and 3% piped networks (metered sales). Antargaz also engages in wholesale sales of LPG and provides logistic, storage and other services to third-party LPG distributors. In June 2010, Antargaz commenced a natural gas marketing business servicing both commercial and residential customers. 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 certain sports facilities and swimming pools, and the poultry industry for use in chicken brooding.

Medium bulk customers use propane only, and consist mainly of large residential developments such as housing projects, hospitals, municipalities and medium-sized industrial enterprises, and poultry brooders. Large bulk customers include agricultural companies, and companies that use LPG in their industrial processes.

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 60% of all LPG cylinders sold in Fiscal 2011, 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 and electricity.

LPG Supply and Storage

Antargaz has an agreement with Totalgaz for the supply of butane, with pricing based on internationally quoted market prices. Under this agreement, 80% of Antargaz’ requirements for butane are guaranteed until September 2012. Requirements are fixed annually and Antargaz can develop other sources of supply. For Fiscal 2011, Antargaz purchased almost 80% of its butane needs from Totalgaz. Antargaz also purchases propane on the international market and on the domestic market, under term agreements with international oil and gas trading companies. In addition, purchases are made on the spot market from international oil and gas companies and to a lesser extent from domestic refineries, including those operated by BP France and Esso SAF. During Fiscal 2011, three suppliers accounted for substantially all of Antargaz’ propane supply.

Antargaz has 4 primary storage facilities in operation, including 3 that are located at deep sea harbor facilities, and 26 secondary storage facilities. It also manages an extensive logistics and transportation network. Access to seaborne facilities allows Antargaz to diversify its LPG supplies through imports. LPG stored in primary storage facilities is transported to smaller storage facilities by rail, sea and road. At secondary storage facilities, LPG is filled into cylinders or trucks equipped with tanks and then delivered to customers.

Competition

The LPG market in France is mature, with modest declines in total demand due to competition with other fuels, conservation and the challenging economic climate. 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 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) and Compagnie des Gaz de Petrole Primagaz (an independent supplier owned by SHV Holding NV), as well as with regional competitors, Vitogaz and Repsol. In recent years, competition has increased as supermarkets affiliate with LPG distributors to offer their own brands of cylinders. Antargaz has partnered with one supermarket chain in this market. If Antargaz is unsuccessful in expanding its services to other supermarket chains, its market share through supermarket sales may decline. Some of Antargaz’ competitors are affiliates of its LPG suppliers. As a result, its competitors may obtain product at more competitive prices. Antargaz seeks to increase demand for its butane and propane cylinders through marketing and product innovations.

Seasonality

Because a significant amount of LPG is used for heating, demand is typically higher during the colder months of the year. Approximately 65% to 70% of Antargaz’ retail sales volume occurs, and substantially all of Antargaz’ operating income is earned, during the six months from October through March.

Sales volume for Antargaz traditionally fluctuates from year-to-year in response to variations in weather, prices and other factors, such as conservation efforts and the challenging economic climate. 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. One of these is a refrigerated facility. The table below sets forth details of each of these facilities.

						Antargaz				Antargaz
						Storage Capacity -				Storage Capacity -
						Propane				Butane
		Ownership %				(m3) (1)				(m3) (1)
Norgal			52.7				22,600				8,900
Geogaz Lavera			16.7				17,400				32,500
Donges			50.0	(2)			30,000				0
Cobogal			15.0				1,300				450

Antargaz has 26 secondary storage facilities, 13 of which are wholly owned. The others are partially owned, through joint ventures.

Employees

At September 30, 2011, Antargaz had approximately 980 employees.

INTERNATIONAL PROPANE — FLAGA AND OTHER

During Fiscal 2011, our International Propane — Flaga and Other LPG distribution business was conducted principally in Europe through our wholly owned subsidiary, Flaga. Flaga is referred to in this section collectively with its subsidiaries as “Flaga” unless the context otherwise requires. Flaga operates in Poland, the Czech Republic, Hungary, Austria, Denmark, Slovakia, Romania and Switzerland. During Fiscal 2011, Flaga sold approximately 159 million gallons of LPG. Flaga is the largest distributor of LPG in Austria and Denmark and one of the largest distributors of LPG in the Czech Republic, Hungary and Slovakia. Our majority-owned partnership in China sold approximately 12 million gallons of LPG during Fiscal 2011.

During the fourth quarter of Fiscal 2010, Flaga acquired LPG distribution businesses in Denmark and Hungary. During the first quarter of Fiscal 2011, Flaga acquired an LPG distribution business in Poland. In October of 2011, a subsidiary of Flaga purchased LPG distribution businesses in Denmark, Finland, Norway and Sweden, and subsidiaries of UGI Corporation purchased LPG distribution businesses in the United Kingdom, Belgium, the Netherlands and Luxembourg. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Subsequent Events” and Note 22 to Consolidated Financial Statements.

FLAGA

Products, Services, Marketing and Storage

During Fiscal 2011, Flaga sold approximately 159 million gallons of LPG. Flaga serves customers that use LPG for residential, commercial, industrial, agricultural and automobile fuel (“auto gas”) purposes. Flaga’s customers primarily use LPG for heating, cooking, motor fuel (including forklifts), construction work, industrial processing, crop drying, power generation and irrigation. Flaga sells LPG in cylinders and in small, medium and large bulk tanks. At September 30, 2011, Flaga had approximately 60,000 customers and 3.3 million cylinders in circulation. Approximately 44% of Flaga’s Fiscal 2011 sales (based on volumes) were cylinder and small bulk, 31% auto gas; 18% large bulk, and 7% medium bulk.

Flaga has 25 sales offices throughout the countries it serves. Sales offices generally consist of an office location where customers can directly purchase LPG. Except for Poland, no single country’s total gallons of LPG sold during Fiscal 2011 represented more than 12% of Flaga’s total gallons in Fiscal 2011. Flaga distributes cylinders directly to its customers and through the use of distributors who resell the cylinders to end users under the distributor’s pricing and terms. No single customer represents or is anticipated to represent more than 5% of total revenues for Flaga, with the exception of one low margin customer which represented approximately 11% of Flaga’s total revenues in Fiscal 2011.

LPG Supply and Storage

Flaga typically enters into an annual agreement with TCO/Chevron for the supply of approximately 30% of Flaga’s LPG requirements, with pricing based on internationally quoted market prices. Flaga also purchases LPG on the international market and on the domestic markets, under annual term agreements with international oil and gas trading companies, including Vitol and Orlen Gas, and from domestic refineries, primarily OMV, Unipetrol, Shell and Statoil. In addition, LPG purchases are made on the spot market from international oil and gas traders. During Fiscal 2011, five suppliers accounted for approximately 50% of Flaga’s LPG supply.

Flaga operates 8 main storage facilities, including one in Denmark that is located at a deep sea harbor facility, one LPG import terminal in Poland, and 66 secondary storage facilities. Flaga manages a widespread logistics and transportation network including approximately 170 leased railcars, and also maintains various transloading and filling agreements with third parties. LPG stored in primary storage facilities is transported to smaller storage facilities by rail or truck.

Seasonality and Competition

The retail propane industry in the Western European countries in which we operate is mature, with slight declines in overall demand in recent years, due primarily to the expansion of natural gas, customer conservation and challenging economic conditions. In the Eastern European countries in which Flaga operates, the demand for LPG is expected to grow. Competition for customers is based on contract terms as well as on product prices. Flaga competes with other LPG marketers, including competitors located in other European countries, and also competes with providers of other sources of energy, principally natural gas, electricity and wood.

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 temperatures during the heating season months and traditionally fluctuate from year-to-year in response to variations in weather, prices and other factors, such as conservation efforts and the challenging economic climate. 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 when product costs rise rapidly. In parts of Flaga’s sales territories, it is particularly difficult to pass on rapid increases in the price of LPG due to the low per capita income of customers in several of its territories and the intensity of competition. Product cost increases can be triggered by periods of severe cold weather, supply interruptions, increases in the prices of base commodities such as crude oil and natural gas, or other unforeseen events. High LPG prices may result in slower than expected growth due to customer conservation and customers seeking less expensive alternative energy sources. In many of Flaga’s sales territories, government policies and incentives that favor alternative energy sources may result in customers migrating to energy sources other than LPG. Rules and regulations applicable to LPG industry operations in many of the Eastern European countries where Flaga operates are still evolving, or are not consistently enforced. As a result, competitive conditions in those areas are intense.

Government Regulation

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

Employees

At September 30, 2011, Flaga had approximately 850 employees.

GAS UTILITY

Gas Utility consists of the regulated natural gas distribution businesses of our subsidiary, UGI Utilities and UGI Utilities’ subsidiaries, PNG and CPG. Gas Utility serves approximately 575,000 customers in eastern and central Pennsylvania and several hundred customers in portions of one Maryland county. Gas Utility is regulated by the PUC and, with respect to its several hundred customers in Maryland, the Maryland Public Service Commission.

Service Area; Revenue Analysis

Gas Utility is authorized to distribute natural gas to approximately 575,000 customers in portions of 46 eastern and central Pennsylvania counties through its distribution system of approximately 12,200 miles of gas mains. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre, Lock Haven, Pittston, Pottsville and Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas Utility’s service area are major production centers for basic industries such as specialty metals, aluminum, glass and paper product manufacturing. Gas Utility also distributes natural gas to several hundred customers in portions of one Maryland county.

System throughput (the total volume of gas sold to or transported for customers within Gas Utility’s distribution system) for Fiscal 2011 was approximately 173.2 billion cubic feet (“bcf”). System sales of gas accounted for approximately 35% of system throughput, while gas transported for residential, commercial and industrial customers who bought their gas from others accounted for approximately 65% of system throughput.

Sources of Supply and Pipeline Capacity

Gas Utility is permitted to recover prudently incurred costs of natural gas it sells to its customers. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures” and Note 8 to Consolidated Financial Statements. 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 2011, Gas Utility purchased approximately 97.5 bcf of natural gas for sale to core-market customers (principally comprised of firm- residential, commercial and industrial customers who purchase their gas from Gas Utility (“retail core market”)) and off-system sales customers. Approximately 74% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 26% of gas purchased by Gas Utility was supplied by approximately 25 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 60% to 65% of Gas Utility’s sales volume is supplied, and approximately 85% to 90% of Gas Utility’s operating income is earned, during a typical peak heating season from October through March.

Competition

Natural gas is a fuel that competes with electricity and oil, and to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of fuel utilization equipment. Due to the expiration of rate caps for electric utilities serving a significant portion of Gas Utility’s service territory, natural gas generally benefits from a competitive price advantage over electricity. However, high efficiency electric heat pumps have led to a decrease in the cost of heating with electricity. Government subsidies currently favor ground source heat pumps over fossil fueled systems. Fuel oil dealers compete for customers in all categories, including industrial customers. Gas Utility responds to this competition with marketing efforts designed to retain and grow its customer base.

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

A number of Gas Utility’s commercial and industrial customers have the ability to switch to an alternate fuel at any time and, therefore, are served on an interruptible basis under rates which are competitively priced with respect to the alternate fuel. Margin from these customers, therefore, is affected by the difference or “spread” between the customers’ delivered cost of gas and the customers’ delivered cost of the alternate fuel, as well as the frequency and duration of interruptions. See “Gas Utility and Electric Utility Regulation and Rates — Gas Utility Rates.”

Approximately 34% 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 27 customers, most of which are among the 10 largest customers for Gas Utility in terms of annual volumes. All of these customers have contracts, 24 of which extend beyond the 2012 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 2012. 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 2011, Gas Utility supplied transportation service to 2 major co-generation installations and 6 electric generation facilities. Gas Utility continues to seek new residential, commercial and industrial customers for both firm and interruptible service. In the residential market sector, Gas Utility connected approximately 10,500 residential heating customers during Fiscal 2011. Approximately 5,500 of these customers, an increase of 34% from Fiscal 2010, converted to natural gas from other energy sources, mainly oil and electricity, largely due to the volatility of oil prices and the elimination of electricity rate caps during Fiscal 2011. New home construction customers and existing non-heating gas customers who added gas heating systems to replace other energy sources primarily accounted for the other residential heating connections in Fiscal 2011.

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

The Electric Utility segment (“Electric Utility”) consists of the regulated electric distribution business of UGI Utilities, serving approximately 62,000 customers in northeastern Pennsylvania. Electric Utility is regulated by the PUC.

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 2,100 miles of transmission and distribution lines and 13 transmission substations. For Fiscal 2011, approximately 55% of sales volume came from residential customers, 33% from commercial customers, and 12% from industrial and other customers.

Sources of Supply

In accordance with Electric Utility’s default service settlement with the PUC effective January 1, 2010, Electric Utility is permitted to recover prudently incurred electricity costs, including costs to obtain supply to meet its customers’ energy requirements, pursuant to a supply plan filed with the PUC. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures” and Note 8 to Consolidated Financial Statements. Electric Utility distributes electricity that it purchases from wholesale markets and electricity that customers purchase from other suppliers. During Fiscal 2011, 4 electric generation suppliers provided energy for customers representing approximately 20% of Electric Utility’s sales volume. See “Gas Utility and Electric Utility Regulation and Rates — Electric Utility Rates.”

Competition

As a result of the Electricity Generation Customer Choice and Competition Act (“ECC Act”), all Pennsylvania retail electric customers have the ability to choose their electric generation supplier. Electric Utility remains the “default service” provider for its customers who do not choose an alternate electric generation supplier. In Fiscal 2011, Electric Utility served nearly all of the electric customers within its service territory and is the only regulated electric utility having the right, granted by the PUC or by law, to distribute electricity in its service territory. As an energy source, electricity competes with natural gas, oil, propane and other heating fuels for residential heating purposes.

The terms and conditions under which Electric Utility provides default service, and rules governing the rates that may be charged for such service, have been established in a Default Service Rate Plan (“DSR Plan”) approved by the PUC. Consistent with the terms of the DSR Plan, effective January 1, 2010, default service rates are designed to recover all reasonable and prudent costs incurred in providing electricity to default service customers. This recovery, through default service rates, no longer subjects Electric Utility to the risk that actual costs for purchased power will exceed default service revenues. Conversely, effective January 1, 2010, Electric Utility does not have the opportunity to recover revenues in excess of actual power costs. See “Gas Utility and Electric Utility Regulation and Rates — Electric Utility Rates.”

GAS UTILITY AND ELECTRIC UTILITY REGULATION AND RATES

Pennsylvania Public Utility Commission Jurisdiction

UGI Utilities’ gas and electric utility operations are subject to regulation by the PUC as to rates, terms and conditions of service, accounting matters, issuance of securities, contracts and other arrangements with affiliated entities, and various other matters. There are primarily two types of rates that UGI Utilities may charge customers for gas and electric service: (1) rates designed to recover costs other than purchased gas costs (“PGCs”) and electric default service costs; and (2) rates designed to recover PGCs and electric default service costs. Rates designed to recover costs other than PGCs and electric default service costs are primarily established in general base rate proceedings. Rates designed to recover PGCs and electric default service costs are established in PGC and electric default service rate proceedings.

Electric Transmission and Wholesale Power Sale Rates

FERC has jurisdiction over the rates and terms and conditions of service of electric transmission facilities used for wholesale or retail choice transactions. Electric Utility owns electric transmission facilities that are within the control area of the PJM Interconnection, LLC (“PJM”) and are dispatched in accordance with a FERC-approved open access tariff and associated agreements administered by PJM. PJM is a regional transmission organization that regulates and coordinates generation supply and the wholesale delivery of electricity. Electric Utility receives certain revenues collected by PJM, determined under a formulary rate schedule that is adjusted in June of each year to reflect annual changes in Electric Utility’s electric transmission revenue requirements, when its transmission facilities are used by third parties.

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

Gas Utility Rates

Rates that Gas Utility may charge for gas service come in two forms: 1) rates designed to recover costs other than PGCs; and 2) rates designed to recover purchase gas costs. Rates designed to recover costs other than PGCs are primarily established in general base rate proceedings. Rates designed to recover PGCs are reviewed in PGC rate proceedings. The most recent general base rate increase for UGI Gas became effective in 1995. In accordance with a statutory mechanism, a rate increase for Gas Utility’s retail core-market customers became effective October 1, 2000 along with a PGC variable credit equal to a portion of the margin received from customers served under interruptible rates to the extent such interruptible customers use third-party pipeline capacity contracted for by UGI Gas for retail core-market customers.

On August 11, 2011, the PUC approved CPG’s base rate case settlement agreement, which resulted in an $8.9 million base rate operating revenue increase for CPG. The increase became effective on August 30, 2011. On August 27, 2009, the PUC approved PNG’s and CPG’s base rate case settlement agreements, which resulted in a $19.75 million base rate operating revenue increase for PNG and a $10 million base rate operating revenue increase for CPG. These increases became effective on August 28, 2009.

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

UGI Gas has two PGC rates: (1) PGC is applicable to small, firm, retail core-market customers consisting of the residential and small commercial and industrial classes; and (2) PGC is applicable to firm, contractual, high-load factor customers served on three separate rates. PNG and CPG each have one PGC rate applicable to all customers.

Electric Utility Rates

The most recent general base rate increase for Electric Utility became effective in 1996. Electric Utility’s rates were unbundled into distribution, transmission and generation (POLR or “default service”) components in 1998. In accordance with the POLR Settlements, Electric Utility increased POLR rates annually from 2005 through 2009.

PUC default service regulations became applicable to Electric Utility’s provision of default service effective January 1, 2010 and Electric Utility, consistent with these regulations, has received approval from the PUC of (1) default service tariff rules applicable for service rendered on or after January 1, 2010, (2) a reconcilable default service cost rate recovery mechanism to recover the cost of acquiring default service supplies for service rendered on or after January 1, 2010, (3) a plan for meeting the post-2009 requirements of the Alternative Energy Portfolio Standards Act (“AEPS Act”), which requires Electric Utility to directly or indirectly acquire certain percentages of its supplies from designated alternative energy sources and (4) a reconcilable AEPS Act cost recovery rate mechanism to recover the costs of complying with AEPS Act requirements applicable to default service supplies for service rendered on or after January 1, 2010. Under these rules, default service rates for most customers will be adjusted quarterly.

FERC Market Manipulation Rules and Other FERC Enforcement and Regulatory Powers

Both Gas Utility and Electric Utility, and our subsidiary, UGI Energy Services, Inc. and several of its subsidiaries 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, 2011, UGI Utilities had approximately 1,400 employees.

MIDSTREAM & MARKETING

Energy Services operates the energy-related businesses described below.

Retail Energy Marketing

Energy Services sells natural gas, liquid fuels and electricity to approximately 10,000 commercial and industrial customers at approximately 30,000 locations. Energy Services serves customers in all or portions of Pennsylvania, New Jersey, Delaware, New York, Ohio, Maryland, Virginia, North Carolina and the District of Columbia. Energy Services distributes natural gas through the use of the transportation systems of 33 utility systems. It supplies power to customers through the use of the transmission systems of 19 utility systems.

A majority of Energy Services’ commodity sales are made under fixed-price agreements. Energy Services manages supply cost volatility related to these agreements by (i) entering into fixed-price supply arrangements with a diverse group of suppliers and holders of interstate pipeline capacity, (ii)  entering into exchange-traded futures contracts on the New York Mercantile Exchange, (iii)entering into over-the-counter derivative arrangements with major international banks and major suppliers, and (iv) utilizing supply assets that it owns or manages. Energy Services also bears the risk for balancing and delivering natural gas and power to its customers under various gas pipeline and utility company tariffs. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Disclosures.”

Midstream Assets

Energy Services operates a natural gas liquefaction, storage and vaporization facility in Temple, Pennsylvania (“Temple Facility”), and propane storage and propane-air mixing stations in Bethlehem, Reading, Hunlock Creek, and White Deer, Pennsylvania. It also operates propane storage, rail transshipment terminals and propane-air mixing stations in Steelton and Williamsport, Pennsylvania. These assets are used in Energy Services’ energy peaking business that provides supplemental energy, primarily liquefied natural gas and propane-air mixtures, to gas utilities at times of high demand (generally during periods of coldest winter weather). During Fiscal 2011, Energy Services continued construction work on the fourfold expansion of its Temple Facility. That project is on schedule and expected to be completed during Fiscal 2012. Energy Services also manages natural gas pipeline and storage contracts for UGI Utilities, subject to a competitive bid process, as well as storage capacity owned by Energy Services.

During Fiscal 2011, a subsidiary of Energy Services acquired underground natural gas storage facilities formerly owned by CPG and received FERC approval to sell storage services at market-based rates. The storage facilities are located in the Marcellus Shale region of Pennsylvania and have a total storage quantity of 15 million decatherms and a maximum daily withdrawal quantity of 224,000 decatherms.

In Fiscal 2011, Energy Services continued making investments in infrastructure projects to support the development of natural gas in the Marcellus Shale region of Pennsylvania. Our initial gathering project to transport natural gas from a pipeline in Pennsylvania to an interstate pipeline was placed into service in October 2011. Future planned investments are expected to cover a range of new midstream asset opportunities, including interstate pipelines, local gathering systems and gas storage facilities.

Electric Generation

We have an approximate 5.97% (approximately 102 megawatt) ownership interest in the Conemaugh generation station (“Conemaugh”), a 1,711 megawatt, coal-fired generation station located near Johnstown, Pennsylvania. Conemaugh is owned by a consortium of energy companies and operated by a unit of Reliant Resources, Inc. Energy Services also owns the Hunlock Station located near Wilkes-Barre, Pennsylvania, which is a 125-megawatt natural gas-fueled generating station, which commenced operations in July 2011. Prior to June 2010, Energy Services operated the Hunlock Station as a 44-megawatt coal-fired facility. At that time, it ceased operations to facilitate conversion to a natural gas-fueled plant. Due to an accident in late July 2011, one unit at Hunlock Station was shut down for repairs and is expected to restart in the spring of 2012. Another unit at Hunlock Station suffered flood damage later in the fourth quarter of Fiscal 2011 and was restarted in early November 2011.

Energy Services owns and operates a landfill gas-fueled electricity generation plant near Hegins, Pennsylvania with gross generating capacity of 11 megawatts. The plant qualifies for renewable energy credits. Energy Services owns and operates a 1 megawatt solar-powered generation facility in Easton, Pennsylvania. During Fiscal 2011, Energy Services completed the construction of 8 solar-powered facilities generating an aggregate of more than 4 megawatts. Several other solar generation projects are in development.

Competition

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

Government Regulation

FERC has jurisdiction over the rates and terms and conditions of service of wholesale sales of electric capacity and energy, as well as the sales for resale of natural gas and related storage and transportation services. Energy Services has a tariff on file with FERC pursuant to which it may make power sales to wholesale customers at market-based rates. Energy Services also has market-based rate authority for power sales to wholesale customers to the extent that Energy Services purchases power in excess of its retail customer needs. Two subsidiaries of Energy Services operate facilities under FERC certificate approvals and offer services to wholesale customers at FERC-approved market-based rates. 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.”

Energy Services is subject to various federal, state and local environmental, safety and transportation laws and regulations governing the storage, distribution and transportation of propane and the operation of bulk storage LPG terminals. These laws include, among others, the Resource Conservation and Recovery Act, CERCLA, the Clean Air Act, the Occupational Safety and Health Act, the Homeland Security Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. CERCLA imposes joint and several liability on certain classes of persons considered to have contributed to the release or threatened release of a “hazardous substance” into the environment without regard to fault or the legality of the original conduct.

Employees

At September 30, 2011, Energy Services and its subsidiaries had approximately 190 employees.

HVAC/R

We conduct a heating, ventilation, air-conditioning, refrigeration and electrical contracting service business through UGI HVAC Enterprises, Inc. (“HVAC/R”) serving portions of eastern Pennsylvania and the Mid-Atlantic region, including the Philadelphia suburbs and portions of New Jersey and northern Delaware. This business serves more than 107,500 customers in residential, commercial, industrial and new construction markets. During Fiscal 2011, HVAC/R generated approximately $84 million in revenues and employed approximately 475 people.

BUSINESS SEGMENT INFORMATION

The table stating the amounts of revenues, operating income (loss) and identifiable assets attributable to each of UGI’s reportable business segments, and to the geographic areas in which we operate, for the 2011, 2010 and 2009 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, 2011, UGI and its subsidiaries had approximately 9,750 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 and Antargaz’ annual retail LPG volume, and 60% to 65% of Gas Utility’s natural gas throughput (the total volume of gas sold to or transported for customers within our distribution system) has been sold during these months. There can be no assurance that normal winter weather in our market areas will occur in the future.

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

We are a holding company whose material assets are the stock of our subsidiaries. Our ability to pay dividends on our common stock and to pay principal and accrued interest on our debt, if any, depends on the payment of dividends to us by our principal subsidiaries, AmeriGas, Inc., UGI Utilities, Inc. and UGI Enterprises, Inc. (including Antargaz). Payments to us by those subsidiaries, in turn, depend upon their consolidated results of operations and cash flows. The operations of our subsidiaries are affected by conditions beyond our control, including weather, competition in national and international markets we serve, the costs and availability of propane, butane, natural gas, electricity, and other energy sources and capital market conditions. The ability of our subsidiaries to make payments to us is also affected by the level of indebtedness of our subsidiaries, which is substantial, and the restrictions on payments to us imposed under the terms of such indebtedness.

Our profitability is subject to LPG pricing and inventory risk.

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

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

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

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

The 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 and conditions in the credit and capital markets. Developments in the credit markets during the past few years 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 current financial market conditions, if they were to continue for the foreseeable future, will not have a significant impact on our ability to fund our existing operations, such market conditions could restrict our ability to grow through acquisitions, limit the scope of major capital projects if access to credit and capital markets is limited, or could adversely affect our operating results.

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

The economic recession, 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 funded status and increase the amount of required contributions to our pension plans.

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

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

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

During Fiscal 2011, AmeriGas Propane purchased approximately 82% of its propane needs from ten suppliers. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, our earnings could be affected. Additionally, in certain areas, a single supplier provides more than 50% of AmeriGas Propane’s propane requirements. Disruptions in supply in these areas could also have an adverse impact on our earnings. Antargaz and Flaga are similarly dependent upon their suppliers. There is no assurance that Antargaz and Flaga will be able to continue to acquire sufficient supplies of LPG to meet demand at prices or within time periods that would allow them to remain competitive.

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

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

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

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

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

Our natural gas businesses compete primarily with electricity and fuel oil, and, to a lesser extent, with propane and coal. Competition among these fuels is primarily a function of their comparative price and the relative cost and efficiency of fuel utilization equipment. There can be no assurance that our natural gas revenues will not be adversely affected by this competition.

Our ability to increase revenues is adversely affected by the decline of the retail LPG industry.

The retail LPG distribution industry in the U.S., France, Austria and Denmark is mature, with no growth, or modest declines in total demand foreseen. Given this forecast, we expect that year-to-year industry volumes will be principally affected by weather patterns. Therefore, our ability to grow within the LPG industry is dependent on our ability to acquire other retail distributors and to achieve internal growth, which includes expansion of the domestic ACE and Strategic Accounts programs in the U.S., as well as the success of our sales and marketing programs designed to attract and retain customers. Any failure to retain and grow our customer base would have an adverse effect on our results.

Our ability to grow our businesses will be adversely affected if we are not successful in making acquisitions or integrating the acquisitions we have made.

One of our strategies is to grow through acquisitions in the United States and in international markets. We may choose to finance future acquisitions with debt, equity, cash or a combination of the three. We can give no assurances that we will find attractive acquisition candidates in the future, that we will be able to acquire such candidates on economically acceptable terms, that we will be able to finance acquisitions on economically acceptable terms, that any acquisitions will not be dilutive to earnings or that any additional debt incurred to finance an acquisition will not affect our ability to pay dividends.

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, including the acquisition of certain of Shell’s LPG distribution businesses in Europe and the anticipated acquisition of the propane operations of Energy Transfer, involve a number of risks. These risks include but are not limited to, the assumption of material liabilities, the diversion of management’s attention from the management of daily operations to the integration of operations, difficulties in the assimilation and retention of employees and difficulties in the assimilation of different cultures and practices, as well as in the assimilation of broad and geographically dispersed personnel and operations. The failure to successfully integrate acquisitions could have an adverse effect on our business, financial condition and results of operations.

Expanding our midstream asset business by constructing new facilities subjects us to risks.

One of the ways we seek to grow our midstream asset business is by constructing new pipelines and gathering systems, expanding our LNG facility and improving our gas storage facilities. These construction projects involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. These projects may not be completed on schedule, or at all, or at the anticipated costs. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. We may construct facilities to capture anticipated future growth in production and demand in an area in which anticipated growth and demand does not materialize. As a result, there is the risk that new and expanded facilities may not be able to attract enough customers to achieve our expected investment returns, which could have a material adverse effect on our business, results of operations or financial condition.

Our need to comply with comprehensive, complex, and sometimes unpredictable government regulations may increase our costs and limit our revenue growth, which may result in reduced earnings.

While we generally refer to our Gas Utility and Electric Utility segments as our “regulated segments,” there are many governmental regulations that have an impact on our businesses. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company which may affect our businesses in ways that we cannot predict.

Regulators may not allow timely recovery of costs for UGI Utilities in the future, which may adversely affect our results of operations.

In our Gas Utility and Electric Utility segments, our distribution operations are subject to regulation by the PUC. The PUC, among other things, approves the rates that UGI Utilities and its subsidiaries, PNG and CPG, may charge their utility customers, thus impacting the returns that UGI Utilities may earn on the assets that are dedicated to those operations. We expect that PNG and CPG will periodically file requests with the PUC to increase base rates that each company charges customers. If UGI Utilities is required in a rate proceeding to reduce the rates it charges its utility customers, or if UGI Utilities is unable to obtain approval for timely rate increases from the PUC, particularly when necessary to cover increased costs, UGI Utilities’ revenue growth will be limited and earnings may decrease.

We are subject to operating and litigation risks that may not be covered by insurance.

Our business operations in the U.S. and other countries are subject to all of the operating hazards and risks normally incidental to the handling, storage and distribution of combustible products, such as LPG, propane and natural gas, and the generation of electricity. These risks could result in substantial losses due to personal injury and/or loss of life, and severe damage to and destruction of property and equipment arising from explosions and other catastrophic events, including acts of terrorism. 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 currently be recovered in PUC rate proceedings, and insurance may not cover all or even part of these costs. Our actual costs to clean up these sites may exceed our current estimates due to factors beyond our control, such as:

	•		the discovery of presently unknown conditions;
	•		changes in environmental laws and regulations;
	•		judicial rejection of our legal defenses to the third-party claims; or
	•		the insolvency of other responsible parties at the sites at which we are involved.

In addition, if we discover additional contaminated sites, we could be required to incur material costs, which would reduce our net income.

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

There continues to be concern, both nationally and internationally, about climate change and the contribution of greenhouse gas (“GHG”) emissions, most notably carbon dioxide, to global climate change. In addition to carbon dioxide, greenhouse gases include, among others, methane, a component of natural gas. While some states have adopted laws or regulations regulating the emission of GHGs for some industry sectors, there is currently no federal or regional legislation mandating the reduction of GHG emissions in the United States. In September 2009, the Environmental Protection Agency (“EPA”) issued a final rule establishing a system for mandatory reporting of GHG emissions. In November 2010, the EPA expanded the reach of its GHG reporting requirements to include the petroleum and natural gas industries. Petroleum and natural gas facilities subject to the rule, which include facilities of our natural gas distribution and electricity generation businesses, are required to begin emissions monitoring in January 2011 and to submit detailed annual reports beginning in March 2012. The rule does not require affected facilities to implement GHG emission controls or reductions.

It is expected that climate change legislation will continue to be part of the legislative and regulatory discussion for the foreseeable future. Increased regulation of GHG emissions, especially in the transportation sector, could impose significant additional costs on us and our customers. The impact of legislation and regulations on us will depend on a number of factors, including (i) what industry sectors would be impacted, (ii) the timing of required compliance, (iii) the overall GHG emissions cap level, (iv) the allocation of emission allowances to specific sources, and (v) the costs and opportunities associated with compliance. At this time, we cannot predict the effect that climate change regulation may have on our business, financial condition or results of operations in the future.

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 and we continue to explore the expansion of our international businesses. As a result, we face risks in doing business abroad that we do not face domestically. Certain aspects inherent in transacting business internationally could negatively impact our operating results, including:

	•		costs and difficulties in staffing and managing international operations;
	•		tariffs and other trade barriers;
	•		difficulties in enforcing contractual rights;
	•		longer payment cycles;
	•		local political and economic conditions;
	•		potentially adverse tax consequences, including restrictions on repatriating earnings and the threat of “double taxation;”
	•		fluctuations in currency exchange rates, which can affect demand and increase our costs;
	•		internal control and risk management practices and policies;
	•		regulatory requirements and changes in regulatory requirements, including French, Austrian, Danish and EU competition laws that may adversely affect the terms of contracts with customers, and stricter regulations applicable to the storage and handling of LPG; and
	•		new and inconsistently enforced LPG industry regulatory requirements, which can have an adverse effect on our competitive position.

Unforeseen difficulties with the implementation or operation of our information systems could adversely affect our internal controls and our businesses.

We contracted with third-party consultants to assist us with the design and implementation of an information system that supports the Partnership’s Order-to-Cash business processes. The efficient execution of the Partnership’s business is dependent upon the proper functioning of its internal systems. Any significant failure or malfunction of the Partnership’s or our other business units’ information systems may result in disruptions of their operations. Our results of operations could be adversely affected if we encounter unforeseen problems with respect to the operation of our information systems.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

BP America Production Company v. Amerigas Propane, L.P. On July 15, 2011, BP America Production Company (“BP”) filed a complaint against AmeriGas Propane, L.P. in the District Court of Denver County, Colorado, alleging, among other things, breach of contract and breach of the covenant of good faith and fair dealing relating to amounts billed for certain goods and services provided to BP since 2005 (the “Services”). The Services relate to the installation of propane-fueled equipment and appliances, and the supply of propane, to approximately 400 residential customers at the request of and for the account of BP. The complaint seeks an unspecified amount of direct, indirect, consequential, special and compensatory damages, including attorneys’ fees, costs and interest and other appropriate relief. It also seeks an accounting to determine the amount of the alleged overcharges related to the Services. We have substantially completed our investigation of this matter and, based upon the results of that investigation, we believe we have good defenses to the claims set forth in the complaint and the amount of loss will not be material.

Federal Trade Commission Investigation of Propane Grill Cylinder Filling Practices. On or about November 4, 2011, the General Partner received notice that the Federal Trade Commission is conducting an antitrust and consumer protection investigation into certain practices of the Partnership which relate to the filling of portable propane grill cylinders. Based upon the limited amount of information available at this time, the Partnership believes the investigation concerns, in whole or in part, the Partnership’s decision, in 2008, to reduce the volume of propane in the grill cylinders it sells to consumers from 17 pounds to 15 pounds. The Partnership believes that it will have good defenses to any claims that may result from this investigation. Because of the limited information available at this time, we are not able to assess the financial impact this investigation or any related claims may have on the Partnership.

With the exception of the matters described above, and those matters set forth in Note 15 to Consolidated Financial Statements included in Item 8 of this Report, no material legal proceedings are pending involving UGI, any of its subsidiaries, or any of their properties, and no such proceedings are known to be contemplated by governmental authorities other than claims arising in the ordinary course of business.

ITEM 4. (REMOVED AND RESERVED)

EXECUTIVE OFFICERS

Information regarding our executive officers is included in Part III of this Report and is incorporated in Part I by reference.

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:

2011 Fiscal Year		High				Low
4th Quarter		$	32.68			$	25.81
3rd Quarter			33.53				30.22
2nd Quarter			33.34				30.63
1st Quarter			32.49				28.57

2010 Fiscal Year		High				Low
4th Quarter		$	29.00			$	24.90
3rd Quarter			27.88				24.30
2nd Quarter			26.95				23.83
1st Quarter			25.65				23.18

Dividends

Quarterly dividends on our Common Stock were paid in Fiscal 2011 and Fiscal 2010 as follows:

2011 Fiscal Year		Amount
4th Quarter		$	0.26000
3rd Quarter			0.25000
2nd Quarter			0.25000
1st Quarter			0.25000

2010 Fiscal Year		Amount
4th Quarter		$	0.25000
3rd Quarter			0.20000
2nd Quarter			0.20000
1st Quarter			0.20000

Record Holders

On November 16, 2011, UGI had 7,495 holders of record of Common Stock.

ITEM 6.		SELECTED FINANCIAL DATA

		Year Ended September 30,
(Millions of dollars, except per share amounts)		2011				2010				2009				2008				2007
FOR THE PERIOD:
Income statement data:
Revenues		$	6,091.3			$	5,591.4			$	5,737.8			$	6,648.2			$	5,476.9
Net income		$	308.2			$	355.7			$	382.0			$	305.3			$	311.2
Less: net income attributable to noncontrolling interests, principally in AmeriGas Partners			(75.3	)			(94.7	)			(123.5	)			(89.8	)			(106.9	)
Net income attributable to UGI Corporation		$	232.9			$	261.0			$	258.5			$	215.5			$	204.3
Earnings per common share attributable to UGI stockholders:
Basic		$	2.09			$	2.38			$	2.38			$	2.01			$	1.92
Diluted		$	2.06			$	2.36			$	2.36			$	1.99			$	1.89
Cash dividends declared per common share		$	1.02			$	0.90			$	0.785			$	0.755			$	0.723
AT PERIOD END:
Balance sheet data:
Total assets		$	6,663.3			$	6,374.3			$	6,042.6			$	5,685.0			$	5,502.7
Capitalization:
Debt:
Bank loans — UGI Utilities		$	—			$	17.0			$	154.0			$	57.0			$	190.0
Bank loans — AmeriGas Propane			95.5				91.0				—				—				—
Bank loans — Antargaz			—				68.2				—				70.4				—
Bank loans — other			43.2				24.2				9.1				9.0				8.9
Long-term debt (including current maturities):
AmeriGas Propane			933.5				791.4				865.6				933.4				933.1
International Propane			571.3				561.1				613.8				589.5				605.2
UGI Utilities			640.0				640.0				640.0				532.0				512.0
Other			12.9				13.3				13.7				14.2				3.2
Total debt			2,296.4				2,206.2				2,296.2				2,205.5				2,252.4
UGI Corporation stockholders’ equity			1,977.7				1,824.5				1,591.4				1,417.7				1,321.9
Noncontrolling interests, principally in AmeriGas Partners			213.4				237.1				225.4				159.2				192.2
Total capitalization		$	4,487.5			$	4,267.8			$	4,113.0			$	3,782.4			$	3,766.5
Ratio of capitalization:
Total debt			51.2	%			51.7	%			55.8	%			58.3	%			59.8	%
UGI Corporation stockholders’ equity			44.1	%			42.8	%			38.7	%			37.5	%			35.1	%
Noncontrolling interests, principally in AmeriGas Partners			4.7	%			5.5	%			5.5	%			4.2	%			5.1	%
			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

We recorded net income attributable to UGI Corporation in Fiscal 2011 of $232.9 million, equal to $2.06 per diluted share, compared to net income attributable to UGI Corporation in Fiscal 2010 of $261.0 million, equal to $2.36 per diluted share. Results in Fiscal 2011 include an after-tax loss of $10.3 million ($0.09 per diluted share) associated with AmeriGas Partners’ extinguishments of Senior Notes and an after-tax loss of $3.9 million ($0.03 per diluted share) from currency hedges associated with funding a portion of UGI’s acquisition of certain of Shell’s European LPG businesses in October 2011. Fiscal 2011 net income also includes $9.4 million ($0.08 per diluted share) from the reversal at Antargaz of a nontaxable reserve associated with the French Competition Authority Matter. Net income attributable to UGI Corporation in Fiscal 2010 includes a $17.2 million after-tax gain ($0.16 per diluted share) from the sale of Energy Services’ subsidiary, Atlantic Energy, LLC (“Atlantic Energy”), and a $3.3 million after-tax loss ($0.03 per diluted share) from the discontinuance of Partnership interest rate hedges.

Fiscal 2011 net income attributable to UGI Corporation includes greater net income from our Gas Utility principally the result of colder Fiscal 2011 heating-season weather and the regulatory effects of greater state tax depreciation. The increase in Gas Utility net income, however, was more than offset by lower net income from our International Propane segment. Significantly warmer late winter and spring weather at Antargaz resulted in an early end to the heating season. In addition, average unit margins at Antargaz, primarily during the first quarter of Fiscal 2011, were negatively impacted by rapidly rising LPG product costs. Excluding the impacts on AmeriGas Propane’s results of the previously mentioned loss on extinguishments of debt in Fiscal 2011 and the loss on the interest rate hedges in Fiscal 2010, Fiscal 2011 AmeriGas Propane net income attributable to UGI Corporation was comparable with Fiscal 2010. AmeriGas Propane volumes sold were negatively affected by significantly warmer than normal late 2011 winter weather in our southern regions and continued customer conservation. Midstream & Marketing’s Fiscal 2011 contribution to net income attributable to UGI Corporation was slightly above Fiscal 2010 (after adjusting for the Fiscal 2010 gain from the sale of Atlantic Energy) principally reflecting greater contributions from its energy peaking business, natural gas storage and natural gas marketing activities and greater tax benefits associated with solar energy projects. Income from these activities was largely offset by lower contribution from electricity generation assets.

We believe that each of our business units has sufficient liquidity in the form of revolving credit facilities, and in the case of Energy Services also an accounts receivable securitization facility, to fund business operations in Fiscal 2012. UGI Utilities, AmeriGas OLP and Antargaz entered into new credit facilities during Fiscal 2011, and Energy Services extended its receivables securitization facility through April 2012. Also, during Fiscal 2011, Flaga entered into a new multi-currency working capital facility and extended the termination dates of its two euro-based working capital facilities into Fiscal 2012. We do not have significant amounts of long-term debt maturing during Fiscal 2012.

On October 14, 2011, UGI, through subsidiaries, acquired Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden. In addition, on October 17, 2011, AmeriGas Partners announced that it had reached a definitive agreement to acquire the retail propane business of Energy Transfer Partners, comprising the third largest retail propane distributor in the United States, for total consideration of approximately $2.9 billion in cash and AmeriGas Partners Common Units. For more information on these transactions, see “Subsequent Events” below and Note 22 to UGI’s Consolidated Financial Statements.

Looking ahead, our results in Fiscal 2012 will be influenced by a number of factors including heating-season temperatures in our business units, the level and volatility of commodity prices for natural gas, LPG, electricity and oil and economic conditions in the U.S. and Europe. During the last year, we took a number of steps to set the stage for accelerating growth in the future including the transfer of CPG Gas underground natural gas storage assets to our Midstream & Marketing business, the completion of the conversion and expansion of the Hunlock Creek gas-fired electricity generating station, the October 2011 consummation of the Shell LPG acquisition in Europe, and the Partnership’s agreement to acquire Heritage Propane from Energy Transfer Partners which we hope to close by March 31, 2012. In addition, at our Midstream & Marketing business we began work on our Auburn gathering system in the Marcellus Shale region in northern Pennsylvania and we are continuing our efforts to complete the expansion of our Temple, Pennsylvania, LNG plant during Fiscal 2012. The growth from these initiatives will not be fully realized in Fiscal 2012 due to the timing of their completion and the timing of integration activities relating to the acquired businesses. In particular, the impact of the anticipated acquisition of the retail propane business of Energy Transfer Partners on Fiscal 2012 results will depend upon when the transaction closes given the size of the acquisition and the seasonality of the business.

Results of Operations

The following analyses compare the Company’s results of operations for (1) Fiscal 2011 with Fiscal 2010 and (2) Fiscal 2010 with the year ended September 30, 2009 (“Fiscal 2009”).

Fiscal 2011 Compared with Fiscal 2010

Consolidated Results

Net Income (Loss) Attributable to UGI Corporation by Business Unit:

																		Variance - Favorable
		2011								2010								(Unfavorable)
						% of								% of								% of
(Millions of dollars)		Amount				Total				Amount				Total				Amount				Total
AmeriGas Propane		$	39.9				17.1	%		$	47.3				18.1	%		$	(7.4	)			(15.6	)%
International Propane			41.0				17.6	%			58.8				22.5	%			(17.8	)			(30.3	)%
Gas Utility			99.3				42.6	%			83.1				31.8	%			16.2				19.5	%
Electric Utility			5.7				2.5	%			6.8				2.6	%			(1.1	)			(16.2	)%
Midstream & Marketing			52.5				22.5	%			68.2				26.1	%			(15.7	)			(23.0	)%
Corporate & Other			(5.5	)			(2.3	)%			(3.2	)			(1.1	)%			(2.3	)			N.M.
Net income attributable to UGI Corporation		$	232.9				100.0	%		$	261.0				100.0	%		$	(28.1	)			(10.8	)%

N.M. — Variance is not meaningful.

Highlights — Fiscal 2011 versus Fiscal 2010

•

Gas Utility results in Fiscal 2011 reflect the benefits of colder heating-season weather. Gas Utility results in Fiscal 2011 also include lower state income tax expense resulting from the regulatory effects of greater state tax depreciation.

•

Antargaz’ Fiscal 2011 results were negatively affected by warmer than normal late winter and spring weather resulting in an early end to the heating season. Antargaz’ results also include $9.4 million from the reversal of a nontaxable reserve associated with the French Competition Authority Matter. Antargaz results in Fiscal 2011 were approximately $7.3 million lower than in Fiscal 2010 due to year-over-year differences in euro to dollar currency rates.

•

AmeriGas Propane Fiscal 2011 results include a $10.3 million after-tax loss on extinguishments of debt while Fiscal 2010 results include a $3.3 million after-tax loss on interest rate hedges.

•

Midstream & Marketing net income was lower in Fiscal 2011 as Fiscal 2010 included a $17.2 million after-tax gain from the sale of Atlantic Energy.

										Increase
AmeriGas Propane		2011				2010				(Decrease)
(Millions of dollars)
Revenues		$	2,538.0			$	2,320.3			$	217.7				9.4	%
Total margin (a)		$	932.7			$	925.2			$	7.5				0.8	%
Partnership EBITDA (b)		$	297.1			$	321.0			$	(23.9	)			(7.4	)%
Operating income		$	242.9			$	235.8			$	7.1				3.0	%
Retail gallons sold (millions)			874.2				893.4				(19.2	)			(2.1	)%
Degree days – % (warmer) than normal (c)			(1.0	)%			(2.3	)%			—				—

Based upon heating degree-day data, average temperatures in the Partnership’s service territories were 1.0% warmer than normal during Fiscal 2011 compared with weather that was approximately 2.3% warmer than normal in Fiscal 2010. Retail propane gallons sold declined principally due to the effects of an early end to the heating season in our southern regions, customer conservation and the impact on AmeriGas Propane’s prior-year volumes of a strong crop-drying season partially offset by volumes acquired through acquisitions.

Retail propane revenues increased $177.3 million during Fiscal 2011 reflecting higher average retail sales prices ($220.2 million) partially offset by lower retail volumes sold ($42.9 million). Wholesale propane revenues increased $24.4 million principally reflecting higher wholesale selling prices ($29.9 million) partially offset by slightly lower wholesale volumes sold ($5.5 million). Average wholesale propane prices at Mont Belvieu, Texas, a major supply location in the U.S., were approximately 27% higher in Fiscal 2011 compared with average wholesale propane prices during Fiscal 2010. Revenues from fee income and ancillary sales and services increased $16.0 million in Fiscal 2011. Total cost of sales increased $210.2 million, to $1,605.3 million, principally reflecting the higher Fiscal 2011 wholesale propane product costs.

Total margin was $7.5 million higher in Fiscal 2011 as higher non-propane margin from fee income and certain ancillary sales and services was offset in part by lower retail propane total margin ($2.9 million). The lower retail propane total margin reflects the effects of the lower retail volumes sold ($17.5 million) partially offset by the effects of slightly higher average retail unit margins ($14.6 million).

The $23.9 million decrease in EBITDA during Fiscal 2011 includes (1) losses on the extinguishments of Partnership Senior Notes ($38.1 million) and (2) modestly higher operating and administrative expenses ($10.9 million). The negative effects of these items on the change in Partnership EBITDA were partially offset by (1) the absence of a $12.2 million loss recorded in Fiscal 2010 resulting from the discontinuance of interest rate hedges; (2) higher other income ($5.7 million); and (3) the previously mentioned greater total margin ($7.5 million). The higher operating and administrative expenses in Fiscal 2011 principally includes greater compensation and benefits expenses ($13.2 million) and vehicle fuel expenses ($8.3 million) partially offset by lower self-insured liability and casualty expenses ($6.3 million).

Operating income (which excludes the loss on extinguishments of debt) increased $7.1 million in Fiscal 2011 principally reflecting (1) the previously mentioned higher total margin ($7.5 million); (2) the absence of the loss on interest rate hedges recorded in Fiscal 2010 ($12.2 million); and (3) the higher other income ($5.7 million) partially offset by the higher operating and administrative expenses ($10.9 million) and greater depreciation and amortization ($7.3 million).

										Increase
International Propane		2011				2010				(Decrease)
(Millions of euros) (a)
Revenues		€	1,059.6			€	763.1			€	296.5				38.9	%
Total margin (b)		€	371.7			€	345.8			€	25.9				7.5	%
Operating income		€	72.0			€	82.4			€	(10.4	)			(12.6	)%
Income before income taxes		€	51.2			€	62.2			€	(11.0	)			(17.7	)%
(Millions of dollars) (a)
Revenues		$	1,488.7			$	1,059.5			$	429.2				40.5	%
Total margin (b)		$	517.9			$	477.4			$	40.5				8.5	%
Operating income		$	86.1			$	117.0			$	(30.9	)			(26.4	)%
Income before income taxes		$	57.0			$	89.5			$	(32.5	)			(36.3	)%
Antargaz retail gallons sold			270.5				279.9				(9.4	)			(3.4	)%
Antargaz degree days – % (warmer) than normal (c)			(7.8	)%			(0.5	)%			—				—
Flaga retail gallons sold			159.2				70.4				88.8				126.1	%
Flaga degree days – % (warmer) than normal (c)			(4.6	)%			(0.5	)%			—				—

Based upon heating degree-day data, temperatures in Antargaz’ service territory were approximately 7.8% warmer than normal and warmer than Fiscal 2010. Temperatures in Flaga’s service territory were also warmer than normal and warmer than the prior year. Antargaz’ retail volumes declined principally due to the warmer Fiscal 2011 weather and, to a lesser extent, price-induced customer conservation resulting from higher year-over-year LPG product prices. LPG wholesale product prices rose rapidly principally during the first quarter of Fiscal 2011 compared with more gradual price increases during Fiscal 2010. Based upon posted wholesale LPG prices in Northwest Europe, Fiscal 2011 average euro-based propane and butane costs were approximately 29% higher than in Fiscal 2010. The significant increase in Flaga’s Fiscal 2011 retail gallons sold reflects the effects of acquisitions made in late Fiscal 2010 and early Fiscal 2011.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. The dollar was generally stronger during the 2011 heating season months and weaker during the remainder of Fiscal 2011. The effects of these differences in exchange rates reduced Antargaz Fiscal 2011 net income compared to last year by approximately $7.3 million or 6 cents per diluted share.

International Propane euro base-currency revenues increased €296.5 million or 38.9% reflecting higher revenues from Antargaz (€117.0 million) and Flaga (€179.5 million). The increase in Antargaz revenues principally reflects the effects of (1) higher average retail selling prices (€80.2 million) and (2) higher wholesale revenues (€48.7 million). The higher Flaga revenues reflect the effects of the previously mentioned acquisitions and higher average retail prices. The higher average retail prices resulted from the previously mentioned year-over-year increase in wholesale LPG product costs. In U.S. dollars, revenues increased $429.2 million or 40.5% principally reflecting the previously mentioned higher euro base-currency revenues. International Propane’s euro base-currency total cost of sales increased to €687.9 million in Fiscal 2011 from €417.3 million in Fiscal 2010 principally reflecting (1) the higher LPG product costs and (2) the greater Flaga retail volumes sold and Antargaz wholesale volumes sold. On a U.S. dollar basis, cost of sales increased to $970.8 million in Fiscal 2011 from $582.1 million in Fiscal 2010 period principally reflecting the higher euro base-currency LPG commodity costs and the previously mentioned higher Flaga retail and Antargaz wholesale volumes sold.

International Propane euro-denominated total margin increased €25.9 million or 7.5% in Fiscal 2011 reflecting higher total margin from Flaga (€41.9 million) partially offset by lower total margin from Antargaz (€16.0 million). The increase in Flaga’s total margin reflects the greater retail gallons sold. The decrease in Antargaz’ total margin principally reflects the lower total volumes and the effects of rapidly rising LPG product costs on unit margins primarily during the first quarter of Fiscal 2011. U.S dollar total margin increased $40.5 million or 8.5% principally reflecting the previously mentioned higher euro base-currency total margin.

International Propane euro base-currency operating income decreased €10.4 million principally reflecting the lower total margin at Antargaz (€16.0 million) and lower operating income at Flaga (€1.9 million) offset by the reversal of the nontaxable reserve at Antargaz associated with the French Competition Authority Matter (€7.1 million). At Flaga, the higher euro base-currency total margin (€41.9 million) was offset by higher operating, administrative and depreciation expenses (€41.7 million) principally associated with the acquired businesses. U.S. dollar based operating income and income before income taxes decreased $30.9 million and $32.5 million, respectively, principally reflecting (1) the decline in euro base-currency operating income; (2) the combined effects of the stronger dollar during the Fiscal 2011 heating-season and the weaker dollar during the second half of Fiscal 2011; and (3) a $6.1 million pre-tax loss on currency hedges used to economically hedge the U.S. dollar amount of a substantial portion of the euro-denominated purchase price of the October 14, 2011, acquisition of Shell’s European LPG businesses.

										Increase
Gas Utility		2011				2010				(Decrease)
(Millions of dollars)
Revenues		$	1,026.4			$	1,047.5			$	(21.1	)			(2.0	)%
Total margin (a)		$	415.8			$	394.1			$	21.7				5.5	%
Operating income		$	199.6			$	175.3			$	24.3				13.9	%
Income before income taxes		$	159.2			$	134.8			$	24.4				18.1	%
System throughput – billions of cubic feet (“bcf”)			173.2				153.9				19.3				12.5	%
Degree days – % colder (warmer) than normal (b)			3.5	%			(4.5	)%			—				—

Temperatures in the Gas Utility service territory based upon heating degree days were 3.5% colder than normal in Fiscal 2011 compared with temperatures that were 4.5% warmer than normal in Fiscal 2010. Total distribution system throughput increased 19.3 bcf reflecting higher throughput to certain low-margin interruptible delivery service customers, the effects of the colder weather on core market and delivery service customers and, to a lesser extent, customer growth from conversion activity. Gas Utility’s core-market customers are comprised of firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.

Gas Utility revenues in Fiscal 2011 were lower than in the prior year principally reflecting a decline in revenues from core-market customers ($33.4 million) partially offset by a $14.7 million increase in revenues from low-margin off-system sales. The decrease in core market revenues principally resulted from lower average retail core market PGC rates reflecting lower natural gas prices ($83.5 million) offset by the effects of the higher throughput. 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 $610.6 million in Fiscal 2011 compared with $653.4 million in Fiscal 2010 principally reflecting the lower average PGC rates offset in part by an increase in retail core-market sales.

Gas Utility total margin increased $21.7 million in Fiscal 2011. The increase is largely the result of a $21.8 million increase in core market margin reflecting the increase in core market throughput.

Gas Utility operating income and income before income taxes in Fiscal 2011 increased $24.3 million and $24.4 million, respectively, principally the result of the previously mentioned increase in total margin ($21.7 million) and higher other income ($4.7 million) including a $3.2 million postretirement benefit plan curtailment gain. These increases were partially offset by slightly higher operating and administrative expenses including higher pension expense.

										Increase
Electric Utility		2011				2010				(Decrease)
(Millions of dollars)
Revenues		$	109.1			$	120.2			$	(11.1	)			(9.2	)%
Total margin (a)		$	35.1			$	36.5			$	(1.4	)			(3.8	)%
Operating income		$	11.4			$	13.7			$	(2.3	)			(16.8	)%
Income before income taxes		$	9.0			$	11.9			$	(2.9	)			(24.4	)%
Distribution sales – millions of kilowatt hours (“gwh”)			994.7				972.6				22.1				2.3	%

Electric Utility’s kilowatt-hour sales in Fiscal 2011 were 2.3% higher than in Fiscal 2010 on heating degree day weather that was 7.8% colder. Notwithstanding the effects of the colder weather, Electric Utility revenues decreased $11.1 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity generation portion of their service and, to a much lesser extent, lower average default service (“DS”) rates compared to the provider of last resort (“POLR”) rates that were in effect through December 31, 2009. Under DS rates, Electric Utility is no longer subject to electricity price and congestion cost risk as it is permitted to pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility no longer recovers revenues in excess of actual costs of electricity as was possible under POLR rates and therefore does not earn margin on default service sales. Electric Utility cost of sales declined to $67.9 million in Fiscal 2011 compared to $77.1 million in Fiscal 2010 principally reflecting the effects of the previously mentioned electricity generation supplier customer switching and lower DS rates.

Electric Utility total margin declined $1.4 million in Fiscal 2011, notwithstanding the greater sales, principally reflecting the absence of margin from sales of electricity beginning January 1, 2010.

Electric Utility Fiscal 2011 operating income and income before income taxes declined $2.3 million and $2.9 million, respectively, principally reflecting the previously mentioned lower total margin, higher operating and maintenance expenses and, with respect to income before income taxes, higher allocated interest expense.

										Increase
Midstream & Marketing		2011				2010				(Decrease)
(Millions of dollars)
Revenues		$	1,059.7			$	1,145.9			$	(86.2	)			(7.5	)%
Total margin (a)		$	139.7			$	135.2			$	4.5				3.3	%
Operating income		$	82.9			$	120.0			$	(37.1	)			(30.9	)%
Income before income taxes		$	80.2			$	119.8			$	(39.6	)			(33.1	)%

Midstream & Marketing total revenues decreased $86.2 million in Fiscal 2011 principally due to (1) the absence of revenues from Atlantic Energy’s import and transshipment facility ($90.8 million) and (2) lower total revenues from natural gas marketing activities ($46.9 million) attributable to lower natural gas prices. These decreases in revenues were partially offset principally by an increase in retail power sales revenues ($39.3 million) and incremental natural gas storage revenues ($7.9 million).

Fiscal 2011 total margin from Midstream & Marketing was modestly higher than in Fiscal 2010 as greater natural gas storage income ($8.4 million), energy peaking margin ($4.6 million), and natural gas and retail power marketing margin ($5.7 million) was offset by lower electric generation total margin ($9.7 million) and the absence of margin from Atlantic Energy ($8.0 million). The decrease in electric generation total margin principally reflects lower spot prices for electricity, increased coal costs at the Conemaugh electricity generating station and lower margin from UGID’s Hunlock Creek electricity generating station. The Hunlock Creek coal-fired generating station ceased operations in May 2010 to transition to a natural gas-fired generating station. The natural gas-fired generating station at Hunlock Creek commenced operations in July 2011. Due to an accident in late July 2011, one unit at Hunlock Creek was shut down for repair and is expected to restart in the spring of 2012. Another unit at Hunlock Creek suffered flood damage during the fourth quarter of Fiscal 2011 and restarted in early November 2011.

The significant decrease in Midstream & Marketing’s operating income principally reflects the absence of the pre-tax gain from the Fiscal 2010 sale of Atlantic Energy ($36.5 million). The decline in income before income taxes reflects the decrease in operating income and greater interest expense ($2.5 million) principally the result of the change in accounting for Energy Services’ Receivables Facility and fees and charges associated with Energy Services’ new credit agreement (see Notes 3 and 18 to Consolidated Financial Statements).

Interest Expense and Income Taxes. Our consolidated interest expense was modestly higher in Fiscal 2011 principally reflecting higher Midstream & Marketing interest expense, due in part to the change in accounting for the Energy Services’ Receivables Facility, and higher Antargaz long-term debt interest expense partially offset by lower interest expense on Partnership debt from lower interest rates on refinanced long-term debt. Our effective income tax rate was lower in Fiscal 2011, reflecting the effects of (1) the impact of federal tax credits associated with solar energy projects; (2) the reversal of the $9.4 million nontaxable reserve associated with the French Competition Authority Matter at Antargaz; and (3) a reduction in UGI Utilities’ income taxes reflecting the regulatory effects of greater state tax depreciation (as further described below under “Utility Matters”).

Fiscal 2010 Compared with Fiscal 2009 Consolidated Results

Net Income (Loss) Attributable to UGI Corporation by Business Unit:

		2010								2009								Variance - Favorable (Unfavorable)
						% of								% of								% of
(Millions of dollars)		Amount				Total				Amount				Total				Amount				Total
AmeriGas Propane		$	47.3				18.1	%		$	65.0				25.1	%		$	(17.7	)			(27.2	)%
International Propane			58.8				22.5	%			78.3				30.3	%			(19.5	)			(24.9	)%
Gas Utility			83.1				31.8	%			70.3				27.2	%			12.8				18.2	%
Electric Utility			6.8				2.6	%			8.0				3.1	%			(1.2	)			(15.0	)%
Midstream & Marketing			68.2				26.1	%			38.1				14.7	%			30.1				79.0	%
Corporate & Other			(3.2	)			(1.1	)%			(1.2	)			(0.4	)%			(2.0	)			N.M.
Net income attributable to UGI Corporation		$	261.0				100.0	%		$	258.5				100.0	%		$	2.5				1.0	%

N.M. — Variance is not meaningful.

Highlights — Fiscal 2010 versus Fiscal 2009

	•		Gas Utility results in Fiscal 2010 reflect the full-year impact of the PNG Gas and CPG Gas August 2009 base rate revenue increases.
	•		Midstream & Marketing’s Fiscal 2010 net income includes a $17.2 million after-tax gain on the sale of Midstream & Marketing’s Atlantic Energy subsidiary.
	•		AmeriGas Propane Fiscal 2010 results include a $3.3 million after-tax loss on interest rate hedges while Fiscal 2009 results include a $10.4 million after-tax gain from the sale of its California LPG storage terminal.
	•		Fiscal 2010 International Propane results reflect lower average unit margins compared with the higher than normal unit margins in Fiscal 2009.
	•		Midstream & Marketing’s Fiscal 2010 results benefited from greater natural gas and retail power margin.
	•		The lingering effects of the global economic recession continued to impact overall business activity in all of our business units.

										Increase
AmeriGas Propane		2010				2009				(Decrease)
(Millions of dollars)
Revenues		$	2,320.3			$	2,260.1			$	60.2				2.7	%
Total margin (a)		$	925.2			$	943.6			$	(18.4	)			(1.9	)%
Partnership EBITDA (b)		$	321.0			$	381.4			$	(60.4	)			(15.8	)%
Operating income		$	235.8			$	300.5			$	(64.7	)			(21.5	)%
Retail gallons sold (millions)			893.4				928.2				(34.8	)			(3.7	)%
Degree days – % (warmer) than normal (c)			(2.3	)%			(3.1	)%			—				—

Based upon heating degree-day data, average temperatures in our service territories were 2.3% warmer than normal during Fiscal 2010 compared with temperatures in the prior year that were 3.1% warmer than normal. Fiscal 2010 retail gallons sold were lower reflecting, among other things, the lingering effects of the economic recession, customer conservation and customer attrition partially offset by volumes acquired through business acquisitions.

Retail propane revenues increased $20.2 million during Fiscal 2010 reflecting an increase as a result of higher average retail sales prices ($94.3 million) partially offset by lower retail volumes sold ($74.1 million). Wholesale propane revenues increased $46.7 million principally reflecting higher year-over-year wholesale selling prices ($37.5 million) and, to a lesser extent, higher wholesale volumes sold ($9.2 million). Average wholesale propane prices at Mont Belvieu, Texas, were approximately 47% higher during Fiscal 2010 compared with average wholesale propane prices during Fiscal 2009. The lower average wholesale propane prices in Fiscal 2009 principally resulted from a precipitous decline in prices that occurred during the first quarter of Fiscal 2009. Other revenues decreased $6.7 million in Fiscal 2010 compared with Fiscal 2009. Total cost of sales increased $78.6 million, to $1,395.1 million, principally reflecting the higher 2010 wholesale propane product costs.

Total margin was $18.4 million lower in Fiscal 2010 primarily due to lower total retail margin ($21.9 million). The lower total retail margin reflects the effects of the lower retail volumes sold ($31.4 million) partially offset by the effects of slightly higher average retail unit margins ($9.5 million) including higher unit margins in our AmeriGas Cylinder Exchange program.

The $60.4 million decrease in Partnership EBITDA during Fiscal 2010 reflects (1) the absence of a pre-tax gain recorded in Fiscal 2009 associated with the November 2008 sale of the Partnership’s California LPG storage facility ($39.9 million); (2) the previously mentioned decline in Fiscal 2010 total margin ($18.4 million); and (3) a loss from the discontinuance of interest rate hedges ($12.2 million). During the three months ended March 31, 2010, the Partnership’s management determined that it was likely that it would not issue $150 million of long-term debt during the summer of 2010 due to the Partnership’s strong cash flow and anticipated extension of all or a portion of the 2009 Supplemental Credit Agreement. As a result, the Partnership discontinued cash flow hedge accounting treatment for interest rate protection agreements associated with this previously anticipated debt issuance and recorded a $12.2 million loss which is reflected in other income,  net, on the Fiscal 2010 Consolidated Statement of Income. These previously mentioned declines in EBITDA were partially offset by a decrease in operating and administrative expenses ($5.4 million) largely due to lower self-insured liability and casualty expenses ($9.2 million) and lower compensation and benefits expense ($4.7 million) partially offset by an increase in a litigation accrual recorded during the fourth quarter of Fiscal 2010 ($7.0 million).

Operating income in Fiscal 2010 decreased $64.7 million reflecting the previously mentioned decrease in Partnership EBITDA ($60.4 million) and slightly higher depreciation and amortization expense associated with fixed assets acquired during the past year ($3.6 million). Partnership interest expense was $5.2 million lower in Fiscal 2010 principally reflecting lower interest expense on lower long-term debt outstanding.

										Increase
International Propane		2010				2009				(Decrease)
(Millions of euros) (a)
Revenues		€	763.1			€	712.7			€	50.4				7.1	%
Total margin (b)		€	345.8			€	392.7			€	(46.9	)			(11.9	)%
Operating income		€	82.4			€	116.3			€	(33.9	)			(29.1	)%
Income before income taxes		€	62.2			€	95.3			€	(33.1	)			(34.7	)%
(Millions of dollars) (a)
Revenues		$	1,059.5			$	955.3			$	104.2				10.9	%
Total margin (b)		$	477.4			$	525.8			$	(48.4	)			(9.2	)%
Operating income		$	117.0			$	151.4			$	(34.4	)			(22.7	)%
Income before income taxes		$	89.5			$	122.0			$	(32.5	)			(26.6	)%
Antargaz retail gallons sold			279.9				289.3				(9.4	)			(3.2	)%
Degree days – % (warmer) than normal (c)			(0.5	)%			(2.9	)%			—				—

International Propane operating results in Fiscal 2010 reflect the full-year consolidation of Zentraleuropa LPG Holdings GmbH (“ZLH”). In January 2009, Flaga purchased for cash consideration the 50% equity interest in ZLH it did not already own. International Propane acquisitions completed during Fiscal 2010 did not have a material effect on results of operations.

Based upon heating degree day data, temperatures in Antargaz’ service territory were 0.5% warmer than normal during Fiscal 2010 compared with temperatures that were 2.9% warmer than normal during Fiscal 2009. Temperatures in Flaga’s service territory were slightly colder than the prior year. The average wholesale commodity price for propane and butane in northwest Europe during Fiscal 2010 was approximately 48% higher than prices during Fiscal 2009. The lower average LPG wholesale prices in the prior-year period reflect precipitous declines in propane and butane wholesale prices principally during the first quarter of Fiscal 2009. Antargaz’ Fiscal 2010 retail propane volumes were lower than in the prior-year period principally as a result of reduced demand for crop drying earlier in Fiscal 2010 which was the result of an exceptionally dry 2009 summer, the effects of customer conservation and the lingering effects of the economic recession in France.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. During Fiscal 2010, the un-weighted average currency translation rate was $1.36 per euro compared to a rate of $1.35 per euro during Fiscal 2009, although the dollar was generally weaker than the euro during the peak earnings months of October to March in Fiscal 2010. The differences in exchange rates did not have a material impact on International Propane net income.

International Propane euro-based revenues increased €50.4 million or 7.1%. The higher Fiscal 2010 revenues principally resulted from the higher Fiscal 2010 wholesale LPG product costs. U.S. dollar revenues increased $104.2 million or 10.9% principally reflecting the higher euro-based revenues. International Propane’s euro-based total cost of sales increased to €417.3 million in Fiscal 2010 from €320.0 million in the prior year, an increase of 30.4%, reflecting the higher per-unit LPG commodity costs. U.S. dollar cost of sales increased to $582.1 million in Fiscal 2010 from $429.5 million in Fiscal 2009, an increase of 35.5%, principally reflecting the higher euro base-currency cost of sales.

International Propane euro-denominated total margin decreased €46.9 million or 11.9% in Fiscal 2010 principally reflecting lower Antargaz total margin (€49.7 million) reflecting the effects of lower average Antargaz retail unit margins (€37.8 million) and, to a much lesser extent, the lower Antargaz retail gallons sold (€10.3 million). Antargaz’ euro-denominated retail unit margins were lower in Fiscal 2010 compared with Fiscal 2009 as the prior-year unit margins were higher than normal due to the rapid and sharp decline in LPG commodity costs that occurred as Antargaz entered the Fiscal 2009 winter heating season. U.S. dollar total margin decreased $48.4 million or 9.2% principally reflecting the lower euro-denominated total margin.

International Propane euro base-currency operating income decreased €33.9 million or 29.1% in Fiscal 2010 principally reflecting the previously mentioned decrease in euro-based International Propane total margin (€46.9 million) offset by the absence of a charge associated with the Antargaz Competition Authority Matter recorded in the prior year (€7.1 million) and lower total Fiscal 2010 operating and administrative expenses (€10.5 million). On a U.S. dollar basis, operating income decreased $34.4 million or 22.7% reflecting the previously mentioned decrease in U.S. dollar-denominated total margin ($48.4 million) and higher depreciation expense ($3.9 million) partially offset by the absence of the charge for the Antargaz Competition Authority Matter recorded in the prior-year period ($10.0 million) and lower total operating and administrative expenses ($9.5 million). Euro base-currency income before income taxes was €33.1 million or 34.7% lower than in the prior-year period primarily reflecting the decline in operating income (€33.9 million). U.S. dollar income before income taxes decreased $32.5 million or 26.6%.

										Increase
Gas Utility		2010				2009				(Decrease)
(Millions of dollars)
Revenues		$	1,047.5			$	1,241.0			$	(193.5	)			(15.6	)%
Total margin (a)		$	394.1			$	387.8			$	6.3				1.6	%
Operating income		$	175.3			$	153.5			$	21.8				14.2	%
Income before income taxes		$	134.8			$	111.3			$	23.5				21.1	%
System throughput - billions of cubic feet (“bcf”)			153.9				149.7				4.2				2.8	%
Degree days – % (warmer) colder than normal (b)			(4.5	)%			4.9	%			—				—

Temperatures in the Gas Utility service territory based upon heating degree days were 4.5% warmer than normal in Fiscal 2010 compared with temperatures that were 4.9% colder than normal in Fiscal 2009. Total distribution system throughput increased 4.2 bcf in Fiscal 2010, despite the warmer weather, principally reflecting an 8.5 bcf increase in low margin interruptible delivery service volumes. Gas Utility’s core market volumes decreased 6.2 bcf (9.0%) due to the previously mentioned warmer weather and to a lesser extent the sluggish economy and customer conservation.

Gas Utility revenues decreased $193.5 million during Fiscal 2010 principally reflecting a decline in revenues from retail core-market customers ($232.3 million) partially offset by a $29.4 million increase in revenues from low-margin off-system sales. The decrease in retail core-market revenues principally resulted from the effects of lower average PGC rates ($135.0 million) and the lower retail core-market volumes ($125.5 million). These decreases in revenues were partially offset by the effects of the PNG Gas and CPG Gas base operating revenue increases that became effective August 28, 2009. Gas Utility’s cost of gas was $653.4 million in Fiscal 2010 compared with $853.2 million in Fiscal 2009 principally reflecting the previously mentioned lower retail core-market sales and average PGC rates ($227.8 million) due to lower natural gas commodity prices.

Notwithstanding the decrease in distribution system volumes, Gas Utility total margin increased $6.3 million in Fiscal 2010. The increase is principally the result of the PNG Gas and CPG Gas base operating revenue increases ($28.2 million) substantially offset by the effect on total margin from the lower core-market volumes.

Gas Utility operating income in Fiscal 2010 increased $21.8 million principally reflecting lower operating and administrative costs ($15.6 million) and the previously mentioned increase in total margin ($6.3 million). Fiscal 2010 operating and administrative costs include, among other things, lower uncollectible accounts and customer assistance expenses ($11.5 million) and lower costs associated with environmental matters ($6.6 million). These decreases were partially offset by higher depreciation expense ($2.2 million) and higher pension expense ($2.1 million). The increase in income before income taxes reflects the previously mentioned higher operating income ($21.8 million) and lower interest expense ($1.6 million) due to lower average bank loan borrowings.

										Increase
Electric Utility		2010				2009				(Decrease)
(Millions of dollars)
Revenues		$	120.2			$	138.5			$	(18.3	)			(13.2	)%
Total margin (a)		$	36.5			$	39.3			$	(2.8	)			(7.1	)%
Operating income		$	13.7			$	15.4			$	(1.7	)			(11.0	)%
Income before income taxes		$	11.9			$	13.7			$	(1.8	)			(13.1	)%
Distribution sales – millions of kilowatt hours (“gwh”)			972.6				965.7				6.9				0.7	%

Temperatures based upon heating degree days in Fiscal 2010 were approximately 6.8% warmer than in Fiscal 2009. The impact on kilowatt-hour sales from the warmer heating-season weather was more than offset by higher air-conditioning related sales from significantly warmer 2010 late spring and summer weather.

Electric Utility revenues decreased $18.3 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the generation portion of their service and, to a lesser extent, lower default service (“DS”) rates effective January 1, 2010. Electric Utility decreased its DS rates effective January 1, 2010 pursuant to a January 22, 2009 settlement of its DS rate filing with the PUC. This reduced average costs to a residential general and residential heating customer by nearly 10% and 4%, respectively, over such costs in Fiscal 2009 and also reduced rates to commercial and industrial customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in excess of actual costs of electricity as was possible under previous Provider of Last Resort (“POLR”) rates in effect prior to January 1, 2010. Electric Utility cost of sales declined to $77.1 million in Fiscal 2010 compared to $91.6 million in Fiscal 2009 principally reflecting the effects of the previously mentioned generation supplier customer switching and lower purchased power costs. For additional information on Electric Utility DS and POLR service, see Note 8 to Consolidated Financial Statements.

Electric Utility total margin declined $2.8 million in Fiscal 2010 principally reflecting the reduction in margin resulting from the implementation of lower DS rates effective January 1, 2010.

Electric Utility operating income and income before income taxes in Fiscal 2010 were $1.7 million and $1.8 million lower, respectively, than in Fiscal 2009 reflecting the lower total margin ($2.8 million) partially offset by lower operating and administrative expenses ($1.1 million).

										Increase
Midstream & Marketing		2010				2009				(Decrease)
(Millions of dollars)
Revenues		$	1,145.9			$	1,224.7			$	(78.8	)			(6.4	)%
Total margin (a)		$	135.2			$	126.2			$	9.0				7.1	%
Operating income		$	120.0			$	64.8			$	55.2				85.2	%
Income before income taxes		$	119.8			$	64.8			$	55.0				84.9	%

Midstream & Marketing total revenues decreased $78.8 million in Fiscal 2010 due to lower gas marketing revenues ($114.1 million) principally from lower average natural gas prices partially offset by the effects of higher retail power sales revenues ($36.8 million).

Total margin from Midstream & Marketing increased $9.0 million principally reflecting (1) higher natural gas marketing margin ($10.5 million) due to higher natural gas marketing unit margins and (2) higher total retail power marketing margin ($7.7 million) on higher volumes sold and larger average unit margins. These increases in margin were partially offset by a decrease in electric generation total margin ($6.9 million) principally from lower average unit margins. The increase in natural gas marketing total margin includes the impact of marketing initiatives focused on the small commercial customer segment. The increases in Midstream & Marketing’s operating income and income before income taxes principally reflects a pre-tax gain from the sale of its Atlantic Energy subsidiary ($36.5 million), the previously mentioned increase in total margin ($9.0 million) and lower operating and administrative costs ($4.8 million), principally from lower total electric generation operating and maintenance costs ($5.1 million), primarily costs associated with the Hunlock coal-fired generating station which ceased operating in May 2010 as it transitioned to a gas-fired generating station.

Interest Expense and Income Taxes. Consolidated interest expense decreased modestly to $133.8 million in Fiscal 2010 from $141.1 million in Fiscal 2009 principally due to lower interest expense on AmeriGas Propane debt ($5.2 million) and lower interest on UGI Utilities revolving credit agreement borrowings ($1.6 million). Our effective income tax rate was modestly higher in Fiscal 2010 principally reflecting the effects of a lower percentage of pretax income from noncontrolling interests, principally in AmeriGas Partners, generally not subject to income taxes.

Financial Condition and Liquidity

We depend on both internal and external sources of liquidity to provide funds for working capital and to fund capital requirements. Our short-term cash requirements not met by cash from operations are generally satisfied with borrowings under credit facilities and, in the case of Midstream & Marketing, also from a receivables purchase facility. Long-term cash needs are generally met through issuance of long-term debt or equity securities.

Our cash and cash equivalents, excluding cash included in commodity futures brokerage accounts that is restricted from withdrawal, totaled $238.5 million at September 30, 2011 compared with $260.7 million at September 30, 2010. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30, 2011 and 2010 UGI had $81.4 million and $111.6 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, 2011, our 44% effective ownership interest in the Partnership consisted of approximately 24.7 million Common Units and combined 2% general partner interests. Approximately 45 days after the end of each fiscal quarter, the Partnership distributes all of its Available Cash (as defined in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, the “Partnership Agreement”) relating to such fiscal quarter. AmeriGas Propane, as general partner of AmeriGas Partners, L.P., is entitled to receive incentive distributions when AmeriGas Partners, L.P.’s quarterly distribution exceeds $0.605 per limited partner unit (see Note 14 to Consolidated Financial Statements).

During Fiscal 2011, Fiscal 2010 and Fiscal 2009, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:

Year Ended September 30,		2011				2010				2009
(Millions of dollars)
AmeriGas Propane		$	56.8			$	44.4			$	39.3
UGI Utilities			99.5				74.0				61.2
International Propane			32.9				38.8				39.0
Midstream & Marketing			30.0				32.5				—
Total		$	219.2			$	189.7			$	139.5

Dividends in Fiscal 2010 from Midstream & Marketing included proceeds from the sale of Atlantic Energy, LLC. Dividends from AmeriGas Propane in Fiscal 2009 include the benefit of a one-time $0.17 per unit increase in the August 2009 quarterly distribution resulting from the Partnership’s Fiscal 2009 sale of its California LPG storage facility (see below and Note 4 to Consolidated Financial Statements). In Fiscal 2011, Fiscal 2010 and Fiscal 2009, Midstream & Marketing received capital contributions from UGI totaling $45.7 million, $51.0 million and $46.8 million, respectively, to fund major LNG storage and electric generation capital projects as well as Marcellus Shale infrastructure projects.

On April 28, 2011, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.26 per common share or $1.04 per common share on an annual basis. This dividend reflects a 4% increase from the previous quarterly dividend rate of $0.25. The new quarterly dividend rate was effective with the dividend payable on July 1, 2011, to shareholders of record on June 15, 2011. Previously, on April 27, 2010, UGI’s Board of Directors approved a 25% increase in the quarterly dividend rate on UGI Common Stock to $0.25 per common share or $1.00 per common share on an annual basis. The new quarterly dividend rate was effective with the dividend payable on July 1, 2010 to shareholders of record on June 15, 2010. The higher than normal percentage dividend increase in Fiscal 2010 reflected our confidence in UGI’s future prospects and strong cash flows.

On April 27, 2011, the General Partner’s Board of Directors approved a quarterly distribution of $0.74 per Common Unit equal to an annual rate of $2.96 per Common Unit. This distribution reflects an approximate 5% increase from the previous quarterly rate of $0.705 per Common Unit. The new quarterly rate was effective with the distribution payable on May 18, 2011, to unitholders of record on May 10, 2011.

Long-term Debt and Credit Facilities

The Company’s debt outstanding at September 30, 2011 totaled $2,296.4 million (including current maturities of long-term debt of $47.4 million and bank loan borrowings of $138.7 million) compared to debt outstanding at September 30, 2010 of $2,206.2 million (including current maturities of long-term debt of $573.6 million and bank loan borrowings of $200.4 million). The significantly lower current maturities of long-term debt at September 30, 2011 primarily reflect the effects of the Fiscal 2011 refinancing of (1) Antargaz’ €380 million term loan ($508.7 million) and (2) one of Flaga’s euro-based term loans. Total debt outstanding at September 30, 2011 consists of (1) $1,029.0 million of Partnership debt; (2) $590.2 million (€440.9 million) of International Propane debt; (3) $640 million of UGI Utilities’ debt; (4) $24.3 million of Midstream & Marketing debt; and (5) $12.9 million of other debt. For a detailed description of the Company’s debt, see below and Note 5 to Consolidated Financial Statements.

Due to the seasonal nature of the Company’s businesses, operating cash flows are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the first and fourth fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest. AmeriGas Propane and UGI Utilities primarily use bank loans to satisfy their seasonal operating cash flow needs. Energy Services historically has used its Receivables Facility to satisfy its operating cash flow needs. Energy Services also has a three-year $170 million credit facility which it can use for working capital and general corporate purposes. During Fiscal 2011, Fiscal 2010 and Fiscal 2009, Antargaz generally funded its operating cash flow needs without using its revolving credit facilities.

AmeriGas Partners. AmeriGas Partners’ total debt at September 30, 2011 includes $920 million of AmeriGas Partners’ Senior Notes, $13.5 million of other long-term debt and $95.5 million of AmeriGas OLP bank loan borrowings.

In January 2011, AmeriGas Partners issued $470 million principal amount of 6.50% Senior Notes due May 2021 (the “6.50% Senior Notes”). The proceeds from the issuance of the 6.50% Senior Notes were used in February 2011 to repay AmeriGas Partners’ $415 million principal amount of its 7.25% Senior Notes due May 2015 pursuant to a tender offer and subsequent redemption. In addition, in February 2011, AmeriGas Partners redeemed the outstanding $14.6 million principal amount of its 8.875% Senior Notes due May 2011. The Partnership incurred a loss of $18.8 million on these extinguishments of debt which amount is reflected on the Fiscal 2011 Consolidated Statement of Income under the caption “Loss on extinguishments of debt.”

In August 2011, AmeriGas Partners issued $450 million principal amount of 6.25% Senior Notes due August 2019 (the “6.25% Senior Notes”). The proceeds from the issuance of the 6.25% Senior Notes were used to repay AmeriGas Partners’ $350 million principal amount of its 7.125% Senior Notes due May 2016 pursuant to a tender offer and subsequent redemption. The Partnership incurred a loss of $19.3 million on this extinguishment of debt which amount is also reflected on the Fiscal 2011 Consolidated Statement of Income under the caption “Loss on extinguishments of debt.”

AmeriGas OLP has a $325 million unsecured credit agreement (“2011 AmeriGas Credit Agreement”) which expires on October 15, 2015. Concurrently with entering into the 2011 AmeriGas Credit Agreement on June 21, 2011, AmeriGas OLP terminated its then-existing $200 million revolving credit agreement dated as of November 6, 2006 and its $75 million credit agreement dated as of April 17, 2009.

At September 30, 2011 and 2010, there were $95.5 million and $91 million of borrowings outstanding under AmeriGas OLP credit agreements at average interest rates of 2.29% and 1.31%, respectively. Borrowings under AmeriGas OLP credit agreements are classified as bank loans on the Consolidated Balance Sheets. Issued and outstanding letters of credit under AmeriGas OLP credit agreements, which reduce the amount available for borrowings, totaled $35.7 million at September 30, 2011 and 2010. The average daily and peak bank loan borrowings outstanding under AmeriGas OLP credit agreements during Fiscal 2011 were $151.1 million and $235 million, respectively. The average daily and peak bank loan borrowings outstanding under AmeriGas OLP credit agreements during Fiscal 2010 were $43.9 million and $135 million, respectively.

Based upon existing cash balances, cash expected to be generated from operations and borrowings available under the 2011 AmeriGas Credit Agreement, the Partnership’s management believes that the Partnership will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2012 except for cash needs related to the acquisition of the retail propane business of Energy Transfer Partners, which will be financed separately (see “Subsequent Events” below).

International Propane. International Propane’s total debt at September 30, 2011 includes $508.7 million (€380 million) outstanding under Antargaz’ 2011 Senior Facilities term loan and a combined $59.1 million (€44.2 million) outstanding under Flaga’s term loans. Total International Propane debt outstanding at September 30, 2011 also includes (1) combined borrowings of $18.9 million (€14.1 million) outstanding under Flaga’s working capital facilities and (2) $3.5 million (€2.6 million) of other long-term debt.

Antargaz. In March 2011, Antargaz entered into a new five-year variable-rate term loan agreement with a consortium of banks (“2011 Senior Facilities Agreement”). The proceeds from the new term loan were used in March 2011 to repay Antargaz’ existing Senior Facilities Agreement borrowings.

The 2011 Senior Facilities Agreement consists of (1) a €380 million variable-rate term loan and (2) a €40 million revolving credit facility. Scheduled maturities under the term loan are €38 million due May 2014, €34.2 million due May 2015, and €307.8 million due March 2016. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of approximately 3.71% through the date of the term loan’s final maturity in March 2016. At September 30, 2011, the effective interest rate on Antargaz’ term loan was 4.66%. UGI has guaranteed up to €100 million of payments under the 2011 Senior Facilities Agreement.

Antargaz’ management believes that it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2012 with cash generated from operations and borrowings under its 2011 Senior Facilities Agreement.

Flaga. In September 2011, Flaga entered into a €40 million euro-based term loan of which €26.7 million matures in August 2016 and €13.3 million matures in September 2016. This term loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin. Flaga has effectively fixed the euribor component of its interest rate on this term loan through September 2016 at 2.68% by entering into interest rate swap agreements. The effective interest rate on this term loan at September 30, 2011 was 4.76%. The proceeds of the €40 million term loan were used to repay €21 million of maturing term loan debt.

Flaga also has a euro-based variable-rate term loan which had an outstanding principal balance of €4.2 million ($5.6 million) on September 30, 2011. Semi-annual principal payments of €0.7 million are due on December 31 and June 30 each year through June 2014. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 2.16% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2011 was 5.04%.

At September 30, 2011, Flaga GmbH has three principal working capital facilities comprising (1) a €46 million multi-currency working capital facility which includes an uncommitted €6 million overdraft facility (the “Flaga 2011 Multi-currency Working Capital Facility”) and (2) two euro-denominated working capital facilities that provide for borrowings and issuances of guarantees totaling €12 million (the “Euro Facilities”). The Flaga 2011 Multi-currency Working Capital Facility expires in September 2014 and the Euro Facilities expire in March 2012. At September 30, 2011 and 2010, there were €4.3 million ($5.7 million) and €9.8 million ($13.4 million) of borrowings outstanding under Flaga multi-currency working capital facilities, respectively, and €8.0 million ($10.7 million) and €7.9 million ($10.8 million) of borrowings outstanding under euro-denominated working capital facilities, respectively. These amounts are reflected as “Bank loans” on the Consolidated Balance Sheets.

At September 30, 2011 and 2010, the weighted-average interest rates on Flaga’s working capital facilities were 3.39% and 3.64%, respectively. Issued and outstanding guarantees, which reduce available borrowings under these facilities, totaled €12.1 million ($16.2 million) at September 30, 2011. The average daily and peak bank loan borrowings outstanding under Flaga working capital facilities during Fiscal 2011 were €16.4 million and €18.0 million, respectively. The average daily and peak bank loan borrowings outstanding under Flaga working capital facilities during Fiscal 2010 were €12.7 million and €17.8 million, respectively.

Based upon cash generated from operations and borrowings under its existing or new working capital facilities, Flaga’s management believes it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2012.

UGI Utilities. UGI Utilities’ total debt at September 30, 2011 includes long-term debt comprising $383 million of Senior Notes and $257 million of Medium-Term Notes. There were no amounts outstanding at September 30, 2011, under UGI Utilities 2011 Revolving Credit Agreement.

On May 25, 2011, UGI Utilities entered into an unsecured, revolving credit agreement (the “UGI Utilities 2011 Credit Agreement”) with a group of banks providing for borrowings up to $300 million (including a $100 million sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2011 Credit Agreement, UGI Utilities terminated its then-existing $350 million revolving credit agreement dated as of August 11, 2006. The UGI Utilities 2011 Credit Agreement expires in May 2012 but may be extended to October 2015 if UGI Utilities satisfies certain requirements relating to approval by the PUC. Borrowings under the UGI Utilities 2011 Credit Agreement are classified as bank loans. During Fiscal 2011 and Fiscal 2010, average daily bank loan borrowings were $17.6 million and $69.9 million, respectively, and peak bank loan borrowings totaled $90 million and $217 million, respectively.

Based upon cash expected to be generated from Gas Utility and Electric Utility operations and borrowings available under the UGI Utilities 2011 Revolving Credit Agreement, UGI Utilities’ management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2012.

Midstream & Marketing. Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $170 million (including a $50 million sublimit for letters of credit) which expires in August 2013. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries and to fund dividend payments provided that, after giving effect to such dividend payments, Energy Services maintains a specified ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement. Borrowings outstanding under the Energy Services Credit Agreement totaled $10 million at September 30, 2011. There were no borrowings under this facility during Fiscal 2010.

Energy Services also has a $200 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper. The Receivables Facility expires in April 2012, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility’s back-up purchasers. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes. Energy Services intends to extend its Receivables Facility prior to its scheduled expiration in April 2012.

Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Through September 30, 2010, this two-step transaction was accounted for as a sale of receivables following GAAP for accounting for transfers and servicing of financial assets and extinguishments of liabilities. Effective October 1, 2010, the Company adopted a new accounting standard that changed the accounting for the Receivables Facility. Beginning October 1, 2010, trade receivables transferred to the commercial paper conduit remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the commercial paper conduit. Additionally, beginning October 1, 2010 the Company records interest expense on amounts owed to the commercial paper conduit.

At September 30, 2011, the outstanding balance of ESFC trade receivables was $52.1 million and there was $14.3 million that was sold to the commercial paper conduit and reflected in bank loans on the Consolidated Balance Sheet. At September 30, 2010, the outstanding balance of ESFC trade receivables was $44.0 million which is net of $12.1 million that was sold to the commercial paper conduit and removed from the balance sheet in accordance with GAAP in effect prior to October 1, 2010. During Fiscal 2011 and Fiscal 2010, peak sales of receivables were $31.7 million and $45.7 million, respectively, and average daily amounts sold were $1.3 million and $8.5 million, respectively.

Based upon cash expected to be generated from operations, borrowings available under the Energy Services Credit Agreement and Receivables Facility, and capital contributions from UGI, management believes that Energy Services will be able to meet its anticipated contractual and projected cash needs during Fiscal 2012.

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.

Cash flow provided by operating activities was $554.7 million in Fiscal 2011, $598.8 million in Fiscal 2010 and $665.0 million in Fiscal 2009. Cash flow from operating activities before changes in operating working capital was $697.6 million in Fiscal 2011, $663.8 million in Fiscal 2010 and $611.7 million in Fiscal 2009. Changes in operating working capital (used) provided operating cash flow of $(142.9) million in Fiscal 2011, $(65.0) million in Fiscal 2010 and $53.3 million in Fiscal 2009. Cash flow from changes in operating working capital principally reflects the impacts of changes in LPG and natural gas prices on operating working capital, primarily accounts receivable, accounts payable and inventories, and the timing and amount of natural gas cost recoveries or refunds through Gas Utility’s PGC recovery mechanism. The significantly lower Fiscal 2010 cash provided by changes in working capital compared to Fiscal 2009 reflects in large part the effects on operating working capital of an increase in LPG commodity prices in Fiscal 2010 compared to the effects on operating working capital of a significant decrease in LPG commodity prices that occurred in Fiscal 2009.

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 $415.4 million in Fiscal 2011, $399.3 million in Fiscal 2010 and $519.9 million in Fiscal 2009. Expenditures for property, plant and equipment in Fiscal 2011 and 2010 reflect greater capital expenditures associated with Midstream & Marketing’s natural gas storage and electric generation projects. Acquisitions of businesses in Fiscal 2011 include $18.5 million of International Propane acquisitions and $34.0 million of Partnership acquisitions. Acquisitions in Fiscal 2010 include $48.7 million of expenditures associated with our International Propane businesses and $34.3 million of acquisition capital expenditures at the Partnership. Acquisitions in Fiscal 2009 include UGI Utilities’ acquisition of CPG ($292.6 million). Cash from changes in restricted cash in futures brokerage accounts provided $17.6 million of cash in Fiscal 2011; used $27.8 million of cash in Fiscal 2010; and provided $63.3 million of cash in Fiscal 2009. The amount of restricted cash required in such accounts is generally the result of changes in underlying commodity prices. During Fiscal 2010, we received $66.6 million in cash proceeds from the sale of Atlantic Energy and in Fiscal 2009 the Partnership received $42.4 million of cash associated with the sale of the Partnership’s California LPG facility.

Financing Activities. Cash flow used by financing activities was $152.1 million in Fiscal 2011, $213.6 million in Fiscal 2010 and $114.6 million in Fiscal 2009. Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; net bank loan borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units and issuances of UGI and AmeriGas Partners equity instruments.

During Fiscal 2011, AmeriGas Partners redeemed $415 million principal amount of 7.25% AmeriGas Partners Senior Notes due 2015 and $14.6 million principal amount of its 8.875% Senior Notes due May 2011 with proceeds from the issuance of $470 million principal amount of 6.50% AmeriGas Partners Senior Notes due 2021. Also during Fiscal 2011, AmeriGas Partners redeemed $350 million principal amount of its 7 1/8% Senior Notes due 2016 with proceeds from the issuance of $450 million principal amount of its 6.25% Senior Notes due 2019. A portion of the proceeds from the issuances of the senior Notes were also used to reduce AmeriGas OLP bank loan borrowings. Repayments of AmeriGas Partners debt includes $30.6 million of transaction fees and expenses associated with these extinguishments. At our International Propane operations, Antargaz repaid its maturing €380 million Senior Facilities Agreement borrowings with the proceeds from its new 2011 Senior Facilities Agreement and Flaga repaid €21 million of maturing term loan debt with the proceeds from its new €40 million euro-denominated term loan. As a result of the previously mentioned change in accounting for the Energy Services Receivables Facility which became effective October 1, 2010, net cash borrowed under the Receivables Facility, which totaled $2.2 million during Fiscal 2011, are reflected in Fiscal 2011 financing activities cash flows. Before the change in accounting, these borrowings were reflected within cash flow from operating activities. In September 2010, Antargaz, in order to minimize the interest it would be required to pay under its then-existing Senior Facilities Agreement, borrowed €50 million ($68.2 million) under the Senior Facilities revolving credit facility. This amount was repaid by Antargaz in October 2010.

Capital Expenditures

In the following table, we present capital expenditures (which exclude acquisitions but include capital leases) by our business segments for Fiscal 2011, Fiscal 2010 and Fiscal 2009. We also provide amounts we expect to spend in Fiscal 2012. We expect to finance Fiscal 2012 capital expenditures principally from cash generated by operations, borrowings under credit facilities and cash on hand.

Year Ended September 30,		2012				2011				2010				2009
(Millions of dollars)		(estimate)
AmeriGas Propane		$	80.3			$	77.2			$	83.2			$	78.7
International Propane			61.3				65.4				59.0				76.3
Gas Utility			89.1				91.3				73.5				73.8
Electric Utility			5.9				7.5				8.1				5.3
Midstream & Marketing			181.2				112.8				116.4				66.2
Other			2.0				1.4				12.7				1.4
Total		$	419.8			$	355.6			$	352.9			$	301.7

The increases in Midstream & Marketing’s capital expenditures in Fiscal 2011 and Fiscal 2010 principally reflect capital expenditures related to natural gas storage and electric generation projects. These Midstream & Marketing capital expenditures were financed in large part by capital contributions from UGI and cash from operations. The decline in International Propane capital expenditures in Fiscal 2010 compared to Fiscal 2009 is principally due to lower expenditures for cylinders at Antargaz. The higher “other” capital expenditures in Fiscal 2010 principally reflect capital improvements at UGI Corporation’s headquarters’ facility following a fire.

Midstream & Marketing’s estimated capital expenditures in Fiscal 2012, principally relating to the completion of its LNG storage assets and Marcellus Shale projects, are expected to be financed principally from capital contributions from UGI and credit agreement borrowings. In 2010, the Company announced plans to invest approximately $300 million over the next few years on infrastructure projects to support the development of natural gas in the Marcellus Shale region. This anticipated investment includes enhancement of its existing underground storage fields located in north-central Pennsylvania and the construction of gas gathering facilities that would make locally produced gas available to Pennsylvania and interstate markets. The recently announced $150 million expansion of the Auburn gathering system builds on a previous investment to move gas for Citrus Energy Appalachia, LLC. The 30-mile extension will link Marcellus production to Transcontinental Gas Pipeline. The timing and extent of the Company’s investment in Marcellus infrastructure will depend on a number of factors including the timing of development of Marcellus gas production, market competition, any required regulatory approvals and construction schedules.

Contractual Cash Obligations and Commitments

The Company has contractual cash obligations that extend beyond Fiscal 2011. 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, 2011:

		Payments Due by Period
										Fiscal				Fiscal
						Fiscal				2013 -				2015 -
(Millions of dollars)		Total				2012				2014				2016				Thereafter
Long-term debt (a)		$	2,157.7			$	47.4			$	196.5			$	783.6			$	1,130.2
Interest on long-term fixed rate debt (b)			975.4				123.5				233.7				207.9				410.3
Operating leases			277.9				68.3				103.9				61.4				44.3
AmeriGas Propane supply contracts			65.8				65.8				—				—				—
International Propane supply contracts			23.3				23.3				—				—				—
Midstream & Marketing supply contracts			280.2				222.5				57.7				—				—
Gas Utility and Electric Utility supply, storage and transportation contracts			529.4				213.0				179.6				72.8				64.0
Derivative financial instruments (c)			47.5				40.4				7.1				—				—
Other purchase obligations (d)			36.0				36.0				—				—				—
Total		$	4,393.2			$	840.2			$	778.5			$	1,125.7			$	1,648.8

Other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2011 principally comprise refundable tank and cylinder deposits (as further described in Note 2 to Consolidated Financial Statements under the caption “Refundable Tank and Cylinder Deposits”); litigation, property and casualty liabilities and obligations under environmental remediation agreements (see Note 15 to Consolidated Financial Statements); pension and other postretirement benefit liabilities recorded in accordance with accounting guidance relating to employee retirement plans (see Note 7 to Consolidated Financial Statements); and liabilities associated with executive compensation plans (see Note 13 to Consolidated Financial Statements). These liabilities are not included in the table of Contractual Cash Obligations and Commitments because they are estimates of future payments and not contractually fixed as to timing or amount. We believe we will be required to make contributions to UGI Utilities’ pension plan (as further described below under “U.S. Pension Plans”) in Fiscal 2012 of approximately $27.6 million. Contributions to the pension plan in years beyond Fiscal 2012 will depend in large part on future returns on pension plan assets. Certain of our operating lease arrangements, primarily vehicle leases with remaining lease terms of one to ten years, have residual value guarantees. Although such fair values at the end of the leases have historically exceeded the guaranteed amount, at September 30, 2011, the maximum potential amount of future payments under lease guarantees assuming the leased equipment was deemed worthless was approximately $9.0 million. In addition, at September 30, 2011, we are committed to invest an additional $8.5 million in a limited partnership that focuses on investments in the alternative energy sector.

Energy Services is evaluating the feasibility of constructing natural gas pipelines in the Marcellus Shale gas production region of north-central Pennsylvania. In some instances, these pipeline projects involve potential partners who share in the development and marketing costs.

See “Subsequent Events” below regarding completed or pending acquisitions and their impact on our cash obligations.

Significant Dispositions and Acquisitions

On July 30, 2010, Energy Services sold all of its interest in its second-tier, wholly owned subsidiary, Atlantic Energy, to DCP Midstream Partners, L.P. for $49.0 million cash plus an amount for inventory and other working capital. Atlantic Energy owns and operates a 20 million gallon marine import and transshipment facility located in the port of Chesapeake, Virginia. The Company recorded a $36.5 million pre-tax gain on the sale which amount is included in “Other income, net” in the Fiscal 2010 Consolidated Statement of Income. The gain increased Fiscal 2010 net income attributable to UGI Corporation by $17.2 million or $0.16 per diluted share.

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

On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated above-ground LPG storage facility located on leased property in California for net cash proceeds of $42.4 million. The gain from the sale increased net income attributable to UGI Corporation by $10.4 million or $0.10 per diluted share.

Antargaz Competition Authority Matter

On July 21, 2009, Antargaz received a Statement of Objections (“Statement”) from France’s Autorité de la concurrence (“Competition Authority”) with respect to the investigation of Antargaz by the General Division of Competition, Consumption and Fraud Punishment. The Statement alleged that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through 2004. 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 is reflected in “Other income, net” on the Fiscal 2009 Consolidated Statement of Income. On December 17, 2010, the Competition Authority issued its decision dismissing all objections against Antargaz. The appeal period has expired without an appeal having been filed. As a result of the decision, during the three-month period ended December 31, 2010, the Company reversed its previously recorded nontaxable accrual for this matter which increased Fiscal 2011 net income by $9.4 million.

U.S. Pension Plans

In the U.S., we currently sponsor one defined benefit pension plan for employees hired prior to January 1, 2009 of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“Pension Plan”). Effective December 31, 2010, UGI Utilities merged its then-existing two defined benefit pension plans. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans. The Antargaz plans’ assets and benefit obligations are not material. The Pension Plan, and the other U.S. pension plan that existed prior to the plan merger, are hereafter referred to as the “U.S. Pension Plans.”

The fair value of the U.S. Pension Plans’ assets totaled $289.8 million and $287.9 million at September 30, 2011 and 2010, respectively. At September 30, 2011 and 2010, the underfunded positions of the U.S. Pension Plans, defined as the excess of the projected benefit obligations (“PBOs”) over the U.S. Pension Plans’ assets, were $167.0 million and $177.1 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 U.S. Pension Plans during Fiscal 2012 of approximately $27.6 million. Pre-tax pension cost associated with the U.S. Pension Plans in Fiscal 2011 was $13.9 million. Pre-tax pension cost associated with the U.S. Pension Plans in Fiscal 2012 is expected to be approximately $15.3 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. Through September 30, 2011, we have recorded cumulative after-tax charges to UGI Corporation’s stockholders’ equity of $12.1 million and recorded regulatory assets totaling $154.1 million in order to reflect the funded status of our pension and other postretirement benefit plans. For a more detailed discussion of the Pension Plans and other postretirement benefit plans, see Note 7 to Consolidated Financial Statements.

Related Party Transactions

During Fiscal 2011, Fiscal 2010 and Fiscal 2009, we did not enter into any related-party transactions that had a material effect on our financial condition, results of operations or cash flows.

Off-Balance-Sheet Arrangements

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

Gas Utility

On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5 million annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. On August 11, 2011, the PUC approved the settlement agreement which resulted in an increase in annual base rate revenues of $8.0 million as well as $0.9 million in revenues per year for use in CPG’s Energy and Efficiency Conservation Program. The increase became effective August 30, 2011, and did not have a material effect on Fiscal 2011 results.

On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011, the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9 million. Compliance with the provisions of the PUC Order approving the transfer of the storage assets is not expected to have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.

On December 1, 2010, PNG filed an application with the PUC for expedited review and approval of the transfer of a 9 mile natural gas pipeline, related facilities, and right of way located in Mehoopany, Pennsylvania (the “Auburn Line”) to Energy Services. The PUC approved the transfer and in September 2011 the Auburn Line was dividended to UGI and subsequently contributed to Energy Services. The net book value of the Auburn Line was $1.1 million.

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 increase in annual base operating revenue for PNG Gas and a $10.0 million increase in annual base operating revenue for CPG Gas. The increases became effective August 28, 2009.

Electric Utility

Prior to January 1, 2010, the terms and conditions under which Electric Utility POLR service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006. In accordance with the POLR Settlement, Electric Utility could increase its POLR rates up to certain limits through December 31, 2009. Beginning January 1, 2010, Electric Utility operates under a DS rate mechanism approved by the PUC that allows for full recovery of all DS costs incurred on and after January 1, 2010.

UGI Utilities Income Taxes

In 2010, U.S. federal tax legislation was enacted that allows taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010, through the end of calendar 2011, when such property is placed in service before 2012. In accordance with existing Pennsylvania tax statutes, Pennsylvania taxpayers are also permitted to fully deduct such qualifying capital expenditures for Pennsylvania state corporate net income tax purposes. Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits from accelerated tax depreciation. UGI Utilities’ Fiscal 2011 effective tax rate reflects the beneficial effects of this greater state tax depreciation. The additional state and federal tax depreciation deductions described above reduce federal and state income taxes otherwise payable and increase UGI Utilities deferred income tax liabilities.

Manufactured Gas Plants

UGI Utilities

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 million and $1.1 million, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. 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, 2011, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $17.9 million. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of 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 (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG Gas and PNG Gas are currently getting regulatory recovery of estimated environmental and remediation costs associated with Pennsylvania sites. At September 30, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

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

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

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 communicated the results of its research to DEC in January 2009 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 matters referenced 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.

Subsequent Events

European LPG Acquisitions. On October 14, 2011, UGI, through subsidiaries, acquired Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden for approximately €130 million in cash, subject to working capital adjustments. The acquired businesses delivered a combined approximately 300 million gallons of LPG in 2010. The purchase price for these businesses was funded principally from existing cash at UGI and the return of cash capital contributions by Midstream & Marketing to UGI from borrowings under the Energy Services Credit Agreement. These cash capital contributions had previously been made by UGI to fund major Midstream & Marketing capital projects.

Proposed AmeriGas Acquisition of the Propane Operations of Energy Transfer Partners. On October 17, 2011, AmeriGas Partners announced that it had reached a definitive agreement to acquire the propane operations of Energy Transfer Partners, L.P. (“Energy Transfer”) for total consideration of approximately $2.9 billion, including $1.5 billion in cash, AmeriGas Partners Common Units valued at approximately $1.3 billion at the time of the execution of the agreement, and the assumption of $71 million in debt (the “Acquisition”). Energy Transfer conducts its propane operations in 41 states through its subsidiaries Heritage Operating, L.P. and Titan Energy Partners, L.P. (collectively, “Heritage Propane”). According to LP-Gas Magazine rankings, Heritage Propane is the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers. The acquisition of Heritage Propane is subject to customary closing conditions, including approval under the Hart-Scott-Rodino Act. AmeriGas Partners’ obligation to complete the Acquisition is also conditioned on it obtaining debt financing on certain agreed upon terms. In addition to new debt financing, the Partnership expects to increase the size of the AmeriGas 2011 Credit Agreement to at least $500 million upon closing of the transaction. The agreement contains termination rights for both parties. Under certain conditions, termination by AmeriGas Partners could result in the payment of a termination fee of up to $125 million. AmeriGas Partners expects to complete the Acquisition by March 31, 2012.

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 as further described below. Antargaz has used over-the-counter derivative commodity instruments and may from time-to-time enter into other derivative contracts, similar to those used by the Partnership. Flaga has used and may use derivative commodity instruments to reduce market risk associated with a portion of its LPG purchases. Over-the-counter derivative commodity instruments used 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 periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism.

Electric Utility’s DS tariffs contain clauses which permit recovery of all prudently incurred power costs through the application of DS rates. Because of this ratemaking mechanism, beginning January 1, 2010 there is limited power cost risk associated with our Electric Utility operations.

In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at September 30, 2011 were not material.

Midstream & Marketing purchases financial transmission rights (“FTRs”) to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. In addition, beginning April 1, 2011, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Although Midstream & Marketing’s FTRs and NYMEX futures contracts associated with the purchase and anticipated later sale of natural gas and propane are generally effective as economic hedges, they do not currently qualify for hedge accounting treatment.

In order to manage market price risk relating to substantially all of Midstream & Marketing’s fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas and electricity futures contracts or enters into fixed-price supply arrangements. Midstream & Marketing also uses NYMEX and over the counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. Midstream & Marketing’s exchange-traded natural gas and electricity futures contracts are traded on the NYMEX and have nominal credit risk. Although Midstream & Marketing’s fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas or electricity would adversely impact Midstream & Marketing’s results. In order to reduce this risk of supplier nonperformance, Midstream & Marketing has diversified its purchases across a number of suppliers. Midstream & Marketing has entered into and may continue to enter into fixed-price sales agreements for a portion of its propane sales. In order to manage the market price risk relating to substantially all of its fixed-price sales contracts for propane, Midstream & Marketing enters into price swap and option contracts.

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

Interest Rate Risk

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

Our variable-rate debt includes bank loan borrowings and Antargaz’ and Flaga’s variable-rate term loans. These debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz and Flaga have effectively fixed the underlying euribor interest rates on their term loans through their scheduled maturity dates through the use of interest rate swaps. At September 30, 2011 combined borrowings outstanding under these variable-rate debt agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate term loan debt, totaled $138.7 million. Excluding Antargaz’ and Flaga’s effectively fixed-rate term loan debt and based upon average borrowings outstanding under remaining variable-rate borrowings, an increase in short-term interest rates of 100 basis points (1%) would have increased our Fiscal 2011 and Fiscal 2010 interest expense by approximately $2.0 million and $1.3 million, respectively. The remainder of our debt outstanding is subject to fixed rates of interest. A 100 basis point increase in market interest rates would result in decreases in the fair value of this fixed-rate debt of $104.1 million and $94.7 million at September 30, 2011 and 2010, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $96.1 million and $104.8 million at September 30, 2011 and 2010, respectively.

Long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce interest rate risk associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”).

Foreign Currency Exchange Rate Risk

Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Realized gains or losses on net investment hedges remain in accumulated other comprehensive income until such foreign operations are liquidated. At September 30, 2011, the fair value of unsettled net investment hedges was a gain of $1.1 million. With respect to our net investments in our International Propane operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value at September 30, 2011 by approximately $76.9 million, which amount would be reflected in other comprehensive income.

In addition, in order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar denominated LPG product purchases during the months of October through March through the use of forward foreign exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% — 30% of estimated dollar-denominated purchases to occur during the heating-season months of October to March.

In October 2011, the Company acquired certain European LPG businesses from Shell. In September 2011, in order to economically hedge the U.S. dollar amount of a substantial portion of the associated euro-denominated purchase price, we entered into foreign currency exchange contracts. These contracts are recorded at fair value with gains or losses recorded in other income (expense). At September 2011, we were hedging a total of €60 million of the euro-denominated purchase price. Losses recorded on acquisition purchase price hedge contracts through September 30, 2011 totaled $6.1 million.

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 large 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 forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts generally require cash deposits in margin accounts. Declines in natural gas, LPG and electricity product costs can require our business units to post collateral with counterparties or make margin deposits to brokerage accounts. At September 30, 2011 and 2010, restricted cash in brokerage accounts totaled $17.2 million and $34.8 million, respectively.

The following table summarizes the fair values of unsettled market risk sensitive derivative instruments assets and (liabilities) held at September 30, 2011 and 2010. The table also includes the changes in fair value that would result if there were a 10% adverse change in (1) the market prices of commodity derivative instruments including the market prices of LPG, gasoline, natural gas, electricity and electricity transmission congestion charges; (2) the three-month and one-month Euribor rates; and (3) the value of the euro versus the U.S. dollar. Gas Utility’s and Electric Utility’s derivative instruments other than gasoline futures and swap contracts are excluded from the table below because any associated net gains or losses are refundable to or recoverable from customers in accordance with Gas Utility and Electric Utility ratemaking.

		Asset (Liability)
						Change in
(Millions of dollars)		Fair Value				Fair Value
September 30, 2011:
Commodity price risk		$	(25.6	)		$	(35.3	)
Interest rate risk			(44.4	)			(8.2	)
Foreign currency exchange rate risk			1.9				(16.5	)
September 30, 2010:
Commodity price risk		$	(37.2	)		$	(40.2	)
Interest rate risk			(18.5	)			(3.7	)
Foreign currency exchange rate risk			(2.2	)			(12.5	)

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

Critical Accounting Policies and Estimates

The preparation of financial statements and related disclosures in compliance with GAAP requires the selection and application of accounting principles appropriate to the relevant facts and circumstances of the Company’s operations and the use of estimates made by management. The Company has identified the following critical accounting policies and estimates that are most important to the portrayal of the Company’s financial condition and results of operations. Changes in these policies and estimates could have a material effect on the financial statements. The application of these accounting policies and estimates necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements. Management has reviewed these critical accounting policies, and the estimates and assumptions associated with them, with the Company’s Audit Committee. In addition, management has reviewed the following disclosures regarding the application of these critical accounting policies and estimates with the Audit Committee.

Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation regarding pending claims and legal actions that arise in the normal course of our businesses. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere, and PNG Gas and CPG Gas owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with GAAP, 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, 2011, our regulatory assets totaled $300.4 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, 2011, our net property, plant and equipment totaled $3,204.5 million and we recorded depreciation expense of $201.2 million during Fiscal 2011. As of September 30, 2011, our net intangible assets other than goodwill totaled $147.8 million and we recorded amortization expense on intangible assets of $20.4 million during Fiscal 2011.

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, 2011, our goodwill totaled $1,562.2 million. We did not record any impairments of goodwill in Fiscal 2011, Fiscal 2010 and Fiscal 2009. The Company will adopt new accounting guidance regarding goodwill impairment in Fiscal 2012 (see Note 3 to Consolidated Financial Statements).

Pension Plan Assumptions. The cost of providing benefits under the U.S. 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 U.S. 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 U.S. Pension Plans assets of 50 basis points to a rate of 7.5% would result in an increase in pre-tax pension cost of approximately $1.6 million in Fiscal 2012. A decrease in the discount rate of 50 basis points to a rate of 4.8% would result in an increase in pre-tax pension cost of approximately $2.8 million in Fiscal 2012.

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. Positions taken by an entity in its tax returns must satisfy a more-likely-than-not recognition threshold assuming the positions 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, 2011, our net deferred tax liabilities totaled $664.3 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 2011 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 by reference.

ITEM 8.		FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None.

ITEM 9A.		CONTROLS AND PROCEDURES

(a)

The Company’s disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including the Chief Executive Officer and Principal Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, with the participation of the Company’s Chief Executive Officer and Principal 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 Principal Financial Officer concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were effective at the reasonable assurance level.

(b)

For “Management’s Report on Internal Control over Financial Reporting” see Item 8 of this Report (which information is incorporated herein by reference).

(c)

No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B.		OTHER INFORMATION

None.

PART III:

ITEMS 10 THROUGH 14.

In accordance with General Instruction G(3), and except as set forth below, the information required by Items 10, 11, 12, 13 and 14 is incorporated in this Report by reference to the following portions of UGI’s Proxy Statement, which will be filed with the Securities and Exchange Commission by December 31, 2011.

				Captions of Proxy Statement
		Information		Incorporated by Reference
Item 10.		Directors, Executive Officers and Corporate Governance		Election of Directors — Nominees; Corporate Governance; Board Independence; Board Committees; Communications with the Board; Audit Committee; Securities Ownership of Management — Section 16(a) — Beneficial Ownership Reporting Compliance; Report of the Audit Committee of the Board of Directors
		The Code of Ethics for the Chief Executive Officer and Senior Financial Officers of UGI Corporation is available without charge on the Company’s website, www.ugicorp.com or by writing to Hugh J. Gallagher, 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 Independence and Board Committees; Policy for Approval of Related Person Transactions
Item 14.		Principal Accounting Fees and Services		Our Independent Registered Public Accounting Firm

Equity Compensation Table

The following table sets forth information as of the end of Fiscal 2011 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			7,595,679	(1)		$	25.69				2,618,351
			900,283	(2)		$	0
Equity compensation plans not approved by security holders			77,500	(3)		$	12.13
Total			8,573,462			$	25.55	(4)