UGI CORP /PA/ - Annual Report: 2011 (Form 10-K)

Form 10-K

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

(Exact name of registrant as specified in its charter)


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

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

(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


(1)		Cubic meters (1 cubic meter is equivalent to approximately 264 gallons).

(2)		Pursuant to a long-term contractual arrangement with the owner.

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	)%		—		—


(a)		Total margin represents total revenues less total cost of sales.


(b)		Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America (“GAAP”). Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements). Partnership EBITDA for Fiscal 2011 includes pre-tax losses of $38.1 million associated with extinguishments of debt. Partnership EBITDA and operating income for Fiscal 2010 includes a pre-tax loss of $12.2 million associated with the discontinuance of interest rate hedges and a pre-tax loss of $7 million associated with an increase in a litigation accrual.

(c)		Deviation from average heating degree-days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska. Fiscal 2010 data has been adjusted to correct a NOAA error.

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	)%		—		—


(a)		Euro amounts represent amounts for Antargaz and Flaga. U.S. dollar amounts include Antargaz and Flaga as well as our operations in China and certain non-operating entities associated with our International Propane segment.

(b)		Total margin represents total revenues less total cost of sales.

(c)		Deviation from average heating degree days for the 30-year period 1971-2000 at locations in our French service territory.

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	)%		—		—


(a)		Total margin represents total revenues less total cost of sales.

(b)		Deviation from average heating degree days for the 15-year period 1995-2009 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

Temperatures in the Gas Utility service territory based upon heating degree days were 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	%


(a)		Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $6.1 million and $6.6 million during Fiscal 2011 and Fiscal 2010, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Consolidated Statements of Income.

Electric Utility’s kilowatt-hour sales in Fiscal 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	)%


(a)		Total margin represents total revenues less total cost of sales.

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	)%		—		—


(a)		Total margin represents total revenues less total cost of sales.

(b)		Partnership EBITDA should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under GAAP. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements). Partnership EBITDA (and operating income) in Fiscal 2010 includes a pre-tax loss associated with the discontinuance of interest rate hedges and a loss of $7 million associated with an increase in a litigation accrual. Partnership EBITDA (and operating income) in Fiscal 2009 includes a pre-tax gain of $39.9 million associated with the sale of the Partnership’s California LPG storage facility.


(c)		Deviation from average heating degree-days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska. Fiscal 2010 data has been adjusted to correct a NOAA error.

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	)%		—		—


(a)		Euro amounts represent amounts for Antargaz and Flaga. U.S. dollar amounts include Antargaz and Flaga as well as our operations in China and certain non-operating entities associated with our International Propane segment.

(b)		Total margin represents total revenues less total cost of sales.

(c)		Deviation from average heating degree days for the 30-year period 1971-2000 at locations in our French service territory.

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

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

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

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	%		—		—


(a)		Total margin represents total revenues less total cost of sales.

(b)		Deviation from average heating degree days for the 15-year period 1995—2009 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

Temperatures in the Gas Utility service territory based upon heating degree days were 4.5% 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	%


(a)		Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $6.6 million and $7.6 million during Fiscal 2010 and Fiscal 2009, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Consolidated Statements of Income.

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

Electric Utility revenues decreased $18.3 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the generation portion of their service and, to a lesser extent, lower default service (“DS”) rates effective January 1, 2010. Electric Utility decreased its DS rates effective January 1, 2010 pursuant to a January 22, 2009 settlement of its DS rate filing with the PUC. This reduced average costs to a residential general and residential heating customer by nearly 10% and 4%, respectively, over such costs in Fiscal 2009 and also reduced rates to commercial and industrial customers. 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	%


(a)		Total margin represents total revenues less total cost of sales.

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

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


(a)		Based upon stated maturity dates.

(b)		Based upon stated interest rates adjusted for the effects of interest rate swaps.

(c)		Represents the sum of amounts due from us if derivative financial instrument liabilities were settled at the September 30, 2011 amounts reflected in the Consolidated Balance Sheet (but excluding amounts associated with interest rate swaps).

(d)		Includes material capital expenditure obligations.

Other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 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

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)


(1)		Represents 7,595,679 stock options under the 2000 Directors’ Stock Incentive Plan and the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006.

(2)		Represents 900,283 phantom share units under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006.

(3)		Column (a) represents 77,500 stock options under the 2002 Non-Qualified Stock Option Plan. Under the 2002 Non-Qualified Stock Option Plan, the option exercise price is not less than 100% of the fair market value of the Company’s common stock on the date of grant. Generally, options become exercisable in three equal annual installments beginning on the first anniversary of the grant date. All options are non-transferable and generally exercisable only while the holder is employed by the Company or an affiliate, with exceptions for exercise following retirement, disability and death. Options are subject to adjustment in the event of recapitalization, stock splits, mergers and other similar corporate transactions affecting the Company’s common stock.

(4)		Weighted-average exercise price of outstanding options; excludes phantom share units.

The information concerning the Company’s executive officers required by Item 10 is set forth below.

EXECUTIVE OFFICERS


Name	Age	Position
Lon R. Greenberg	61	Chairman and Chief Executive Officer
John L. Walsh	56	President, Chief Operating Officer and Principal Financial Officer
Davinder S. Athwal	44	Vice President — Accounting and Financial Control and Chief Risk Officer
Eugene V.N. Bissell	58	President and Chief Executive Officer, AmeriGas Propane, Inc.
Robert F. Beard	46	President and Chief Executive Officer, UGI Utilities, Inc.
Bradley C. Hall	58	Vice President — New Business Development
Robert H. Knauss	58	Vice President and General Counsel and Assistant Secretary
François Varagne	56	Chairman of the Board and Chief Executive Officer of Antargaz

All officers, except Mr. Varagne, are elected for a one-year term at the organizational meetings of the respective Boards of Directors held each year. Mr. Varagne was re-appointed as Chairman of the Board of Antargaz on April 1, 2010, for a term of five years. Mr. Varagne resigned effective October 12, 2011.

There are no family relationships between any of the officers or between any of the officers and any of the directors.

Lon R. Greenberg

Mr. Greenberg has been Chairman of the Board of Directors of UGI since 1996 and Chief Executive Officer since 1995. He was formerly President (1994 to 2005), Vice Chairman of the Board (1995 to 1996), and Senior Vice President — Legal and Corporate Development (1989 to 1994). Mr. Greenberg also serves as a Director of UGI Utilities, Inc., AmeriGas Propane, Inc., Aqua America, Inc. and Ameriprise Financial, Inc.

John L. Walsh

Mr. Walsh is a Director and President and Chief Operating Officer of UGI Corporation (since April 2005). In addition, Mr. Walsh serves as Vice Chairman of AmeriGas Propane, Inc. (since 2005) and UGI Utilities, Inc. (since 2005). Previously, he also served as President and Chief Executive Officer of UGI Utilities, Inc. (2009 to 2011). Mr. Walsh was the Chief Executive of the Industrial and Special Products Division of the BOC Group plc (industrial gases), a position he assumed in 2001. He was also an Executive Director of BOC (2001 to 2005). He joined BOC in 1986 as Vice President-Special Gases and held various senior management positions in BOC, including President of Process Gas Solutions, North America (2000 to 2001) and President of BOC Process Plants (1996 to 2000). Mr. Walsh also serves as a Director of UGI Utilities, Inc. and AmeriGas Propane, Inc.

Davinder S. Athwal

Mr. Athwal is Vice President — Accounting and Financial Control and Chief Risk Officer (since January 2009). He previously served as the Global Mergers & Acquisitions Controller of Nortel Networks, Inc., a global supplier of telecommunications equipment and solutions, a position in which he served since 2007. Mr. Athwal served as Director, Global Revenue Governance for Nortel Networks, Inc. from 2006 through 2007. Mr. Athwal served in both accounting and risk management roles for IBM Corporation, a globally integrated innovation and technology company (2003 to 2006).

Eugene V.N. Bissell

Mr. Bissell is President, Chief Executive Officer and a Director of AmeriGas Propane, Inc. (since July 2000), having served as Senior Vice President — Sales and Marketing (1999 to 2000) and Vice President — Sales and Operations (1995 to 1999). Previously, he was Vice President — Distributors and Fabrication, BOC Gases (1995), having been Vice President — National Sales (1993 to 1995) and Regional Vice President (Southern Region) for Distributor and Cylinder Gases Division, BOC Gases (1989 to 1993). From 1981 to 1987, Mr. Bissell held various positions with the Company and its subsidiaries, including Director, Corporate Development. Mr. Bissell is a member of the Board of Directors of the National Propane Gas Association and a member of the Kalamazoo College Board of Trustees. Mr. Bissell is planning to retire in the Spring of 2012.

Robert F. Beard

Mr. Beard is President and Chief Executive Officer of UGI Utilities, Inc. (since September 2011). He previously served as Vice President — Marketing, Rates and Gas Supply of UGI Utilities, Inc. (2010 to 2011) and Vice President — Southern Region of UGI Utilities, Inc. (2008 to 2010). From 2006 until 2008, Mr. Beard served as Vice President — Operations and Engineering of PPL Gas Utilities Corporation and, from 2002 until 2006, he also served as Director — Operations and Engineering of PPL Gas Utilities Corporation.

Bradley C. Hall

Mr. Hall is Vice President — New Business Development (since October 1994). He also serves as President of UGI Enterprises, Inc. (since 1994) and UGI Energy Services, Inc. (since 1995). He joined the Company in 1982 and held various positions in UGI Utilities, Inc., including Vice President — Marketing and Rates.

Robert H. Knauss

Mr. Knauss was elected Vice President and General Counsel and Assistant Secretary on September 30, 2003. He previously served as Vice President — Law and Associate General Counsel of AmeriGas Propane, Inc. (1996 to 2003), and Group Counsel — Propane of UGI (1989 to 1996). He joined the Company in 1985. Previously, Mr. Knauss was an associate at the firm of Ballard Spahr LLP in Philadelphia. Mr. Knauss is planning to retire in the Spring of 2012.

François Varagne

Mr. Varagne was Chairman of the Board and Chief Executive Officer of Antargaz through September 30, 2011. Mr. Varagne resigned effective October 12, 2011. Before joining Antargaz, Mr. Varagne was Chairman of the Board and Chief Executive Officer of VIA GTI, a common carrier in France (1998 to 2001). Prior to that, Mr. Varagne was Chairman of the Board and Chief Executive Officer of Brink’s France, a funds carrier (1997 to 1998).

PART IV:


ITEM 15.		EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

Documents filed as part of this report:

(1)

Financial Statements:

Included under Item 8 are the following financial statements and supplementary data:

Management’s Report on Internal Control over Financial Reporting

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of September 30, 2011 and 2010

Consolidated Statements of Income for the years ended September 30, 2011, 2010 and 2009

Consolidated Statements of Comprehensive Income for the years ended September 30, 2011, 2010 and 2009

Consolidated Statements of Cash Flows for the years ended September 30, 2011, 2010 and 2009

Consolidated Statements of Changes in Equity for the years ended September 30, 2011, 2010 and 2009

Notes to Consolidated Financial Statements

(2)

Financial Statement Schedules:

I —

Condensed Financial Information of Registrant (Parent Company)

	II —		Valuation and Qualifying Accounts for the years ended September 30, 2011, 2010 and 2009

			We have omitted all other financial statement schedules because the required information is (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.

(3)

List of Exhibits:

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):


Incorporation by Reference
Exhibit No.	Exhibit	Registrant	Filing	Exhibit

2.1	Contribution and Redemption Agreement, dated October 15, 2011, by and among AmeriGas Partners, L.P., Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P. and Heritage ETC, L.P.	AmeriGas Partners, L.P.	Form 8-K (10/15/11)		2.1

3.1	(Second) Amended and Restated Articles of Incorporation of the Company as amended through June 6, 2005	UGI	Form 10-Q (6/30/05)		3.1


Incorporation by Reference
Exhibit No.	Exhibit	Registrant	Filing	Exhibit

3.2	Bylaws of UGI as amended through September 28, 2004	UGI	Form 8-K (9/28/04)		3.2

4	Instruments defining the rights of security holders, including indentures. (The Company agrees to furnish to the Commission upon request a copy of any instrument defining the rights of holders of long-term debt not required to be filed pursuant to Item 601(b)(4) of Regulation S-K)

4.1	The description of the Company’s Common Stock contained in the Company’s registration statement filed under the Securities Exchange Act of 1934, as amended	UGI	Form 8-B/A (4/17/96)		3.(4	)

4.2	UGI’s (Second) Amended and Restated Articles of Incorporation and Bylaws referred to in 3.1 and 3.2 above

4.3	Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of July 27, 2009	AmeriGas Partners, L.P.	Form 10-Q (6/30/09)		3.1

4.4	Indenture, dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee	AmeriGas Partners, L.P.	Form 10-Q (12/31/10)		4.1

4.5	First Supplemental Indenture, dated as of January 20, 2011, to Indenture dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee	AmeriGas Partners, L.P.	Form 8-K (1/19/11)		4.1

4.6	Second Supplemental Indenture, dated as of August 10, 2011, to Indenture dated as of January 20, 2011, by and among AmeriGas Partners, L.P., AmeriGas Finance Corp. and U.S. Bank National Association, as trustee	AmeriGas Partners, L.P.	Form 8-K (8/10/11)		4.1

4.7	Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994	Utilities	Registration Statement No. 33-77514 (4/8/94)		4(c	)

4.8	Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association	Utilities	Form 8-K (9/12/06)		4.2

4.9	Form of Fixed Rate Medium-Term Note	Utilities	Form 8-K (8/26/94)		4(i	)

4.10	Form of Fixed Rate Series B Medium-Term Note	Utilities	Form 8-K (8/1/96)		4(i	)

4.11	Form of Floating Rate Series B Medium-Term Note	Utilities	Form 8-K (8/1/96)	4(ii		)


Incorporation by Reference
Exhibit No.	Exhibit	Registrant	Filing	Exhibit

4.12	Officer’s Certificate establishing Medium-Term Notes Series	Utilities	Form 8-K (8/26/94)	4(iv		)

4.13	Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture	Utilities	Form 8-K (8/1/96)	4(iv		)

4.14	Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture	Utilities	Form 8-K (5/21/02)		4.2

4.15	Forms of Floating Rate and Fixed Rate Series C Medium-Term Notes	Utilities	Form 8-K (5/21/02)		4.1

10.1**	UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006	UGI	Form 8-K (2/27/07)		10.1

10.2*	UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 — Terms and Conditions as amended and restated effective July 1, 2011

10.3**	UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees effective December 6, 2005	UGI	Form 10-K (9/30/06)		10.66

10.4**	UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers effective May 20, 2008	UGI	Form 10-Q (6/30/08)		10.1

10.5**	UGI Corporation Amended and Restated Directors’ Deferred Compensation Plan as of January 1, 2005	UGI	Form 10-K (9/30/10)		10.5

10.6**	UGI Corporation 2000 Directors’ Stock Option Plan Amended and Restated as of May 24, 2005	UGI	Form 10-K (9/30/06)		10.13

10.7**	UGI Corporation 1997 Stock Option and Dividend Equivalent Plan Amended and Restated as of May 24, 2005	UGI	Form 10-K (9/30/10)		10.7

10.8**	UGI Corporation 2000 Stock Incentive Plan Amended and Restated as of May 24, 2005	UGI	Form 10-K (9/30/06)		10.14

10.9**	UGI Corporation 2009 Deferral Plan As Amended and Restated Effective June 1, 2010	UGI	Form 10-Q (6/30/10)		10.1

10.10**	UGI Corporation Senior Executive Employee Severance Plan as in effect as of January 1, 2008	UGI	Form 10-Q (3/31/08)		10.1

10.11**	UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective January 1, 2009	UGI	Form 10-K (9/30/09)		10.11

10.12**	Amendment 2009-1 to the UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan as Amended and Restated effective January 1, 2009	UGI	Form 10-Q (12/31/09)		10.1


Incorporation by Reference
Exhibit No.	Exhibit	Registrant	Filing	Exhibit

10.13**	UGI Corporation 2009 Supplemental Executive Retirement Plan For New Employees as Amended and Restated as of October 1, 2010	UGI	Form 10-Q (12/31/09)		10.2

10.14**	UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006	UGI	Form 10-K (9/30/07)		10.8

10.15**	AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., as Amended and Restated effective January 1, 2005	AmeriGas Partners, L.P.	Form 10-K (9/30/08)		10.7

10.16**	AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. effective July 30, 2010	AmeriGas Partners, L.P.	Form 8-K (7/30/10)		10.2

10.17**	AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. effective July 30, 2010 — Terms and Conditions	AmeriGas Partners, L.P.	Form 10-K (9/30/10)		10.10

10.18**	AmeriGas Propane, Inc. Non-Qualified Deferred Compensation Plan, as Amended and Restated effective January 1, 2009	AmeriGas Partners, L.P.	Form 10-K (9/30/08)		10.44

10.19**	Letter Agreement dated May 15, 2002 regarding severance arrangement for Mr. Varagne	UGI	Form 10-K (9/30/05)		10.15

10.20**	AmeriGas Propane, Inc. Senior Executive Employee Severance Plan, as in effect January 1, 2008	AmeriGas Partners, L.P.	Form 10-K (9/30/09)		10.12

10.21**	AmeriGas Propane, Inc. Executive Employee Severance Plan, as in effect January 1, 2008	AmeriGas Partners, L.P.	Form 10-K (9/30/08)		10.4

10.22**	AmeriGas Propane, Inc. Supplemental Executive Retirement Plan, as Amended and Restated effective January 1, 2009	AmeriGas Partners, L.P.	Form 10-Q (12/31/09)		10.1

10.23**	AmeriGas Propane, Inc. Executive Annual Bonus Plan, effective as of October 1, 2006	AmeriGas Partners, L.P.	Form 10-K (9/30/07)		10.19

10.24**	Summary of Antargaz Supplemental Retirement Plans effective as of September 1, 2009	UGI	Form 10-K (9/30/09)		10.20

10.25*	UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for Non Employee Directors, dated January 7, 2011

10.26**	UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for UGI Employees, dated January 1, 2009	UGI	Form 10-Q (3/31/09)		10.8

10.27*	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 1, 2011


Incorporation by Reference
Exhibit No.	Exhibit	Registrant	Filing	Exhibit

10.28*	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2011

10.29*	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for AmeriGas Employees, dated January 1, 2011

10.30*	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Utilities Employees, dated January 1, 2011

10.31*	UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Employees, dated January 1, 2011

10.32*	UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2011

10.33*	UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Stock Option Grant Letter effective January 1, 2011

10.34*	UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Performance Unit Grant Letter effective January 1, 2011

10.35*	Description of oral compensation arrangements for Messrs. Greenberg, Knauss, Varagne and Walsh

10.36**	Description of oral compensation arrangement for Mr. Bissell	AmeriGas Partners, L.P.	Form 10-K (9/30/11)		10.26

10.37**	AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., as amended and restated effective January 1, 2005, Restricted Unit Grant Letter dated as of December 31, 2009	AmeriGas Partners, L.P.	Form 10-Q (3/31/10)		10.2

10.38**	Summary of Director Compensation as of October 1, 2010	UGI	Form 10-K (9/30/10)		10.33

10.39**	Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Messrs. Greenberg, Knauss and Walsh	UGI	Form 10-Q (6/30/08)		10.3

10.40**	Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Mr. Bissell	AmeriGas Partners, L.P.	Form 10-Q (6/30/08)		10.1


Incorporation by Reference
Exhibit No.	Exhibit	Registrant	Filing	Exhibit

10.41**	Form of Confidentiality and Post-Employment Activities Agreement with AmeriGas Propane, Inc. for Mr. Bissell	AmeriGas Partners, L.P.	Form 10-Q (3/31/05)		10.3

10.42**	Settlement Agreement dated October 12, 2011 among AGZ Holding, Antargaz and Mr. Varagne	UGI	Form 8-K (10/12/11)		10.1

10.43	Trademark License Agreement dated April 19, 1995 among UGI Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P.	UGI	Form 10-K (9/30/10)		10.37

10.44	Trademark License Agreement, dated April 19, 1995 among AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P.	AmeriGas Partners, L.P.	Form 10-Q (12/31/10)		10.1

10.45	Credit Agreement dated as of June 21, 2011 by and among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as a Guarantor, Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and Issuing Lender (“Agent”), Wells Fargo Securities, LLC, as Sole Lead Arranger and Sole Book Manager and Wells Fargo Bank, National Association, Branch Banking and Trust Company, Citibank, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, Citizens Bank of Pennsylvania, The Bank of New York Mellon, Compass Bank, Manufacturers and Traders Trust Company, Sovereign Bank, TD Bank, N.A. and the other financial institutions from time to time party thereto	AmeriGas Partners, L.P.	Form 10-Q (6/30/11)		10.2

10.46	Release of Liens and Termination of Security Documents dated as of November 6, 2006 by and among AmeriGas Propane, Inc., Petrolane Incorporated, AmeriGas Propane, L.P., AmeriGas Propane Parts & Service, Inc. and Wachovia Bank, National Association, as Collateral Agent for the Secured Creditors, pursuant to the Intercreditor and Agency Agreement dated as of April 19, 1995	AmeriGas Partners, L.P.	Form 10-K (9/30/06)		10.3

*10.47	Receivables Purchase Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 8 thereto dated April 22, 2010 and Amendment No. 9 thereto dated August 26, 2010, by and among UGI Energy Services, Inc., as servicer, Energy Services Funding Corporation, as seller, Market Street Funding, LLC, as issuer, and PNC Bank, National Association, as administrator


Incorporation by Reference
Exhibit No.	Exhibit	Registrant	Filing	Exhibit

10.48	Amendment No. 10, dated as of April 21, 2011 to Receivables Purchase Agreement, dated as of November 30, 2001(as amended, supplemented or modified from time to time), by and among UGI Energy Services, Inc. as servicer, Energy Services Funding Corporation, as seller, Market Street Funding LLC, as issuer, and PNC Bank, National Association, as administrator	UGI	Form 8-K (4/21/11)		10.1

10.49	Credit Agreement, dated as of May 25, 2011 among UGI Utilities, Inc., as borrower, and PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and RBS Citizens, N.A., as joint lead arrangers and joint bookrunners, and PNC Bank, National Association, Citizens Bank of Pennsylvania, Citibank, N.A., Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, The Bank of New York Mellon, and the other financial institutions from time to time parties thereto	Utilities	Form 8-K (5/25/11)		10.1

10.50	Purchase and Sale Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 3 thereto dated August 26, 2010, by and between UGI Energy Services, Inc. and Energy Services Funding Corporation	UGI	Form 10-K (9/30/10)		10.47

10.51	Credit Agreement, dated as of August 26, 2010, among UGI Energy Services, Inc., as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, PNC Bank, National Association, as syndication agent, and Wells Fargo Bank, National Association and Credit Suisse AG, Cayman Islands Branch, as co-documentation agents	UGI	Form 10-K (9/30/10)		10.48

10.52	Senior Facilities Agreement dated March 16, 2011 by and among AGZ Holding, as Parent and Borrower, Antargaz, as Borrower, BNP Paribas, Caisse Régionale de Crédit Agricole Mutuel de Paris et d’Ile de France, Credit Lyonnais and Natixis, as Mandated Lead Arrangers and Bookrunners, Barclays Bank PLC, Banque Commerciale pour le Marché de l’Entreprise and ING Belgium SA, Succursale en France, as Mandated Lead Arrangers, Natixis, as Facility Agent and Security Agent, Banco Bilbao Vizcaya Argentaria, Crédit du Nord, HSBC France, Crédit Suisse International, Bred Banque Populaire and Banque Palatine, as Arrangers and the Financial Institutions named therein	UGI	Form 10-Q (3/31/11)		10.1


Incorporation by Reference
Exhibit No.	Exhibit	Registrant	Filing	Exhibit

10.53	Pledge of Financial Instruments Account relating to Financial Instruments held by AGZ Holding in Antargaz, dated March 16, 2011, by and among AGZ Holding, as Pledgor, Natixis, as Security Agent and Bank Account Holder, and the Lenders, as Beneficiaries	UGI	Form 10-Q (3/31/11)		10.2

10.54	Pledge of Financial Instruments Account relating to Financial Instruments held by Antargaz in certain subsidiary companies, dated March 16, 2011, by and among Antargaz, as Pledgor, Natixis, as Security Agent and Bank Account Holder, and the Lenders, as Beneficiaries	UGI	Form 10-Q (3/31/11)		10.3

10.55	Master Agreement for Assignment of Receivables dated March 16, 2011 between AGZ Holding, as Assignor, Natixis, as Security Agent, and the Beneficiaries	UGI	Form 10-Q (3/31/11)		10.4

10.56	Master Agreement for Assignment of Receivables dated March 16, 2011 between Antargaz, as Assignor, Natixis, as Security Agent, and the Beneficiaries	UGI	Form 10-Q (3/31/11)		10.5

10.57	First Demand Guarantee dated March 16, 2011 by UGI Corporation in favor of Natixis and the Lenders set forth in the Senior Facilities Agreement dated March 16, 2011	UGI	Form 10-Q (3/31/11)		10.6

10.58	Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, Inc. effective as of May 1, 2007	Utilities	Form 10-Q (6/30/10)		10.1

10.59	Amendment No. 1 dated November 1, 2004, to the Service Agreement (Rate FSS) dated as of November 1, 1989 between Utilities and Columbia, as modified pursuant to the orders of the Federal Energy Regulatory Commission at Docket No. RS92-5-000 reported at Columbia Gas Transmission Corp., 64 FERC ¶61,060 (1993), order on rehearing, 64 FERC ¶61,365 (1993)	UGI	Form 10-K (9/30/10)		10.60

10.60	Firm Storage and Delivery Service Agreement (Rate GSS) dated July 1, 1996 between Transcontinental Gas Pipe Line Corporation and PG Energy	Utilities	Form 8-K (8/24/06)		10.8

10.61	SST Service Agreement No. 79133 dated November 1, 2004 between Columbia Gas Transmission Corporation and UGI Utilities, Inc.	Utilities	Form 10-Q (6/30/10)		10.2

10.62	FTS-1 Service Agreement No. 46283 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 between Columbia Gulf Transmission Company and UGI Utilities, Inc.	Utilities	Form 10-Q (3/31/11)		10.1


Incorporation by Reference
Exhibit No.	Exhibit	Registrant	Filing	Exhibit

10.63	FTS Service Agreement No. 46284 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004, between Columbia Transmission Corporation and UGI Utilities, Inc.	Utilities	Form 10-Q (3/31/11)		10.2

10.64	Amendment to FTS-1 Service Agreement No. 46283 and FTS Service Agreement No. 46284 each dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 dated November 1, 1993	Utilities	Form 10-Q (3/31/11)		10.3

14	Code of Ethics for principal executive, financial and accounting officers	UGI	Form 10-K (9/30/03)		14

*21	Subsidiaries of the Registrant

*23	Consent of PricewaterhouseCoopers LLP

*31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*31.2	Certification by the Principal Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*32	Certification by the Chief Executive Officer and the Principal Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS**	XBRL.Instance

101.SCH**	XBRL Taxonomy Extension Schema

101.CAL**	XBRL Taxonomy Extension Calculation Linkbase

101.DEF**	XBRL Taxonomy Extension Definition Linkbase

101.LAB**	XBRL Taxonomy Extension Labels Linkbase

101.PRE**	XBRL Taxonomy Extension Presentation Linkbase


*		Filed herewith.

**		As required by Item 14(a)(3), this exhibit is identified as a compensatory plan or arrangement.

***		XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.


	UGI CORPORATION
Date: November 21, 2011	By:	/s/ John L. Walsh
		John L. Walsh
		President and Chief Operating Officer (Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 21, 2011, by the following persons on behalf of the Registrant in the capacities indicated.


Signature				Title

/s/ Lon R. Greenberg Lon R. Greenberg				Chairman and Chief Executive Officer (Principal Executive Officer) and Director

/s/ John L. Walsh John L. Walsh				President and Chief Operating Officer (Principal Operating and Financial Officer) and Director

/s/ Davinder S. Athwal Davinder S. Athwal				Vice President — Accounting and Financial Control, Chief Risk Officer (Principal Accounting Officer)

/s/ Stephen D. Ban Stephen D. Ban				Director

/s/ Richard W. Gochnauer Richard W. Gochnauer				Director

/s/ Frank S. Hermance Frank S. Hermance				Director

/s/ Ernest E. Jones Ernest E. Jones				Director

/s/ Anne Pol Anne Pol				Director

/s/ M. Shawn Puccio M. Shawn Puccio				Director

/s/ Marvin O. Schlanger Marvin O. Schlanger				Director

/s/ Roger B. Vincent Roger B. Vincent				Director

EXHIBIT INDEX


Exhibit No.		Description
	10.2	UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 — Terms and Conditions as amended and restated effective July 1, 2011

	10.25	UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for Non Employee Directors, dated January 7, 2011

	10.27	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 1, 2011

	10.28	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2011

	10.29	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for AmeriGas Employees, dated January 1, 2011

	10.30	UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Utilities Employees, dated January 1, 2011

	10.31	UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Employees, dated January 1, 2011

	10.32	UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2011

	10.33	UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Stock Option Grant Letter effective January 1, 2011

	10.34	UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Performance Unit Grant Letter effective January 1, 2011

	10.35	Description of oral compensation arrangements for Messrs. Greenberg, Knauss, Varagne and Walsh


Exhibit No.		Description
	10.47	Receivables Purchase Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 8 thereto dated April 22, 2010 and Amendment No. 9 thereto dated August 26, 2010, by and among UGI Energy Services, Inc., as servicer, Energy Services Funding Corporation, as seller, Market Street Funding, LLC, as issuer, and PNC Bank, National Association, as administrator

	21	Subsidiaries of the Registrant

	23	Consent of PricewaterhouseCoopers LLP

	31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	31.2	Certification by the Principal Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	32	Certification by the Chief Executive Officer and the Principal Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS*		XBRL.Instance

101.SCH*		XBRL Taxonomy Extension Schema

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase

101.DEF*		XBRL Taxonomy Extension Definition Linkbase

101.LAB*		XBRL Taxonomy Extension Labels Linkbase

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase


*		XBRL information will be considered to be furnished, not filed, for the first two years of a company’s submission of XBRL information.

UGI CORPORATION AND SUBSIDIARIES

FINANCIAL INFORMATION

FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K

YEAR ENDED SEPTEMBER 30, 2011

F-1

UGI CORPORATION

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES


	Pages

Management’s Report on Internal Control over Financial Reporting		F-3

Financial Statements:

Report of Independent Registered Public Accounting Firm		F-4

Consolidated Balance Sheets as of September 30, 2011 and 2010		F-5

Consolidated Statements of Income for the years ended September 30, 2011, 2010 and 2009		F-6

Consolidated Statements of Comprehensive Income for the years ended September 30, 2011, 2010 and 2009		F-7

Consolidated Statements of Cash Flows for the years ended September 30, 2011, 2010 and 2009		F-8

Consolidated Statements of Changes in Equity for the years ended September 30, 2011, 2010 and 2009		F-9

Notes to Consolidated Financial Statements	F-10 to F-58

Financial Statement Schedules:

For the years ended September 30, 2011, 2010 and 2009:

I — Condensed Financial Information of Registrant (Parent Company)	S-1 to S-3

II — Valuation and Qualifying Accounts	S-4 to S-5

We have omitted all other financial statement schedules because the required information is either (1) not present; (2) not present in amounts sufficient to require submission of the schedule; or (3) included elsewhere in the financial statements or related notes.

F-2

Report of Management

Financial Statements

The Company’s consolidated financial statements and other financial information contained in this Annual Report are prepared by management, which is responsible for their fairness, integrity and objectivity. The consolidated financial statements and related information were prepared in accordance with accounting principles generally accepted in the United States of America and include amounts that are based on management’s best judgments and estimates.

The Audit Committee of the Board of Directors is composed of three members, none of whom is an employee of the Company. This Committee is responsible for (i) overseeing the financial reporting process and the adequacy of internal control and (ii) monitoring the independence and performance of the Company’s independent registered public accounting firm and internal auditors. The Committee is also responsible for maintaining direct channels of communication among the Board of Directors, management, and both the independent registered public accounting firm and the internal auditors.

PricewaterhouseCoopers LLP, our independent registered public accounting firm, is engaged to perform audits of our consolidated financial statements. These audits are performed in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our independent registered public accounting firm was given unrestricted access to all financial records and related data, including minutes of all meetings of the Board of Directors and committees of the Board. The Company believes that all representations made to the independent registered public accounting firm during their audits were valid and appropriate.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, management has conducted an assessment, including testing, of the Company’s internal control over financial reporting, using the criteria in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”).

Internal control over financial reporting refers to the process, designed under the supervision and participation of management including our Chief Executive Officer and our Chief Financial Officer, to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes policies and procedures that, among other things, provide reasonable assurance that assets are safeguarded and that transactions are executed in accordance with management’s authorization and are properly recorded to permit the preparation of reliable financial information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to changing conditions, or the degree of compliance with the policies or procedures may deteriorate.

Based on its assessment, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, 2011, based on the COSO Framework. PricewaterhouseCoopers LLP, our independent registered public accounting firm, audited the effectiveness of the Company’s internal control over financial reporting as of September 30, 2011, as stated in their report, which appears herein.

/s/ Lon R. Greenberg
Chief Executive Officer

/s/ John L. Walsh
Chief Financial Officer

/s/ Davinder S. Athwal
Chief Accounting Officer

F-3

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of UGI Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, changes in equity and cash flows present fairly, in all material respects, the financial position of UGI Corporation and its subsidiaries at September 30, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2011 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15 (a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers
Philadelphia, Pennsylvania
November 21, 2011

F-4

UGI CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Millions of dollars)


	September 30,
	2011			2010
ASSETS
Current assets
Cash and cash equivalents	$	238.5		$	260.7
Restricted cash		17.2			34.8
Accounts receivable (less allowances for doubtful accounts of $36.8 and $34.6, respectively)		546.7			467.8
Accrued utility revenues		14.8			14.0
Inventories		363.0			314.0
Deferred income taxes		44.9			32.6
Income taxes recoverable		19.2			20.1
Utility regulatory assets		8.6			26.1
Derivative financial instruments		10.2			11.3
Prepaid expenses and other current assets		43.0			38.7

Total current assets		1,306.1			1,220.1

Property, plant and equipment
Utilities		2,201.0			2,129.3
Non-utility		3,083.5			2,840.4

		5,284.5			4,969.7
Accumulated depreciation and amortization		(2,080.0	)		(1,929.5	)

Net property, plant, and equipment		3,204.5			3,040.2

Goodwill		1,562.2			1,562.7
Intangible assets, net		147.8			150.1
Other assets		442.7			401.2

Total assets	$	6,663.3		$	6,374.3


LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	47.4		$	573.6
Bank loans		138.7			200.4
Accounts payable		399.6			372.6
Employee compensation and benefits accrued		73.9			86.3
Deposits and advances		161.5			165.3
Derivative financial instruments		49.7			58.0
Other current liabilities		207.1			218.5

Total current liabilities		1,077.9			1,674.7

Debt and other liabilities
Long-term debt		2,110.3			1,432.2
Deferred income taxes		709.2			601.4
Deferred investment tax credits		5.0			5.3
Other noncurrent liabilities		569.8			599.1

Total liabilities		4,472.2			4,312.7

Commitments and contingencies (note 15)

Equity:
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,507,094 and 115,400,294 shares, respectively)		937.4			906.1
Retained earnings		1,085.8			966.7
Accumulated other comprehensive loss		(17.7	)		(10.1	)
Treasury stock, at cost		(27.8	)		(38.2	)

Total UGI Corporation stockholders’ equity		1,977.7			1,824.5
Noncontrolling interests, principally in AmeriGas Partners		213.4			237.1

Total equity		2,191.1			2,061.6

Total liabilities and equity	$	6,663.3		$	6,374.3

See accompanying notes to consolidated financial statements.

F-5

UGI CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Millions of dollars, except per share amounts)


	Year Ended September 30,
	2011			2010			2009
Revenues
Utilities	$	1,135.5		$	1,167.7		$	1,379.5
Non-utility and other		4,955.8			4,423.7			4,358.3

		6,091.3			5,591.4			5,737.8

Costs and Expenses
Cost of sales (excluding depreciation shown below):
Utilities		678.5			730.5			944.8
Non-utility and other		3,332.4			2,853.5			2,725.8
Operating and administrative expenses		1,266.4			1,177.4			1,220.0
Utility taxes other than income taxes		16.6			18.6			16.9
Depreciation		201.2			187.6			180.2
Amortization		26.7			22.6			20.7
Other income, net		(46.5	)		(58.0	)		(55.9	)

		5,475.3			4,932.2			5,052.5


Operating income		616.0			659.2			685.3
Loss from equity investees		(0.9	)		(2.1	)		(3.1	)
Loss on extinguishments of debt		(38.1	)		—			—
Interest expense		(138.0	)		(133.8	)		(141.1	)

Income before income taxes		439.0			523.3			541.1
Income taxes		(130.8	)		(167.6	)		(159.1	)

Net income		308.2			355.7			382.0
Less: net income attributable to noncontrolling interests, principally in AmeriGas Partners		(75.3	)		(94.7	)		(123.5	)

Net income attributable to UGI Corporation	$	232.9		$	261.0		$	258.5


Earnings per common share attributable to UGI Corporation stockholders:
Basic	$	2.09		$	2.38		$	2.38


Diluted	$	2.06		$	2.36		$	2.36


Average common shares outstanding (thousands):
Basic		111,674			109,588			108,523


Diluted		112,944			110,511			109,339

See accompanying notes to consolidated financial statements.

F-6

UGI CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Millions of dollars)


	Year Ended September 30,
	2011			2010			2009

Net income	$	308.2		$	355.7		$	382.0
Net losses on derivative instruments (net of tax of $(15.4), $(29.2) and $82.1, respectively)		(10.8	)		(16.8	)		(204.1	)
Reclassifications of net losses on derivative instruments (net of tax of $(20.4), $(25.3) and $(78.6), respectively)		11.8			22.9			225.0
Foreign currency translation adjustments (net of tax of $4.5, $7.9 and $(8.4), respectively)		(14.0	)		(39.4	)		29.5
Foreign currency gains and losses on long-term intra-company transactions (net of tax of $0.4)		(0.8	)		—			—
Benefit plans (net of tax of $(0.1), $12.7 and $31.1, respectively)		0.1			(18.7	)		(44.4	)
Reclassification of benefit plans actuarial losses and prior service costs (net of tax of $(0.4), $(2.9) and $(1.6), respectively) to net income		0.6			4.2			2.3
Reclassification of pension plans actuarial losses and prior service costs (net of tax of $(59.1)) to regulatory assets		—			83.3			—

Comprehensive income		295.1			391.2			390.3

Less: comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners		(69.8	)		(101.4	)		(155.5	)

Comprehensive income attributable to UGI Corporation	$	225.3		$	289.8		$	234.8

See accompanying notes to consolidated financial statements.

F-7

UGI CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of dollars)


	Year Ended September 30,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	308.2		$	355.7		$	382.0
Reconcile to net cash provided by operating activities:
Depreciation and amortization		227.9			210.2			200.9
Gains on sales of LPG storage facilities		—			(36.5	)		(39.9	)
Deferred income taxes, net		82.7			62.6			26.8
Provision for uncollectible accounts		20.0			27.1			34.1
Stock-based compensation expense		15.6			13.2			11.4
Net change in realized gains and losses deferred as cash flow hedges		12.2			23.8			(21.0	)
Loss on extinguishments of debt		38.1			—			—
Other, net		(7.1	)		7.7			17.4
Net change in:
Accounts receivable and accrued utility revenues		(66.0	)		(94.6	)		79.5
Inventories		(40.7	)		34.3			67.0
Utility deferred fuel costs, net of changes in unsettled derivatives		12.8			(18.5	)		10.3
Accounts payable		19.2			47.1			(146.1	)
Other current assets		(1.9	)		(9.4	)		30.3
Other current liabilities		(66.3	)		(23.9	)		12.3

Net cash provided by operating activities		554.7			598.8			665.0


CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(360.7	)		(347.3	)		(301.7	)
Acquisitions of businesses, net of cash acquired		(52.5	)		(83.0	)		(322.6	)
Net proceeds from sale of Partnership LPG storage facility		—			—			42.4
Net proceeds from sale of Atlantic Energy, LLC		—			66.6			—
Decrease (increase) in restricted cash		17.6			(27.8	)		63.3
Other, net		(19.8	)		(7.8	)		(1.3	)

Net cash used by investing activities		(415.4	)		(399.3	)		(519.9	)


CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock		(113.8	)		(98.6	)		(85.1	)
Distributions on AmeriGas Partners publicly held Common Units		(93.7	)		(89.1	)		(90.4	)
Issuances of debt		1,480.6			—			118.0
Repayments of debt		(1,383.6	)		(94.8	)		(82.2	)
Receivables Facility net borrowings		2.2			—			—
(Decrease) increase in bank loans		(74.6	)		37.9			13.1
Issuances of UGI Common Stock		27.3			27.5			10.8
Other		3.5			3.5			1.2

Net cash used by financing activities		(152.1	)		(213.6	)		(114.6	)


EFFECT OF EXCHANGE RATE CHANGES ON CASH		(9.4	)		(5.3	)		4.4


Cash and cash equivalents (decrease) increase	$	(22.2	)	$	(19.4	)	$	34.9


Cash and cash equivalents:
End of year	$	238.5		$	260.7		$	280.1
Beginning of year		260.7			280.1			245.2

(Decrease) increase	$	(22.2	)	$	(19.4	)	$	34.9


SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for:
Interest	$	135.0		$	130.5		$	136.3
Income taxes	$	48.6		$	128.5		$	130.2

See accompanying notes to consolidated financial statements.

F-8

UGI CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Millions of dollars, except per share amounts)


	Year Ended September 30,
	2011			2010			2009
Common stock, without par value
Balance, beginning of year	$	906.1		$	875.6		$	858.3
Common Stock issued:
Employee and director plans		14.7			14.4			2.9
Dividend reinvestment plan		2.2			1.7			1.6
Excess tax benefits realized on equity-based compensation		3.8			4.2			2.9
Stock-based compensation expense		10.6			10.2			9.9

Balance, end of year	$	937.4		$	906.1		$	875.6


Retained earnings
Balance, beginning of year	$	966.7		$	804.3		$	630.9
Net income attributable to UGI Corporation		232.9			261.0			258.5
Cash dividends on Common Stock ($1.02, $0.90 and $0.785 per share, respectively)		(113.8	)		(98.6	)		(85.1	)

Balance, end of year	$	1,085.8		$	966.7		$	804.3


Accumulated other comprehensive income (loss)
Balance, beginning of year	$	(10.1	)	$	(38.9	)	$	(15.2	)
Net losses on derivative instruments, net of tax		(23.4	)		(37.8	)		(127.3	)
Reclassification of net losses on derivative instruments, net of tax		29.9			37.2			116.2
Benefit plans, principally actuarial gains (losses), net of tax		0.1			(18.7	)		(44.4	)
Reclassification of benefit plans actuarial losses and prior service costs, net of tax, to net income		0.6			4.2			2.3
Reclassifications of pension plans actuarial losses and prior service cost, net of tax, to regulatory assets		—			83.3			—
Foreign currency losses on long-term intra-company transacations		(0.8	)		—			—
Foreign currency translation adjustments, net of tax		(14.0	)		(39.4	)		29.5

Balance, end of year	$	(17.7	)	$	(10.1	)	$	(38.9	)


Treasury stock
Balance, beginning of year	$	(38.2	)	$	(49.6	)	$	(56.3	)
Common Stock issued:
Employee and director plans		9.7			10.6			5.9
Dividend reinvestment plan		0.7			0.8			0.8

Balance, end of year	$	(27.8	)	$	(38.2	)	$	(49.6	)


Total UGI Corporation stockholders’ equity	$	1,977.7		$	1,824.5		$	1,591.4


Noncontrolling interests
Balance, beginning of year	$	237.1		$	225.4		$	159.2
Net income attributable to noncontrolling interests, principally in AmeriGas Partners		75.3			94.7			123.5
Net gains (losses) on derivative instruments		12.6			21.0			(76.8	)
Reclassification of net (gains) losses on derivative instruments		(18.1	)		(14.3	)		108.8
Dividends and distributions		(94.0	)		(89.1	)		(91.7	)
Other		0.5			(0.6	)		2.4

Balance, end of year	$	213.4		$	237.1		$	225.4


Total equity	$	2,191.1		$	2,061.6		$	1,816.8

See accompanying notes to consolidated financial statements.

F-9

UGI Corporation and Subsidiaries

Notes to Consolidated Financial Statements

(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Index to Notes

Note 1 — Nature of Operations

Note 2 — Significant Accounting Policies

Note 3 — Accounting Changes

Note 4 — Acquisitions and Dispositions

Note 5 — Debt

Note 6 — Income Taxes

Note 7 — Employee Retirement Plans

Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters

Note 9 — Inventories

Note 10 — Property, Plant and Equipment

Note 11 — Goodwill and Intangible Assets

Note 12 — Series Preferred Stock

Note 13 — Common Stock and Equity-Based Compensation

Note 14 — Partnership Distributions

Note 15 — Commitments and Contingencies

Note 16 — Fair Value Measurements

Note 17 — Disclosures About Derivative Instruments and Hedging Activities

Note 18 — Energy Services Accounts Receivable Securitization Facility

Note 19 — Other Income, Net

Note 20 — Quarterly Data (unaudited)

Note 21 — Segment Information

Note 22 — Subsequent Events

Note 1 — Nature of Operations

UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes and markets energy products and related services. In the United States, we own and operate (1) a retail propane marketing and distribution business; (2) natural gas and electric distribution utilities; (3) electricity generation facilities; and (4) an energy marketing, midstream infrastructure, storage and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”

We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”), a publicly traded limited partnership, and its principal operating subsidiaries, AmeriGas Propane, L.P. (“AmeriGas OLP”) and, prior to its October 1, 2010 merger with AmeriGas OLP, AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (together with AmeriGas OLP, the “Operating Partnership”). AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30, 2011, the General Partner held a 1% general partner interest and 42.8% limited partner interest in AmeriGas Partners and an effective 44.4% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners Common Units (“Common Units”). The remaining 56.2% interest in AmeriGas Partners comprises 32,433,087 Common Units held by the general public as limited partner interests.

Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries (1) conducts an LPG distribution business in France (“Antargaz”); (2) conducts an LPG distribution business in central and eastern Europe (“Flaga”); and (3) conducts an LPG distribution business in the Nantong region of China. We refer to our foreign operations collectively as “International Propane.” Enterprises, through Energy Services, Inc. (“Energy Services”) and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage and energy services business primarily in the Mid-Atlantic region of the United States. In addition, Energy Services’ wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electric generation facilities located in Pennsylvania. The businesses of Energy Services and its subsidiaries, including UGID, are referred to herein collectively as “Midstream & Marketing.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries.

F-10

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Our natural gas and electric distribution utility businesses are conducted through our wholly owned subsidiary UGI Utilities, Inc. (“UGI Utilities”) and its subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas;” PNG’s natural gas distribution utility is referred to as “PNG Gas;” and CPG’s natural gas distribution utility is referred to as “CPG Gas.” UGI Gas, PNG Gas and CPG Gas are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”

Note 2 — Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.

Certain prior-year amounts have been reclassified to conform to the current-year presentation.

Principles of Consolidation

The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the general public’s interests in the Partnership and other parties’ interests in consolidated but less than 100% owned subsidiaries as noncontrolling interests. We eliminate all significant intercompany accounts and transactions when we consolidate. Investments in business entities in which we do not have control, but have significant influence over operating or financial policies, are accounted for under the equity method of accounting and our proportionate share of income or loss is recorded in loss from equity investees on the Consolidated Statements of Income. Undistributed net earnings of our equity investees included in consolidated retained earnings were not material at September 30, 2011. Investments in business entities that are not publicly traded and in which we hold less than 20% of voting rights are accounted for using the cost method. Such investments are recorded in other assets and totaled $72.4 and $68.8 at September 30, 2011 and 2010, respectively.

On January 29, 2009, Flaga purchased for cash consideration the 50% equity interest in Zentraleuropa LPG Holdings GmbH (“ZLH”) it did not already own from its joint-venture partner, Progas GmbH & Co. KG. As a result, the operations of ZLH are consolidated with those of the Company beginning in January 2009.

Effects of Regulation

UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980 related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulator.

For additional information regarding the effects of rate regulation on our utility operations, see Note 8.

F-11

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity, foreign currency and interest rate derivative instruments. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements require that we assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

•

Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Instruments categorized in Level 1 consist of our exchange-traded commodity futures and option contracts and non exchange-traded commodity futures and non exchange-traded electricity forward contracts whose underlying is identical to an exchange-traded contract.

•

Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over the counter commodity price swap and option contracts, interest rate swaps and interest rate protection agreements, foreign currency forward contracts, financial transmission rights (“FTRs”) and non exchange-traded electricity forward contracts that do not qualify for Level 1.

•

Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at September 30, 2011 or 2010.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. See Note 16 for additional information on fair value measurements.

Derivative Instruments

We account for derivative instruments and hedging activities in accordance with guidance provided by the FASB which requires that all derivative instruments be recognized as either assets or liabilities and measured at fair value. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.

A substantial portion of our derivative financial instruments are designated and qualify as cash flow hedges or net investment hedges. In addition, gains and losses on certain derivative financial instruments used by Gas Utility and Electric Utility are included in regulatory assets or liabilities in accordance with FASB guidance regarding accounting for rate-regulated entities. For cash flow hedges, changes in the fair value of the derivative financial instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the occurrence of the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Certain of our derivative financial instruments, although generally effective as economic hedges, do not qualify for hedge accounting treatment. Changes in the fair values of these derivative instruments are reflected in net income. Cash flows from derivative financial instruments, other than net investment hedges, are included in cash flows from operating activities. Cash flows from net investment hedges are included in cash flows from investing activities.

F-12

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and related supplemental information required by GAAP, see Note 17.

Foreign Currency Translation

Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income.

Revenue Recognition

Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing records revenues when energy products are delivered or services are provided to customers. Revenues from the sale of appliances and equipment are recognized at the later of sale or installation. Revenues from repair or maintenance services are recognized upon completion of services.

UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service and commodities rendered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective.

We present revenue-related taxes collected from customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in total revenues in accordance with regulatory practice.

LPG Delivery Expenses

Expenses associated with the delivery of LPG to customers of the Partnership and our International Propane operations (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as operating and administrative expenses on the Consolidated Statements of Income. Depreciation expense associated with the Partnership and International Propane delivery vehicles is classified in depreciation on the Consolidated Statements of Income.

Income Taxes

AmeriGas Partners and the Operating Partnership are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss and (2) the differences between the book and tax basis of our investment in the Partnership. The Operating Partnership have subsidiaries which operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation.

Gas Utility and Electric Utility record deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax depreciation methods based upon amounts recognized for ratemaking purposes. They also record a deferred income tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse.

We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. Investment tax credits associated with Midstream & Marketing’s qualifying solar energy property under the Emergency Economic Stabilization Act of 2008 are reflected in income tax expense when such property is placed in service.

F-13

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income. For Fiscal 2011, Fiscal 2010 and Fiscal 2009, interest expense (income) of $0.2, $(0.2) and $(0.4), respectively, was recognized in income taxes on the Consolidated Statements of Income.

Earnings Per Common Share

Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2011, Fiscal 2010 and Fiscal 2009:


(Thousands of shares)	2011(a)		2010		2009(a)
Average common shares outstanding for basic computation		111,674		109,588		108,523
Incremental shares issuable for stock options and common stock awards		1,270		923		816

Average common shares outstanding for diluted computation		112,944		110,511		109,339


(a)		For Fiscal 2011 and Fiscal 2009, there were approximately 3,700 shares and 2,800 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share because their effect was antidilutive.

Comprehensive Income

Comprehensive income comprises net income and other comprehensive income (loss). Other comprehensive income (loss) principally results from gains and losses on derivative instruments qualifying as cash flow hedges, actuarial gains and losses on postretirement benefit plans and foreign currency translation adjustments. Other comprehensive income in Fiscal 2010 also includes the reclassification of $83.3 of actuarial losses associated with a UGI Utilities’ pension plan to regulatory assets and deferred income taxes as a result of an August 2010 PUC order regarding regulatory treatment of such pension plan’s funded status (see Note 8).

The components of AOCI at September 30, 2011 and 2010 follow:


							Foreign
				Derivative			Currency
	Postretirement			Instruments Net			Translation
	Benefit Plans			Losses			Adjustments		Total
Balance, September 30, 2011	$	(12.1	)	$	(47.6	)	$	42.0	$	(17.7	)
Balance, September 30, 2010	$	(12.8	)	$	(54.1	)	$	56.8	$	(10.1	)

Cash and Cash Equivalents

All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.

Restricted Cash

Restricted cash represents those cash balances in our commodity futures and option brokerage accounts which are restricted from withdrawal.

Inventories

Our inventories are stated at the lower of cost or market. We determine cost using an average cost method for natural gas, propane and other LPG; specific identification for appliances; and the first-in, first-out (“FIFO”) method for all other inventories.

F-14

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Property, Plant and Equipment and Related Depreciation

We record property, plant and equipment at original cost. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition.

We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives ranging from 15 to 40 years for buildings and improvements; 7 to 40 years for storage and customer tanks and cylinders; 25 to 35 years for electricity generation facilities; and 2 to 12 years for vehicles, equipment and office furniture and fixtures. Costs to install Partnership and Antargaz-owned tanks, net of amounts billed to customers, are capitalized and amortized over the estimated period of benefit not exceeding ten years.

We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.3% in Fiscal 2011, 2.5% in Fiscal 2010 and 2.4% in Fiscal 2009. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.6% in Fiscal 2011, 2.6% in Fiscal 2010 and 2.9% in Fiscal 2009. When Utilities retire depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes.

We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit not exceeding fifteen years once the installed software is ready for its intended use.

No depreciation expense is included in cost of sales in the Consolidated Statements of Income.

Goodwill and Intangible Assets

In accordance with GAAP relating to goodwill and other intangibles, we amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. Goodwill and other intangible assets with indefinite lives are not amortized but are subject to tests for impairment at least annually. We perform impairment tests more frequently than annually if events or circumstances indicate that the value of goodwill or intangible assets with indefinite lives might be impaired. When performing our impairment tests, we use quoted market prices or, in the absence of quoted market prices, discounted estimates of future cash flows. No provisions for goodwill or other intangible asset impairments were recorded during Fiscal 2011, Fiscal 2010 or Fiscal 2009.

No amortization expense is included in cost of sales in the Consolidated Statements of Income. For further information, see Note 11.

Impairment of Long-Lived Assets

We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No material provisions for impairments were recorded during Fiscal 2011, Fiscal 2010 or Fiscal 2009.

Refundable Tank and Cylinder Deposits

Included in “Other noncurrent liabilities” on our Consolidated Balance Sheets are customer paid deposits on Antargaz owned tanks and cylinders of $204.4 and $211.8 at September 30, 2011 and 2010, respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms.

Environmental Matters

We are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.

F-15

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can reasonably be estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas is permitted to amortize as removal costs site-specific environmental investigation and remediation costs, net of related third-party payments, associated with Pennsylvania sites. UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs, and CPG Gas and PNG Gas are currently getting regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. For further information, see Note 15.

Employee Retirement Plans

We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 7).

Equity-Based Compensation

All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units”), is measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as a liability or as equity in our Consolidated Balance Sheets. Equity-based compensation costs associated with the portion of Unit awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Equity-based compensation costs associated with the portion of Unit awards classified as liabilities are measured based upon their estimated fair value at the grant date and remeasured as of the end of each period.

We have calculated a tax windfall pool using the shortcut method. We record deferred tax assets for awards that we expect will result in deductions on our income tax returns, based on the amount of compensation cost recognized and the statutory tax rate in the jurisdiction in which we will receive a deduction. Differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return are recorded in Common Stock (if the tax benefit exceeds the deferred tax asset) or in the Consolidated Statements of Income (if the deferred tax asset exceeds the tax benefit and no tax windfall pool exists from previous awards).

For additional information on our equity-based compensation plans and related disclosures, see Note 13.

Note 3 — Accounting Changes

Adoption of New Accounting Standards

Presentation of Comprehensive Income. In June 2011, the FASB issued Accounting Standards Update (“ASU”) 2011-05, “Presentation of Comprehensive Income,” which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) Topic 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. ASU 2011-05 does not change the items that must be reported in other comprehensive income. Additionally, reclassification adjustments between net income and comprehensive income must be shown on the face of the financial statements. On October 21, 2011, the FASB decided to propose a deferral of the new requirement to present reclassification adjustments on the face of the income statement. The change in presentation is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011 with full retrospective application required. Early adoption is permitted. We applied the new provisions of the guidance effective September 30, 2011, (except for the presentation of reclassification adjustments on the face of the statement of net income), and report the components of comprehensive income in two separate but consecutive statements as permitted by the new guidance.

F-16

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Transfers of Financial Assets. Effective October 1, 2010, the Company adopted new guidance regarding accounting for transfers of financial assets. Among other things, the new guidance eliminates the concept of Qualified Special Purpose Entities (“QSPEs”). It also amends previous derecognition guidance. The adoption of the new accounting guidance changed the Company’s accounting prospectively for sales of undivided interests in accounts receivable to the commercial paper conduit of a major bank under the Energy Services Receivables Facility. Effective October 1, 2010, trade receivables sold 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. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet. Also effective October 1, 2010, the Company records interest expense on amounts owed to the commercial paper conduit. Prior to October 1, 2010, losses on sales of accounts receivable to the commercial paper conduit were reflected in other income, net. Additionally, effective October 1, 2010 borrowings and repayments associated with the Energy Services Receivables Facility are reflected in cash flows from financing activities. Previously, such transactions were reflected in cash flows from operating activities. For further information, see Note 18.

Business Combinations. Effective October 1, 2009, we adopted new guidance on accounting for business combinations. The new guidance applies to all transactions or other events in which an entity obtains control of one or more businesses. The new guidance establishes, among other things, principles and requirements for how the acquirer (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in a business combination or gain from a bargain purchase; and (3) determines what information with respect to a business combination should be disclosed. The new guidance applies prospectively to business combinations for which the acquisition date is on or after October 1, 2009. Among the more significant changes in accounting for acquisitions are (1) transaction costs are generally expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, are generally recorded at fair value with subsequent adjustments recognized in operations (rather than as adjustments to the purchase price); and (3) decreases in valuation allowances on acquired deferred tax assets are recognized in operations (rather than as decreases in goodwill). The new guidance did not have a material impact on our Fiscal 2010 financial statements.

New Accounting Standards Not Yet Adopted

Goodwill Impairment. In September 2011, the FASB issued guidance on testing goodwill for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test in GAAP. The more-likely-than-not threshold is deemed as having a likelihood of more than 50 percent. Previous guidance required an entity to test goodwill for impairment at least annually by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit is less than the carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the new guidance, an entity is not required to calculate fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. The new guidance does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirements to test goodwill annually for impairment. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted. We will adopt the new guidance in Fiscal 2012.

Fair Value Measurements. In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRS.” The amendments in ASU 2011-04 result in common fair value measurement and disclosure requirements in GAAP and International Financial Reporting Standards (“IFRS”). The new guidance applies to all reporting entities that are required or permitted to measure or disclose the fair value of an asset, liability or an instrument classified in shareholders’ equity. Among other things, the new guidance requires quantitative information about unobservable inputs, valuation processes and sensitivity analysis associated with fair value measurements categorized within Level 3 of the fair value hierarchy. The new guidance is effective for our interim period ending March 31, 2012 and is required to be applied prospectively. We do not expect it will have a material impact on our results of operations or financial condition.

F-17

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Note 4 — Acquisitions & Dispositions

During Fiscal 2011, AmeriGas OLP acquired a number of domestic retail propane distribution businesses for $34.0 cash, and Flaga acquired a propane distribution business in Poland for total cash consideration of approximately $19.0. During Fiscal 2010, AmeriGas OLP acquired a number of domestic retail propane distribution businesses for $34.3 cash, and our International Propane operations acquired propane distribution businesses in Denmark, Hungary and Switzerland, and an additional 46% interest in our retail business in China, for total cash consideration of $48.7. During Fiscal 2009, AmeriGas OLP, in addition to the acquisition of the assets of CPP described below, acquired several retail propane distribution businesses for total cash consideration of $17.9 and Flaga acquired the 50% of ZLH it did not already own for $18.2.

On October 1, 2008, UGI Utilities acquired all of the outstanding stock of PPL Gas Utilities Corporation (now CPG), the natural gas distribution utility of PPL Corporation (“PPL”), for cash consideration of $267.6 plus estimated working capital of $35.4 (the “CPG Acquisition”). Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary, Penn Fuel Propane, LLC (now named UGI Central Penn Propane, LLC, “CPP”), its retail propane distributor, sold its assets to AmeriGas OLP. CPG distributes natural gas to approximately 76,000 customers in eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in portions of one Maryland county. CPP sold propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition at closing with a combination of $120 cash contributed by UGI on September 25, 2008, proceeds from the issuance on October 1, 2008 of $108 principal amount of 6.375% Senior Notes due 2013 and approximately $75.0 of UGI Utilities’ credit agreement borrowings. AmeriGas OLP funded its acquisition of the assets of CPP with AmeriGas OLP credit agreement borrowings, and UGI Utilities used the $33.6 cash proceeds from the sale of the assets of CPP to AmeriGas OLP to reduce its revolving credit agreement borrowings.

The assets and liabilities resulting from the CPG Acquisition which reflect the final purchase price allocation are included in our Consolidated Balance Sheets at September 30, 2011 and 2010. Pursuant to the CPG Acquisition purchase agreement, the purchase price was subject to adjustment for the difference between the estimated working capital of $35.4 and the actual working capital as of the closing date agreed to by both UGI Utilities and PPL. During Fiscal 2009, UGI Utilities and PPL reached an agreement on the working capital adjustment pursuant to which PPL paid UGI Utilities $9.7 in cash, including interest.

The purchase price of the CPG Acquisition, including transaction fees and expenses and incurred liabilities totaling approximately $2.9, was allocated to the assets acquired and liabilities assumed as follows:


Current assets less current liabilities	$	22.7
Property, plant and equipment		236.1
Goodwill		36.8
Utility regulatory assets		22.5
Other assets		12.5
Noncurrent liabilities		(34.4	)

Total	$	296.2

The goodwill above is primarily the result of synergies between the acquired businesses and our existing utility and propane businesses. Substantially all of the goodwill is deductible for income tax purposes over a fifteen-year period. The operating results of CPG and CPP are included in our consolidated results beginning October 1, 2008.

On July 30, 2010, Energy Services sold all of its interest in its second-tier, wholly owned subsidiary Atlantic Energy, LLC (“Atlantic Energy”) to DCP Midstream Partners, L.P. for $49.0 in cash plus an amount for inventory and other working capital. Atlantic Energy owns and operates a 20 million gallon marine import and transshipment facility located in the port of Chesapeake, Virginia. The Company recorded a $36.5 pre-tax gain on the sale which amount is included in “Other income, net” in the Fiscal 2010 Consolidated Statement of Income. The gain increased Fiscal 2010 net income attributable to UGI Corporation by $17.2 or $0.16 per diluted share. Atlantic Energy’s income from operations was not material in Fiscal 2010 and 2009.

On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated above-ground LPG storage facility located on leased property in California. The Partnership recorded a $39.9 pre-tax gain on the sale which amount is included in “Other income, net” in the Fiscal 2009 Consolidated Statement of Income. The gain increased Fiscal 2009 net income attributable to UGI Corporation by $10.4 or $0.10 per diluted share.

F-18

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Note 5 — Debt

Long-term debt comprises the following at September 30:


	2011			2010
AmeriGas Propane:
AmeriGas Partners Senior Notes:
6.50%, due May 2021	$	470.0		$	—
6.25%, due August 2019		450.0			—
8.875%, due May 2011		—			14.7
7.25%, due May 2015		—			415.0
7.125%, due May 2016		—			350.0
Other		13.5			11.7

Total AmeriGas Propane		933.5			791.4

International Propane:
Antargaz 2011 Senior Facilities term loan, due through March 2016		508.7			—
Antargaz Senior Facilities term loan, due March 2011		—			518.1
Flaga term loan, due through September 2016		53.5			—
Flaga term loan, due through September 2011		—			32.7
Flaga term loan, due through June 2014		5.6			7.6
Other		3.5			2.7

Total International Propane		571.3			561.1

UGI Utilities:
Senior Notes:
6.375%, due September 2013		108.0			108.0
5.75%, due September 2016		175.0			175.0
6.21%, due September 2036		100.0			100.0
Medium- Term Notes:
5.53%, due September 2012		40.0			40.0
5.37%, due August 2013		25.0			25.0
5.16%, due May 2015		20.0			20.0
7.37%, due October 2015		22.0			22.0
5.64%, due December 2015		50.0			50.0
6.17%, due June 2017		20.0			20.0
7.25%, due November 2017		20.0			20.0
5.67%, due January 2018		20.0			20.0
6.50%, due August 2033		20.0			20.0
6.13%, due October 2034		20.0			20.0

Total UGI Utilities		640.0			640.0


Other		12.9			13.3


Total long-term debt		2,157.7			2,005.8

Less: current maturities		(47.4	)		(573.6	)

Total long-term debt due after one year	$	2,110.3		$	1,432.2

F-19

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Scheduled principal repayments of long-term debt due in fiscal years 2012 to 2016 follow:


	2012		2013		2014		2015		2016
AmeriGas Propane	$	4.8	$	3.1	$	2.4	$	2.0	$	1.1
UGI Utilities		40.0		133.0		—		20.0		247.0
International Propane		2.1		3.2		53.7		46.5		465.9
Other		0.5		0.6		0.5		0.5		0.6

Total	$	47.4	$	139.9	$	56.6	$	69.0	$	714.6

AmeriGas Propane

In January 2011, AmeriGas Partners issued $470 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 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 principal amount of its 8.875% Senior Notes due May 2011. The Partnership incurred a loss of $18.8 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.” The loss reduced net income attributable to UGI Corporation by $5.2 during Fiscal 2011.

In August 2011, AmeriGas Partners issued $450 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 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 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.” This loss reduced net income attributable to UGI Corporation by $5.2 during Fiscal 2011.

The 6.50% and 6.25% Senior Notes generally may be redeemed at our option (pursuant to a tender offer). A redemption premium applies through May 2019 (with respect to the 6.50% Notes) and through August 2017 (with respect to the 6.25% Notes). In addition, in the event that AmeriGas Partners completes a registered public offering of Common Units, the Partnership may, at its option, redeem up to 35% of the outstanding 6.50% Notes (through May 2014) or 35% of the outstanding 6.25% Notes (through August 2014), each at a premium. AmeriGas Partners may, under certain circumstances involving excess sales proceeds from the disposition of assets not reinvested in the business or a change of control, be required to offer to prepay its 6.50% and 6.25% Senior Notes.

In June 2011, AmeriGas OLP entered into an unsecured revolving credit agreement (the “AmeriGas 2011 Credit Agreement”) with a group of banks providing for borrowings up to $325 (including a $100 sublimit for letters of credit). Concurrently with entering into the AmeriGas 2011 Credit Agreement, AmeriGas OLP terminated its then-existing $200 revolving credit agreement dated as of November 6, 2006 and its $75 credit agreement dated as of April 17, 2009 (the “2009 AmeriGas Supplemental Credit Agreement”). The AmeriGas 2011 Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a two-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas 2011 Credit Agreement, plus a margin. The margin on base rate borrowings (which ranges from 0.75% to 1.75%), Eurodollar Rate borrowings (which ranges from 1.75% to 2.75%), and the AmeriGas 2011 Credit Agreement facility fee rate (which ranges from 0.30% to 0.50%) are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (“EBITDA”), each as defined in the AmeriGas 2011 Credit Agreement.

At September 30, 2011 and 2010, there were $95.5 and $91 of borrowings outstanding under the AmeriGas 2011 Credit Agreement and predecessor credit agreements, respectively, which amounts are reflected as bank loans on the Consolidated Balance Sheets. The weighted-average interest rates on 2011 AmeriGas Credit Agreement and predecessor credit agreements borrowings at September 30, 2011 and 2010 were 2.29% and 1.31%, respectively. Issued and outstanding letters of credit, which reduce available borrowings under the 2011 AmeriGas Credit Agreement and predecessor credit agreements, totaled $35.7 at September 30, 2011 and 2010.

Restrictive Covenants. The 6.50% and 6.25% Senior Notes of AmeriGas Partners restrict the ability of the Partnership and AmeriGas OLP to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets. Under the 6.50% and 6.25% Senior Note Indentures, AmeriGas Partners is generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. At September 30, 2011, these restrictions did not limit the amount of Available Cash. See Note 14 for definition of Available Cash included in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. (“Partnership Agreement”).

F-20

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

The AmeriGas 2011 Credit Agreement restricts the incurrence of additional indebtedness and also restrict certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas 2011 Credit Agreement requires that The Partnership and AmeriGas OLP maintain ratios of total indebtedness to EBITDA, as defined, below certain thresholds. In addition, the Partnership must maintain a minimum ratio of EBITDA to interest expense, as defined, as calculated on a rolling four-quarter basis. Generally, as long as no default exists or would result, the Partnership and AmeriGas OLP are permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter.

International Propane

In March 2011, Antargaz entered into a new five-year Senior Facilities Agreement with a consortium of banks (“2011 Senior Facilities Agreement”) consisting of a €380 variable-rate term loan and a €40 revolving credit facility. The proceeds from the new term loan were used to repay Antargaz’ then-existing Senior Facilities Agreement term loan due March 2011.

Scheduled maturities under the term loan are €38 due May 2014, €34.2 due May 2015, and €307.8 due March 2016. Borrowings under the 2011 Senior Facilities Agreement bear interest at one-, two-, three- or six-month euribor, plus a margin, as defined by the 2011 Senior Facilities Agreement. There were no amounts outstanding under the 2011 Senior Facilities Agreement revolving credit facility at September 30, 2011. The margin on the term loan and revolving credit facility borrowings (which ranges from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the 2011 Senior Facilities Agreement. 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 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%. The 2011 Senior Facilities Agreement is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivables. In order to minimize the interest margin on its Senior Facilities Agreement borrowings, in September 2010 Antargaz borrowed €50 ($68.2), the total amount available under its revolving credit facility, which amount remained outstanding at September 30, 2010. This amount was repaid in October 2010.

In September 2011, Flaga entered into a €40 euro-based variable-rate term loan of which €26.7 matures in August 2016 and €13.3 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. The margin on such borrowings ranges from 1.58% to 3.93% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios. 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 rates on this term loan at September 30, 2011 was 4.76%. At September 30, 2010, Flaga had a €24.0 euro-based variable-rate term loan which matured during Fiscal 2011. Flaga had effectively fixed the euribor component of its interest rate on this term loan through September 2011 at 3.91% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2010 was 4.21%.

Flaga also has a euro-based variable-rate term loan which had outstanding principal balances of €4.2 ($5.6) and €5.6 ($7.6) as of September 30, 2011 and 2010, respectively. This term loan matures in June 2014 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 2.625% to 3.50% and is based upon certain equity, return on assets and debt to EBITDA ratios as determined on a UGI consolidated basis. Semi-annual principal payments of €0.7 are due on December 31 and June 30 each year through June 2014. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 2.16% by entering into an interest rate swap agreement. The effective interest rates on this term loan at September 30, 2011 and 2010 were 5.04% and 5.03%, respectively.

During Fiscal 2011, in order to increase Flaga’s borrowing capacity, Flaga entered into several agreements to increase or extend maturities of its working capital facilities.

F-21

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

At September 30, 2011, Flaga GmbH has three working capital facilities comprising (1) a €46 multi-currency working capital facility which includes an uncommitted €6 overdraft facility (the “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 Working Capital Facilities”). The 2011 Multi-currency Working Capital Facility replaced two previously existing multi-currency working capital facilities which expired in September 2011 (the “Predecessor Multi-currency Facilities”). The 2011 Multi-currency Working Capital Facility expires in September 2014 and the Euro Working Capital Facilities expire in March 2012. At September 30, 2011 and 2010, there was €4.3 ($5.7) and €9.8 ($13.4) of borrowings outstanding under the 2011 Multi-currency Working Capital Facility and the Predecessor Multi-currency Facilities, respectively, and €8.0 ($10.7) and €7.9 ($10.8) of borrowings outstanding under the Euro Working Capital Facilities, respectively. These amounts are reflected as bank loans on the Consolidated Balance Sheets.

Borrowings under the 2011 Multi-currency Working Capital Facility and Euro Working Capital Facilities generally bear interest at market rates (a daily euro-based rate or three-month euribor rates) plus a margin. The weighted-average interest rate on the 2011 Multi-currency Working Capital Facility and Euro Working Capital Facilities borrowings at September 30, 2011 was 3.39%. The weighted-average interest rate on the predecessor multi-currency facilities and the Euro Facilities at September 30, 2010 was 2.91%. Issued and outstanding letters of credit, which reduce available borrowings under these facilities, totaled €12.1 ($16.2) and €5.4 ($7.4) at September 30, 2011 and 2010, respectively.

Restrictive Covenants and Guarantees. The 2011 Senior Facilities Agreement restricts the ability of Antargaz to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires Antargaz to maintain a ratio of net debt to EBITDA on a French generally accepted accounting basis, as defined in the agreement, that shall not exceed 3.50 to 1.00. Under this agreement, Antargaz is generally permitted to make restricted payments, such as dividends if no event of default exists or would exist upon payment of such restricted payment. UGI has guaranteed up to €100 of payments under the 2011 Senior Facilities Agreement.

The Flaga term loans, working capital facilities and interest rate swap agreements are guaranteed by UGI. In addition, under certain conditions regarding changes in certain financial ratios of UGI, the lending banks may accelerate repayment of the debt.

UGI Utilities

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 (including a $100 sublimit for letters of credit) which expires in May 2012 but may be extended to October 2015 if UGI Utilities satisfies certain requirements relating to approval by the PUC. Concurrently with entering into the UGI Utilities 2011 Credit Agreement, UGI Utilities terminated its then-existing $350 revolving credit agreement dated as of August 11, 2006. Under the UGI Utilities 2011 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 2.0% and is based upon the credit ratings of certain indebtedness of UGI Utilities. UGI Utilities has no borrowings outstanding under the UGI Utilities 2011 Credit Agreement at September 30, 2011. UGI Utilities had borrowings outstanding under its credit agreements, which we classify as bank loans, totaling $17 at September 30, 2010. The weighted-average interest rates on UGI Utilities’ revolving credit agreements borrowings at September 30, 2010 was 3.25%. Issued and outstanding letters of credit, which reduce available borrowings under the UGI Utilities 2011 Credit Agreement, totaled $2.0 at September 30, 2011.

Restrictive Covenants. UGI Utilities 2011 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

Energy Services

Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings up to $170 (including a $50 sublimit for letters of credit) which expires in August 2013. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries. In addition, Energy Services may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement, does not exceed 2.00 to 1.00. There were $10 of borrowings outstanding under the Energy Services Credit Agreement at September 30, 2011. There were no borrowings outstanding under the Energy Services Credit Agreement at September 30, 2010.

F-22

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Borrowings under the Energy Services Credit Agreement bear interest at either (i) a rate derived from LIBOR (the “LIBO Rate”) plus 3.0% for each Eurodollar Revolving Loan (as defined in the Energy Services Credit Agreement) or (ii) the Alternate Base Rate plus 2.0%. The Alternate Base Rate (as defined in the Energy Services Credit Agreement) is generally the greater of (a) the Agent Bank’s prime rate, (b) the federal funds rate plus 0.50% and (c) the one-month LIBO Rate plus 1.0%. The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services.

Restrictive Covenants. The Energy Services Credit Agreement restricts the ability of Energy Services to dispose of assets, effect certain consolidations or mergers, incur indebtedness and guaranty obligations, create liens, make acquisitions or investments, make certain dividend or other distributions and make any material changes to the nature of its businesses. In addition, the Energy Services Credit Agreement requires Energy Services to not exceed a ratio of Consolidated Total Indebtedness, as defined, to Consolidated EBITDA, as defined; a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense, as defined; a maximum ratio of Consolidated Total Indebtedness to Consolidated Total Capitalization, as defined, at any time when Consolidated Total Indebtedness is greater than $250; and a minimum Consolidated Net Worth, as defined, of $150.

Energy Services also has a $200 receivables securitization facility (see Note 18).

Restricted Net Assets

At September 30, 2011, the amount of net assets of UGI’s consolidated subsidiaries that was restricted from transfer to UGI under debt agreements, subsidiary partnership agreements and regulatory requirements under foreign laws totaled approximately $1,700.

Note 6 — Income Taxes

Income before income taxes comprises the following:


	2011		2010		2009
Domestic	$	388.8	$	448.8	$	431.7
Foreign		50.2		74.5		109.4

Total income before income taxes	$	439.0	$	523.3	$	541.1

The provisions for income taxes consist of the following:


	2011			2010			2009
Current expense:
Federal	$	24.4		$	60.5		$	69.6
State		14.5			20.4			21.6
Foreign		15.0			25.8			41.1
Investment tax credit		(5.8	)		(1.7	)		—

Total current expense		48.1			105.0			132.3
Deferred expense (benefit):
Federal		79.3			54.5			27.6
State		2.4			6.4			(1.1	)
Foreign		1.4			2.1			0.7
Investment tax credit amortization		(0.4	)		(0.4	)		(0.4	)

Total deferred expense		82.7			62.6			26.8

Total income tax expense	$	130.8		$	167.6		$	159.1

Federal income taxes for Fiscal 2010 and Fiscal 2009 are net of foreign tax credits of $2.1 and $34.9, respectively.

F-23

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows:


	2011			2010			2009
U.S. federal statutory tax rate		35.0	%		35.0	%		35.0	%
Difference in tax rate due to:
Noncontrolling interests not subject to tax		(6.0	)		(6.4	)		(8.0	)
State income taxes, net of federal benefit		2.2			3.5			2.5
Effects of international operations		(0.6	)		(0.6	)		(0.3	)
Other, net		(0.8	)		0.5			0.2

Effective tax rate		29.8	%		32.0	%		29.4	%

Deferred tax liabilities (assets) comprise the following at September 30:


	2011			2010
Excess book basis over tax basis of property, plant and equipment	$	490.4		$	414.9
Investment in AmeriGas Partners		172.7			170.9
Intangible assets and goodwill		52.1			51.0
Utility regulatory assets		124.7			127.4
Foreign currency translation adjustment		8.5			12.9
Other		7.2			8.6

Gross deferred tax liabilities		855.6			785.7

Pension plan liabilities		(62.8	)		(76.1	)
Employee-related benefits		(42.7	)		(42.4	)
Operating loss carryforwards		(31.8	)		(25.5	)
Foreign tax credit carryforwards		(60.1	)		(61.3	)
Utility regulatory liabilities		(12.4	)		(13.5	)
Derivative financial instruments		(30.5	)		(34.8	)
Other		(32.9	)		(41.7	)

Gross deferred tax assets		(273.2	)		(295.3	)

Deferred tax assets valuation allowance		81.9			78.4

Net deferred tax liabilities	$	664.3		$	568.8

At September 30, 2011, foreign net operating loss carryforwards principally relating to Flaga and certain operations of Antargaz totaled $46.0 and $5.5, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries which approximate $177.9 and expire through 2031. We also have operating loss carryforwards of $7.4 for certain operations of AmeriGas Propane that expire through 2031. At September 30, 2011, deferred tax assets relating to operating loss carryforwards include $10.6 for Flaga, $1.9 for Antargaz, $1.0 for UGI International Holdings BV, $2.7 for AmeriGas Propane and $15.6 for certain other subsidiaries. A valuation allowance of $15.6 has been provided for deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries because, on a state reportable basis, it is more likely than not that these assets will expire unused. A valuation allowance of $6.2 was also provided for deferred tax assets related to certain operations of Antargaz, Flaga and UGI International Holdings BV. Operating activities and tax deductions related to the exercise of non-qualified stock options contributed to the state net operating losses disclosed above. We first recognize the utilization of state net operating losses from operations (which exclude the impact of tax deductions for exercises of non-qualified stock options) to reduce income tax expense. Then, to the extent state net operating loss carryforwards, if realized, relate to non-qualified stock option deductions, the resulting benefits will be credited to UGI Corporation stockholders’ equity.

We have foreign tax credit carryforwards of approximately $60.1 expiring through 2022 resulting from the actual and planned repatriation of Antargaz’ accumulated earnings since acquisition which are includable in U.S. taxable income. Because we expect that these credits will expire unused, a valuation allowance has been provided for the entire foreign tax credit carryforward amount. The valuation allowance for all deferred tax assets increased by $3.5 in Fiscal 2011 due primarily to unusable net operating losses obtained in connection with overseas acquisitions of $3.2 and an increase in unusable state operating losses of $1.5 partially offset by a decrease in the foreign tax credit carryforwards of $1.2.

F-24

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

We conduct business and file tax returns in the U.S., numerous states, local jurisdictions and in France and certain central and eastern European countries. Our U.S. federal income tax returns are settled through the 2008 tax year and our French tax returns are settled through the 2007 tax year. Our Austrian tax returns are settled through 2007 and our other central and eastern European tax returns are effectively settled for various years from 2004 to 2009. UGI Corporation’s federal income tax return for Fiscal 2009 is currently under audit. Although it is not possible to predict with certainty the timing of the conclusion of the pending U.S. federal tax audit in progress, we anticipate that the Internal Revenue Service’s (“IRS’s”) audit of our Fiscal 2009 U.S. federal income tax return may be completed during Fiscal 2012. State and other income tax returns in the U.S. are generally subject to examination for a period of three to five years after the filing of the respective returns.

As of September 30, 2011, we have unrecognized income tax benefits totaling $6.5 including related accrued interest of $0.2. If these unrecognized tax benefits were subsequently recognized, $1.6 would be recorded as a benefit to income taxes on the consolidated statement of income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. Included in the balance at September 30, 2011 are $4.8 of tax positions for which the deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, the disallowance of the current deduction would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The amount of reasonably possible changes in unrecognized tax benefits and related interest in the next twelve months is a net reduction of approximately $4.2.

A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:


Balance at September 30, 2008	$	4.9
Additions for tax positions of the current year		0.5
Additions for tax positions of prior years		0.3
Reductions as a result of tax positions taken in prior years		(1.2	)
Settlements with tax authorities		(2.2	)

Balance at September 30, 2009		2.3
Additions for tax positions of the current year		4.3
Reductions as a result of tax positions taken in prior years		(0.2	)
Settlements with tax authorities		(1.0	)

Balance at September 30, 2010		5.4
Additions for tax positions of the current year		0.4
Additions for tax positions of prior years		1.0
Settlements with tax authorities		(0.5	)

Balance at September 30, 2011	$	6.3

Beginning with the tax year ended September 30, 2009, the Company received IRS consent to change its tax method of accounting for capitalizing certain repair and maintenance costs associated with its Gas Utility and Electric Utility assets. The filing of the Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax benefits totaling approximately $30.2 which were used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 Pennsylvania income tax return also produced a $43.4 state net operating loss (“NOL”) carryforward. Under current Pennsylvania state income tax law, the NOL can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. As of September 30, 2011, a state net operating loss carryforward of $29.3 remains. Because the Company believes that it is more likely than not that it will fully utilize this state NOL prior to its expiration, no valuation allowance has been recorded. The Company’s determination of what constitutes a capital cost versus ordinary expense as it relates to the new tax method will likely be reviewed upon audit by the IRS and may be subject to subsequent adjustment. Accordingly, the status of this tax return position is uncertain at this time. In accordance with accounting guidance regarding uncertain tax positions, during Fiscal 2011 and Fiscal 2010, the Company added $1.2 and $3.9 including interest to its liability for unrecognized tax benefits related to this tax method. However, because this tax matter relates only to the timing of tax deductibility, we have recorded an offsetting deferred tax asset of an equal amount. For further information on the regulatory impact of this change, see Note 8.

F-25

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

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.

Note 7 — Employee Retirement Plans

Defined Benefit Pension and Other Postretirement 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”). We also provide postretirement health care benefits to certain retirees and active employees and postretirement life insurance benefits to nearly all domestic active and retired employees. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related to the Antargaz plans, such amounts are not material.

Effective December 31, 2010, UGI Utilities merged its then-existing two defined benefit pension plans (“Utilities Pension Plan Merger”). As a result of the Utilities Pension Plan Merger and in accordance with GAAP relating to accounting for retirement benefits, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2010, which decreased other noncurrent liabilities by $46.7; decreased associated regulatory assets by $43.1; and increased pre-tax other comprehensive income by $3.6. The Pension Plan, and the other U.S. pension plan that existed prior to the Utilities Pension Plan Merger, are hereafter referred to as the “U.S. Pension Plans.”

F-26

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the U.S. Pension Plans and the Antargaz pension plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets, and the funded status of pension and other postretirement plans as of September 30, 2011 and 2010. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation.


	Pension						Other Postretirement
	Benefits						Benefits
	2011			2010			2011			2010
Change in benefit obligations:
Benefit obligations — beginning of year	$	471.8		$	428.9		$	22.9		$	21.4
Service cost		8.8			8.7			0.4			0.4
Interest cost		24.1			23.5			1.1			1.1
Actuarial (gain) loss		(22.0	)		32.2			(2.4	)		1.6
Plan amendments		—			—			(0.1	)		—
Plan settlements		—			(2.7	)		—			—
Foreign currency		(0.1	)		(0.5	)		—			(0.2	)
Benefits paid		(19.7	)		(18.3	)		(1.4	)		(1.4	)

Benefit obligations — end of year	$	462.9		$	471.8		$	20.5		$	22.9


Change in plan assets:
Fair value of plan assets — beginning of year	$	287.9		$	279.8		$	10.0		$	9.7
Actual gain on plan assets		2.6			25.9			0.1			0.7
Foreign currency		—			(0.2	)		—			—
Employer contributions		19.2			3.4			1.1			1.0
Settlement payments		—			(2.7	)		—			—
Benefits paid		(19.7	)		(18.3	)		(1.4	)		(1.4	)

Fair value of plan assets — end of year	$	290.0		$	287.9		$	9.8		$	10.0

Funded status of the plans — end of year	$	(172.9	)	$	(183.9	)	$	(10.7	)	$	(12.9	)


(Liabilities) recorded in the balance sheet:
Unfunded liabilities — included in other current liabilities	$	(27.6	)	$	(20.3	)	$	—		$	—
Unfunded liabilities — included in other noncurrent liabilities		(145.3	)		(163.6	)		(10.7	)		(12.9	)

Net amount recognized	$	(172.9	)	$	(183.9	)	$	(10.7	)	$	(12.9	)


Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
Prior service (credit) cost	$	(0.2	)	$	(0.4	)	$	(0.1	)	$	0.1
Net actuarial loss (gain)		13.6			13.8			(0.8	)		0.1

Total	$	13.4		$	13.4		$	(0.9	)	$	0.2

Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	$	1.8		$	0.3		$	(3.2	)	$	(3.4	)
Net actuarial loss		146.9			155.6			6.3			5.9

Total	$	148.7		$	155.9		$	3.1		$	2.5

In Fiscal 2012, we estimate that we will amortize approximately $8.8 of net actuarial losses and $0.2 of prior service credits from UGI stockholders’ equity and regulatory assets into retiree benefit cost.

F-27

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Actuarial assumptions for our domestic plans are described below. Assumptions for the Antargaz plans are based upon market conditions in France. The discount rates at September 30 are used to measure the year-end benefit obligations and the earnings effects for the subsequent year. The discount rate assumption was determined by selecting a hypothetical portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the plans’ benefit payments. The expected rate of return on assets assumption is based on the current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below).


	Pension Plans												Other Postretirement Benefits
	2011(a)			2010			2009			2008			2011			2010			2009			2008
Weighted-average assumptions:
Discount rate		5.3	%		5.0	%		5.5	%		6.8	%		5.3	%		5.0	%		5.5	%		6.8	%
Expected return on plan assets		8.0	%		8.5	%		8.5	%		8.5	%		5.5	%		5.5	%		5.5	%		5.5	%
Rate of increase in salary levels		3.5	%		3.8	%		3.8	%		3.8	%		3.5	%		3.8	%		3.8	%		3.8	%


(a)		The discount rate used during Fiscal 2011 to calculate pension expense was a rate of 5.0% through December 31, 2010 (the date of the Utilities Plan Merger) and 5.5% for the remainder of Fiscal 2011.

The ABO for the U. S. Pension Plans was $415.0 and $417.8 as of September 30, 2011 and 2010, respectively.

Net periodic pension expense and other postretirement benefit costs include the following components:


	Pension Benefits									Other Postretirement Benefits
	2011			2010			2009			2011			2010			2009
Service cost	$	8.8		$	8.7		$	7.1		$	0.4		$	0.4		$	0.3
Interest cost		24.1			23.5			23.3			1.1			1.1			1.2
Expected return on assets		(25.8	)		(25.8	)		(25.7	)		(0.5	)		(0.5	)		(0.6	)
Curtailment gain		—			—			—			(3.2	)		—			—
Settlement loss		—			1.0			1.8			—			—			—
Amortization of:
Transition obligation		—			—			—			—			—			0.2
Prior service cost (benefit)		0.2			—			—			(0.7	)		(0.4	)		(0.4	)
Actuarial loss (gain)		7.5			5.9			3.8			0.4			0.1			(0.1	)

Net benefit cost (income)		14.8			13.3			10.3			(2.5	)		0.7			0.6
Change in associated regulatory liabilities		—			—			—			3.1			3.1			3.3

Net benefit cost after change in regulatory liabilities	$	14.8		$	13.3		$	10.3		$	0.6		$	3.8		$	3.9

U.S. Pension Plans’ assets are held in trust. It is our general policy to fund amounts for pension benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2011 and 2010, we made cash contributions to the U.S. Pension Plans of $18.7 and $3.4, respectively. We did not make any contributions to the U.S. Pension Plans in Fiscal 2009. In conjunction with the settlement of obligations under a subsidiary retirement benefit plan, Antargaz made a settlement payment of €4.1 ($5.7) during Fiscal 2009. We believe that in Fiscal 2012 we will be required to make contributions to the U.S. Pension Plans totaling approximately $27.6.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs determined under GAAP. The difference between such amounts and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. The required contributions to the VEBA during Fiscal 2012 are not expected to be material.

F-28

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Expected payments for pension benefits and for other postretirement welfare benefits are as follows:


			Other
	Pension		Postretirement
	Benefits		Benefits
Fiscal 2012	$	20.7	$	2.0
Fiscal 2013		21.7		2.0
Fiscal 2014		23.0		2.0
Fiscal 2015		24.3		2.0
Fiscal 2016		26.0		2.0
Fiscal 2017 - 2021		148.5		9.9

The assumed domestic health care cost trend rates are 7.5% for Fiscal 2012, decreasing to 5.0% in Fiscal 2017. A one percentage point change in the assumed health care cost trend rate would not have a material impact on the Fiscal 2011 other postretirement benefit cost or September 30, 2011 other postretirement benefit ABO.

We also sponsor unfunded and non-qualified supplemental executive retirement plans. At September 30, 2011 and 2010, the PBOs of these plans were $25.6 and $23.9, respectively. We recorded net costs for these plans of $3.0 in Fiscal 2011, $2.6 in Fiscal 2010 and $3.1 in Fiscal 2009. These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $7.6 and $4.7 at September 30, 2011 and 2010, respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $0.7 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2012.

U.S. Pension Plans and VEBA Assets. The assets of the U.S. Pension Plans and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the U.S. Pension Plans and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly-traded diversified equity and fixed income mutual funds and UGI Common Stock.

F-29

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

The targets, target ranges and actual allocations for the U.S. Pension Plans’ and VEBA trust assets at September 30 are as follows:

U.S. Pension Plans


							Target
	Actual						Asset			Permitted
	2011			2010			Allocation			Range
Equity investments:
Domestic		49.4	%		56.1	%		52.5	%		40.0% - 65.0	%
International		10.7	%		12.2	%		12.5	%		7.5% - 17.5	%

Total		60.1	%		68.3	%		65.0	%		60.0% - 70.0	%
Fixed income funds & cash equivalents		39.9	%		31.7	%		35.0	%		30.0% - 40.0	%

Total		100.0	%		100.0	%		100.0	%

VEBA


							Target
	Actual						Asset			Permitted
	2011			2010			Allocation			Range

Domestic equity investments		62.2	%		65.0	%		65.0	%		60.0% - 70.0	%

Fixed income funds & cash equivalents		37.8	%		35.0	%		35.0	%		30.0% - 40.0	%

Total		100.0	%		100.0	%		100.0	%

Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap mutual funds. Investments in international equity mutual funds are indexed to various Morgan Stanley Composite indices. The fixed income investments comprise investments designed to match the duration of the Barclays Capital Aggregate Bond Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 7.6% and 8.3% of U.S. Pension Plans assets at September 30, 2011 and 2010, respectively. At September 30, 2011, there were no significant concentrations of risk (defined as greater than 10% of the fair value of total assets) associated with any individual company, industry sector or international geographic region.

GAAP establishes a hierarchy that prioritizes fair value measurements based upon the inputs and valuation techniques used to measure fair value. This fair value hierarchy groups assets into three levels, as described in Note 2. We maximize the use of observable inputs and minimize the use of unobservable inputs when determining fair value. The fair values of U.S. Pension Plans and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee.

F-30

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

The fair values of the U.S. Pension Plans’ and VEBA trust assets at September 30, 2011 and 2010 by asset class are as follows:


	Pension Plans
	Quoted Prices
	in Active		Significant
	Markets for		Other
	Identical Assets		Observable		Unobservable
	and Liabilities		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
September 30, 2011:
Equity investments:
Domestic	$	143.1	$	—	$	—	$	143.1
International		31.0		—		—		31.0
Fixed income		113.6		—		—		113.6
Cash equivalents		—		2.0		—		2.0

Total	$	287.7	$	2.0	$	—	$	289.7


September 30, 2010:
Equity investments:
Domestic	$	161.5	$	—	$	—	$	161.5
International		35.2		—		—		35.2
Fixed income		88.9		—		—		88.9
Cash equivalents		—		2.3		—		2.3

Total	$	285.6	$	2.3	$	—	$	287.9


	VEBA
	Quoted Prices
	in Active		Significant
	Markets for		Other
	Identical Assets		Observable		Unobservable
	and Liabilities		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
September 30, 2011:
Domestic equity	$	6.1	$	—	$	—	$	6.1
Fixed income		3.3		—		—		3.3
Cash equivalents		—		0.4		—		0.4

Total	$	9.4	$	0.4	$	—	$	9.8


September 30, 2010:
Domestic equity	$	6.5	$	—	$	—	$	6.5
Fixed income		3.0		—		—		3.0
Cash equivalents		—		0.5		—		0.5

Total	$	9.5	$	0.5	$	—	$	10.0

The expected long-term rates of return on U.S. Pension Plans’ and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption.

F-31

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Defined Contribution Plans. We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for employer matching contributions at various rates. The cost of benefits under the savings plans totaled $10.4 in Fiscal 2011, $9.8 in Fiscal 2010 and $10.1 in Fiscal 2009.

Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters

The following regulatory assets and liabilities associated with Utilities are included in our accompanying balance sheets at September 30:


	2011		2010
Regulatory assets:
Income taxes recoverable	$	97.9	$	82.5
Underfunded pension and postretirement plans		150.7		159.2
Environmental costs		19.5		22.6
Deferred fuel and power costs		12.2		36.6
Removal costs, net		12.3		13.0
Other		7.8		5.8

Total regulatory assets	$	300.4	$	319.7


Regulatory liabilities:
Postretirement benefits	$	11.5	$	10.5
Environmental overcollections		4.7		7.2
Deferred fuel and power refunds		6.6		8.3
State tax benefits — distribution system repairs		6.3		6.7
Other		0.7		—

Total regulatory liabilities	$	29.8	$	32.7

Income taxes recoverable. This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 50 years.

Underfunded pension and other postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with pension and other postretirement benefits which is probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants.

Environmental costs. Environmental costs represents amounts actually spent by UGI Gas to clean up sites in Pennsylvania as well as the portion of estimated probable future environmental remediation and investigation costs principally at manufactured gas plant (“MGP”) sites that CPG Gas and PNG Gas expect to incur in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (see Note 15). UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites. PNG Gas and CPG Gas are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2011, the period over which PNG Gas and CPG Gas expect to recover these costs will depend upon future remediation activity.

F-32

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Deferred fuel and power — costs and refunds. Gas Utility’s tariffs and, commencing January 1, 2010, Electric Utility’s default service (“DS”) tariffs (as further described below under “Electric Utility DS Rates”), contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and DS rates in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it purchases for firm-residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Net unrealized losses on such contracts at September 30, 2011 and 2010 were $3.1 and $1.4, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with GAAP relating to rate-regulated entities. At September 30, 2011 and 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $8.7 and $19.7, respectively, which amounts are reflected in current derivative financial instruments and other noncurrent liabilities on the Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power costs or deferred fuel and power refunds. At September 30, 2011 and 2010, such gains or losses were not material.

Removal costs, net. This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. At September 30, 2011, UGI Utilities expects to recover these costs over periods of 1 to 5 years.

Postretirement benefits. Gas Utility and Electric Utility are recovering ongoing postretirement benefit costs at amounts permitted by the PUC in prior base rate proceedings. With respect to UGI Gas and Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits are being deferred for future refund to or recovery from ratepayers. Such amounts are reflected in regulatory liabilities in the table above.

Environmental overcollections. This regulatory liability represents the difference between amounts recovered in rates and actual costs incurred (net of insurance proceeds) associated with the terms of a consent order agreement between CPG and the Pennsylvania Department of Environmental Protection to remediate certain gas plant sites.

State income tax benefits — distribution system repairs. As previously described in Note 6, the Company received IRS consent to change its tax method of accounting for capitalizing certain repair and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, resulting from the deduction for income tax purposes of these repair and maintenance expenses which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.

Other. Other regulatory assets comprise a number of items including, among others, deferred postretirement costs, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2011, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 years.

UGI Utilities’ regulatory liabilities relating to postretirement benefits, environmental overcollections and state tax benefits — distribution system repairs are included in “Other noncurrent liabilities” on the Consolidated Balance Sheets. UGI Utilities does not recover a rate of return on its regulatory assets.

F-33

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Other Regulatory Matters

PNG and CPG Base Rate Filings. On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5 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 as well as $0.9 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 January 28, 2009, PNG and CPG filed separate requests with the PUC to increase base operating revenues by $38.1 annually for PNG and $19.6 annually for CPG to fund system improvements and operations necessary to maintain safe and reliable natural gas service and energy assistance for low income customers as well as energy conservation programs for all customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on agreements with the opposing parties regarding the requested base operating revenue increases. On August 27, 2009, the PUC approved the settlement agreements which resulted in a $19.8 increase in annual base operating revenue for PNG Gas and a $10.0 increase in annual base operating revenue for CPG Gas. The increases became effective August 28, 2009 and did not have a material effect on Fiscal 2009 results.

Electric Utility DS Rates. Prior to January 1, 2010, the terms and conditions under which Electric Utility provided provider of last resort (“POLR”) service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006. In accordance with the POLR Settlement, Electric Utility could increase its POLR rates up to certain limits through December 31, 2009. 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.

Transfers of Assets. 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. 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 9.0 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.

Note 9 — Inventories

Inventories comprise the following at September 30:


	2011		2010
Non-utility LPG and natural gas	$	222.2	$	157.9
Gas Utility natural gas		95.6		111.5
Materials, supplies and other		45.2		44.6

Total inventories	$	363.0	$	314.0

F-34

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

At September 30, 2011, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”) two of which expire in October 2012 and one of which expires in October 2013. Pursuant to these and predecessor SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above. The carrying values of gas storage inventories released under the SCAAs to non-affiliates at September 30, 2011 and 2010 comprising 3.9 billion cubic feet (“bcf”) and 8.0 bcf of natural gas was $19.0 and $41.9, respectively.

Note 10 — Property, Plant and Equipment

Property, plant and equipment comprise the following at September 30:


	2011		2010
Utilities:
Distribution	$	1,951.9	$	1,866.0
Transmission		83.4		78.2
General and other, including work in process		165.7		185.1

Total Utilities		2,201.0		2,129.3


Non-utility:
Land		98.5		94.1
Buildings and improvements		214.8		206.4
Transportation equipment		112.6		111.3
Equipment, primarily cylinders and tanks		2,127.6		2,020.3
Electric generation		230.0		97.9
Other, including work in process		300.0		310.4

Total non-utility		3,083.5		2,840.4

Total property, plant and equipment	$	5,284.5	$	4,969.7

Note 11 — Goodwill and Intangible Assets

Goodwill and other intangible assets comprise the following at September 30:


	2011			2010
Goodwill (not subject to amortization)	$	1,562.2		$	1,562.7


Other intangible assets:
Customer relationships, noncompete agreements and other	$	232.1		$	215.4
Trademark (not subject to amortization)		47.9			46.3

Gross carrying amount		280.0			261.7
Accumulated amortization		(132.2	)		(111.6	)

Net carrying amount	$	147.8		$	150.1

F-35

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Changes in the carrying amount of goodwill are as follows:


	AmeriGas		Gas		Midstream &			International Propane						Corporate &
	Propane		Utility		Marketing			Antargaz			Other			Other & Elims.		Total
Balance September 30, 2009	$	670.1	$	180.1	$	11.8		$	646.9		$	70.4		$	3.0	$	1,582.3
Goodwill acquired		12.9		—		—			—			20.6			—		33.5
Purchase accounting adjustments		0.1		—		—			—			—			—		0.1
Dispositions		—		—		(9.0	)		—			—			4.0		(5.0	)
Foreign currency translation		—		—		—			(44.2	)		(4.0	)		—		(48.2	)

Balance September 30, 2010		683.1		180.1		2.8			602.7			87.0			7.0		1,562.7
Goodwill acquired		13.1		—		—			—			—			—		13.1
Purchase accounting adjustments		0.1		2.0		—			—			(3.2	)		—		(1.0	)
Foreign currency translation		—		—		—			(10.9	)		(1.6	)		—		(12.6	)

Balance September 30, 2011	$	696.3	$	182.1	$	2.8		$	591.8		$	82.2		$	7.0	$	1,562.2

We amortize customer relationships and noncompete agreement intangibles over their estimated periods of benefit which do not exceed 15 years. Amortization expense of intangible assets was $20.4 in Fiscal 2011, $19.9 in Fiscal 2010 and $18.4 in Fiscal 2009. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2012 — $20.1; Fiscal 2013 — $19.5; Fiscal 2014 — $18.6; Fiscal 2015 — $16.6; Fiscal 2016 — $10.3. There were no accumulated impairment losses at September 30, 2011.

Note 12 — Series Preferred Stock

UGI has 10,000,000 shares of UGI Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2011 or 2010.

UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. At September 30, 2011 and 2010, there were no shares of UGI Utilities Series Preferred Stock outstanding.

Note 13 — Common Stock and Equity-Based Compensation

UGI Common Stock share activity for Fiscal 2009, Fiscal 2010 and Fiscal 2011 follows:


	Issued		Treasury			Outstanding
Balance, September 30, 2008		115,247,694		(7,386,732	)		107,860,962

Issued:
Employee and director plans		13,600		776,074			789,674
Dividend reinvestment plan		—		96,071			96,071

Balance, September 30, 2009		115,261,294		(6,514,587	)		108,746,707

Issued:
Employee and director plans		139,000		1,390,207			1,529,207
Dividend reinvestment plan		—		97,673			97,673

Balance, September 30, 2010		115,400,294		(5,026,707	)		110,373,587

Issued:
Employee and director plans		106,800		1,263,065			1,369,865
Dividend reinvestment plan		—		92,570			92,570

Balance, September 30, 2011		115,507,094		(3,671,072	)		111,836,022

F-36

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Equity-Based Compensation

The Company grants equity-based awards to employees and non-employee directors comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners Common Unit-based equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $15.6 ($10.3 after-tax), $13.2 ($8.7 after-tax) and $17.6 ($11.4 after-tax) in Fiscal 2011, Fiscal 2010 and Fiscal 2009, respectively.

UGI Equity-Based Compensation Plans and Awards. Under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 (the “OECP”), we may grant options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”) and other equity-based awards to key employees and non-employee directors. The exercise price for options may not be less than the fair market value on the grant date. Awards granted under the OECP may vest immediately or ratably over a period of years, and stock options can be exercised no later than ten years from the grant date. In addition, the OECP provides that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.

Under the OECP, awards representing up to 15,000,000 shares of UGI Common Stock may be granted. The maximum number of shares that may be issued pursuant to grants other than stock options or SARs is 3,200,000. Dividend equivalents on UGI Unit awards to employees will be paid in cash. Dividend equivalents on non-employee director awards are accumulated in additional Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of Common Stock and cash. UGI Unit awards granted to Antargaz employees are settled in shares of Common Stock. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance goals and service conditions. It is our practice to issue treasury shares to satisfy substantially all option exercises and UGI Unit awards. We do not expect to repurchase shares for such purposes during Fiscal 2012.

UGI Stock Option Awards. Stock option transactions under the OECP and predecessor plans for Fiscal 2009, Fiscal 2010 and Fiscal 2011 follow:


								Weighted
				Weighted		Total		Average
				Average		Intrinsic		Contract Term
	Shares			Option Price		Value		(Years)
Shares under option — September 30, 2008		6,652,245		$	21.71	$	30.9		6.6

Granted		1,411,200		$	24.65
Cancelled		(87,334	)	$	25.81
Exercised		(474,618	)	$	13.30	$	6.0

Shares under option — September 30, 2009		7,501,493		$	22.74	$	23.2		6.4

Granted		1,394,300		$	24.37
Cancelled		(62,501	)	$	25.12
Exercised		(1,276,247	)	$	18.09	$	11.7

Shares under option — September 30, 2010		7,557,045		$	23.81	$	36.2		6.5

Granted		1,443,558		$	31.55
Cancelled		(235,437	)	$	27.79
Exercised		(1,091,987	)	$	20.95	$	11.4

Shares under option — September 30, 2011		7,673,179		$	25.55	$	15.1		6.2


Options exercisable — September 30, 2009		4,744,054		$	21.00
Options exercisable — September 30, 2010		4,706,376		$	22.99
Options exercisable — September 30, 2011		4,879,784		$	24.15	$	12.7		5.2

Non-vested options — September 30, 2011		2,793,395		$	27.99	$	2.4		8.0

F-37

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Cash received from stock option exercises and associated tax benefits were $22.9 and $3.8, $23.1 and $4.3, and $6.3 and $2.2 in Fiscal 2011, Fiscal 2010 and Fiscal 2009, respectively. As of September 30, 2011, there was $3.6 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 2.1 years.

The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2011:


	Range of exercise prices
	Under		$20.00 -		$25.01 -		Over
	$20.00		$25.00		$30.00		$30.00
Options outstanding at September 30, 2011:
Number of options		336,300		3,539,727		2,456,694		1,340,458
Weighted average remaining contractual life (in years)		1.9		6.0		5.7		8.7
Weighted average exercise price	$	15.42	$	23.05	$	27.24	$	31.59

Options exercisable at September 30, 2011:
Number of options		336,300		2,351,093		2,124,391		68,000
Weighted average exercise price	$	15.42	$	22.44	$	27.19	$	31.74

UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $5.40 in Fiscal 2011, $4.49 in Fiscal 2010 and $4.13 in Fiscal 2009. These amounts were determined using a Black-Scholes option pricing model which values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, expected dividend payments and the risk-free interest rate over the expected life of the option. The expected life of option awards represents the period of time during which option grants are expected to be outstanding and is derived from historical exercise patterns. Expected volatility is based on historical volatility of the price of UGI’s Common Stock. Expected dividend yield is based on historical UGI dividend rates. The risk free interest rate is based on U.S. Treasury bonds with terms comparable to the options in effect on the date of grant.

The assumptions we used for valuing option grants during Fiscal 2011, Fiscal 2010 and Fiscal 2009 are as follows:


	2011			2010			2009
Expected life of option	5.75 years			5.75 years			5.75 years
Weighted average volatility		24.3	%		24.0	%		23.7	%
Weighted average dividend yield		3.4	%		3.3	%		3.0	%

Expected volatility		23.8% - 24.3	%		24.0	%		20.3% - 23.7	%
Expected dividend yield		3.1% - 3.4	%		3.3% - 3.4	%		2.9% - 3.2	%
Risk free rate		1.2% - 2.4	%		1.7% - 3.1	%		1.7% - 3.0	%

UGI Unit Awards. UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. The number of UGI Performance Units ultimately paid at the end of the performance period (generally three-years) may be higher or lower than the target amount, or even zero, based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to companies in the Standard & Poor’s Utilities Index for grants prior to January 1, 2011 and the Russell Midcap Utility Index (excluding telecommunication companies) for grants on or after January 1, 2011 (“UGI comparator group”). Based on the TSR percentile rank, grantees may receive 0% to 200% of the target award granted. If UGI’s TSR ranks below the 40th percentile compared to the UGI comparator group, the employee will not be paid. At the 40th percentile, the employee will be paid an award equal to 50% of the target award; at the 50th percentile, 100%; and at the 100th percentile, 200%. The actual amount of the award is interpolated between these percentile rankings. Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest.

The fair value of UGI Stock Units on the grant date is equal to the market price of UGI Stock on the grant date. Under GAAP, UGI Performance Units are equity awards with a market-based condition which, if settled in shares, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of UGI Performance Units are estimated using a Monte Carlo valuation model. The fair value associated with the target award is accounted for as equity and the fair value of the award over the target, as well as all dividend equivalents, is accounted for as a liability. The expected term of the UGI Performance Unit awards is three years based on the performance period. Expected volatility is based on the historical volatility of UGI Common Stock over a three-year period. The risk-free interest rate is based on the yields on U.S. Treasury bonds at the time of grant. Volatility for all companies in the UGI comparator group is based on historical volatility.

F-38

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

The following table summarizes the weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs:


	Grants Awarded in Fiscal
	2011			2010			2009
Risk free rate		1.0	%		1.7	%		1.0	%
Expected life	3 years			3 years			3 years
Expected volatility		27.6	%		28.0	%		27.1	%
Dividend yield		3.2	%		3.3	%		3.2	%

The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $35.19 for Units granted in Fiscal 2011, $22.51 for Units granted in Fiscal 2010 and $27.91 for Units granted in Fiscal 2009.

The following table summarizes UGI Unit award activity for Fiscal 2011:


	Total					Vested					Non-Vested
				Weighted					Weighted					Weighted
				Average					Average					Average
	Number of			Grant Date		Number of			Grant Date		Number of			Grant Date
	UGI			Fair Value		UGI			Fair Value		UGI			Fair Value
	Units			(per Unit)		Units			(per Unit)		Units			(per Unit)
September 30, 2010		930,493		$	22.99		570,835		$	21.27		359,658		$	25.71
UGI Performance Units:
Granted		223,525		$	35.19		—		$	—		223,525		$	35.19
Forfeited		(77,906	)	$	30.18		—		$	—		(77,906	)	$	30.18
Vested		—		$	—		198,749		$	28.84		(198,749	)	$	28.84
Unit awards paid		(185,374	)	$	30.17		(185,374	)	$	30.17		—		$	—
Performance criteria not met		—		$	—		—		$	—		—		$	—
UGI Stock Units:
Granted(a)		61,945		$	33.31		—		$	—		61,945		$	33.31
Forfeited		(30,600	)	$	34.88		—		$	—		(30,600	)	$	34.88
Vested		—		$	—		36,545		$	30.54		(36,545	)	$	30.54
Unit awards paid		(21,800	)	$	26.37		(21,800	)	$	26.37		—		$	—

September 30, 2011		900,283		$	24.13		598,955		$	21.41		301,328		$	29.56


(a)		Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2010 and Fiscal 2009 were 27,060 and 52,767, respectively.

F-39

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

During Fiscal 2011, Fiscal 2010 and Fiscal 2009, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:


	2011		2010		2009
UGI Performance Unit awards:
Number of original awards granted		197,917		193,983		163,450
Fiscal year granted		2008		2007		2006
Payment of awards:
Shares of UGI Common Stock issued		142,494		123,169		117,847
Cash paid	$	7.5	$	2.6	$	3.1

UGI Stock Unit awards:
Number of original awards granted		22,400		—		88,449
Payment of awards:
Shares of UGI Common Stock issued		17,545		—		58,376
Cash paid	$	0.2	$	—	$	0.8

During Fiscal 2011, Fiscal 2010 and Fiscal 2009, we granted UGI Unit awards representing 285,470, 231,710 and 269,017 shares, respectively, having weighted-average grant date fair values per Unit of $34.78, $22.69 and $27.26, respectively.

As of September 30, 2011, there was a total of approximately $6.6 of unrecognized compensation cost associated with 900,283 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.9 years. The total fair values of UGI Units that vested during Fiscal 2011, Fiscal 2010 and Fiscal 2009 were $6.8, $5.0 and $7.6, respectively. As of September 30, 2011 and 2010, total liabilities of $6.0 and $8.7, respectively, associated with UGI Unit awards are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.

At September 30, 2011, 2,618,351 shares of Common Stock were available for future grants under the OECP, of which up to 1,437,297 may be issued pursuant to future grants other than stock options or SARs.

AmeriGas Partners Equity-Based Compensation Plans and Awards. Under the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. (“2010 Propane Plan”), the General Partner may award to employees and non-employee directors grants of Common Units, performance units, options, phantom units, unit appreciation rights and other Common Unit-based awards. The total aggregate number of Common Units that may be issued under the Plan is 2,800,000. The exercise price for options may not be less than the fair market value on the date of grant. Awards granted under the 2010 Propane Plan may vest immediately or ratably over a period of years, and options can be exercised no later than ten years from the grant date. In addition, the 2010 Propane Plan provides that Common Unit-based awards may also provide for the crediting of Common Unit distribution equivalents to participants’ accounts.

The 2010 Propane Plan succeeded the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan (“2000 Propane Plan”) which expired on December 31, 2009, and replaced the AmeriGas Propane, Inc. Discretionary Long-Term Incentive Plan for Non-Executive Key Employees (“Nonexecutive Propane Plan”). Under the 2000 Propane Plan, the General Partner could award to key employees the right to receive Common Units (comprising performance units), or cash equivalent to the fair market value of such Common Units. In addition, the 2000 Propane Plan authorizes the crediting of Common Unit distribution equivalents to participants’ accounts. Under the Nonexecutive Propane Plan, the General Partner could grant awards to key employees who did not participate in the 2000 Propane Plan. Generally, awards under the Nonexecutive Propane Plan vest at the end of a three-year period and are paid in Common Units and cash. No additional grants will be made under the 2000 Propane Plan and the Nonexecutive Propane Plan.

Recipients of performance unit awards under the 2010 Propane Plan and the 2000 Propane Plan (“AmeriGas Performance Units”) are awarded a target number of AmeriGas Performance Units. The number of AmeriGas Performance Units ultimately paid at the end of the performance period (generally three years) may be higher or lower than the target amount based upon AmeriGas Partners’ Total Unitholder Return (“TUR”) percentile rank relative to entities in a peer group. Percentile rankings and payout percentages are generally the same as those used for the UGI Performance Unit awards. Any Common Unit distribution equivalents earned are paid in cash. Generally, except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed by the General Partner. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements.

F-40

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Under GAAP, AmeriGas Performance Units are equity awards with a market-based condition which, if settled in Common Units, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of AmeriGas Performance Units are estimated using a Monte Carlo valuation model. The fair value associated with the target award and the award above the target, if any, which will be paid in Common Units, is accounted for as equity and the fair value of all Common Unit distribution equivalents, which will be paid in cash, is accounted for as a liability. The expected term of the AmeriGas Performance Unit awards is three years based on the performance period. Expected volatility is based on the historical volatility of Common Units over a three-year period. The risk-free interest rate is based on the rates on U.S. Treasury bonds at the time of grant. Volatility for all limited partnerships in the peer group is based on historical volatility.

The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards and related compensation costs:


	Grants Awarded in Fiscal
	2011			2010			2009
Risk-free rate		1.0	%		1.7	%		1.0	%
Expected life	3 years			3 years			3 years
Expected volatility		34.6	%		35.0	%		32.0	%
Dividend yield		5.8	%		6.8	%		9.1	%

The General Partner granted awards under the 2010 Propane Plan representing 49,287, 57,750 and 60,200 Common Units in Fiscal 2011, Fiscal 2010 and Fiscal 2009, respectively, having weighted-average grant date fair values per Common Unit subject to award of $53.19, $41.39 and $31.94, respectively. At September 30, 2011, 2,747,263 Common Units were available for future award grants under the 2010 Propane Plan.

The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2011:


	Total					Vested					Non-Vested
	Number of					Number of					Number of
	AmeriGas					AmeriGas					AmeriGas
	Partners			Weighted		Partners			Weighted		Partners			Weighted
	Common			Average		Common			Average		Common			Average
	Units			Grant Date		Units			Grant Date		Units			Grant Date
	Subject			Fair Value		Subject			Fair Value		Subject			Fair Value
	to Award			(per Unit)		to Award			(per Unit)		to Award			(per Unit)
September 30, 2010		146,600		$	37.05		53,851		$	37.14		92,749		$	37.00
Granted		49,287		$	53.19		—		$	—		49,287		$	53.19
Forfeited		(2,967	)	$	35.41		—		$	—		(2,967	)	$	35.41
Vested		—		$	—		46,351		$	39.88		(46,351	)	$	39.88
Awards paid		(37,564	)	$	38.75		(37,564	)	$	38.75		—		$	—

September 30, 2011		155,356		$	41.79		62,638		$	38.20		92,718		$	44.22

F-41

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

During Fiscal 2011, Fiscal 2010 and Fiscal 2009, the Partnership paid AmeriGas Common Unit-based awards in Common Units and cash as follows:


	2011		2010		2009
Number of Common Units subject to original Awards granted		41,064		49,650		38,350
Fiscal year granted		2008		2007		2006
Payment of Awards:
AmeriGas Partners Common Units issued		35,787		42,121		36,437
Cash paid	$	1.2	$	1.2	$	0.9

As of September 30, 2011, there was a total of approximately $2.6 of unrecognized compensation cost associated with 155,356 Common Units subject to award that is expected to be recognized over a weighted-average period of 1.8 years. The total fair value of Common Unit-based awards that vested during Fiscal 2011, Fiscal 2010 and Fiscal 2009 was $2.0, $2.0 and $1.6, respectively. As of September 30, 2011 and 2010, total liabilities of $1.2 and $1.3 associated with Common Unit-based awards are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.

Note 14 — Partnership Distributions

The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount equal to its Available Cash for such quarter. Available Cash generally means:

all cash on hand at the end of such quarter,

plus all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter,

less the amount of cash reserves established by the General Partner in its reasonable discretion.

The General Partner may establish reserves for the proper conduct of the Partnership’s business and for distributions during the next four quarters.

Distributions of Available Cash are made 98% to limited partners and 2% to the General Partner (representing a 1% General Partner interest in AmeriGas Partners and 1.01% interest in AmeriGas OLP) until Available Cash exceeds the Minimum Quarterly Distribution of $0.55 and the First Target Distribution of $0.055 per Common Unit (or a total of $0.605 per Common Unit). When Available Cash exceeds $0.605 per Common Unit in any quarter, the General Partner will receive a greater percentage of the total Partnership distribution (the “incentive distribution”) but only with respect to the amount by which the distribution per Common Unit to limited partners exceeds $0.605.

During Fiscal 2011, Fiscal 2010 and Fiscal 2009, the Partnership made quarterly distributions to Common Unitholders in excess of $0.605 per limited partner unit. As a result, the General Partner has received a greater percentage of the total Partnership distribution than its aggregate 2% general partner interest in AmeriGas OLP and AmeriGas Partners. The total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $9.0 in Fiscal 2011, $6.9 in Fiscal 2010 and $8.5 in Fiscal 2009. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2011, Fiscal 2010 and Fiscal 2009 of $5.0, $3.0 and $4.5, respectively.

On July 27, 2009, the General Partner’s Board of Directors approved a distribution of $0.84 per Common Unit payable on August 18, 2009 to unitholders of record on August 10, 2009. This distribution included the regular quarterly distribution of $0.67 per Common Unit and $0.17 per Common Unit reflecting a distribution of a portion of the proceeds from the Partnership’s November 2008 sale of its California storage facility.

F-42

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Note 15 — Commitments and Contingencies

Commitments

We lease various buildings and other facilities and vehicles, computer and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such leases was $69.8 in Fiscal 2011, $70.6 in Fiscal 2010 and $70.1 in Fiscal 2009.

Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows:


											After
	2012		2013		2014		2015		2016		2016
AmeriGas Propane	$	53.8	$	45.3	$	37.2	$	29.3	$	21.1	$	40.4
UGI Utilities		4.8		4.3		3.1		2.3		2.1		2.2
International Propane		7.1		5.5		4.0		2.4		2.3		1.3
Other		2.6		2.7		1.9		1.2		0.6		0.4

Total	$	68.3	$	57.8	$	46.2	$	35.2	$	26.1	$	44.3

Our businesses enter into contracts of varying lengths and terms to meet their supply, pipeline transportation, storage, capacity and energy needs. Gas Utility has gas supply agreements with producers and marketers with terms not exceeding one year. Gas Utility also has agreements for firm pipeline transportation and natural gas storage services, which Gas Utility may terminate at various dates through Fiscal 2022. Gas Utility’s costs associated with transportation and storage capacity agreements are included in its annual PGC filings with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices. Electric Utility purchases its electricity needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2014. Midstream & Marketing enters into fixed-price contracts with suppliers to purchase natural gas and electricity to meet its sales commitments. Generally, these contracts have terms of less than two years. The Partnership enters into fixed-price and variable-priced contracts to purchase a portion of its supply requirements. These contracts generally have terms of less than one year. International Propane enters into variable-priced contracts to purchase a portion of its supply requirements that generally do not exceed one year.

The following table presents contractual obligations under Gas Utility, Electric Utility, Midstream & Marketing, AmeriGas Propane and International Propane supply, storage and service contracts existing at September 30, 2011:


											After
	2012		2013		2014		2015		2016		2016
Gas Utility and Electric Utility supply, storage and transportation contracts	$	213.0	$	103.3	$	76.2	$	47.8	$	25.0	$	64.0
Midstream & Marketing supply contracts		222.5		54.1		3.6		—		—		—
AmeriGas Propane supply contracts		65.8		—		—		—		—		—
International Propane supply contracts		23.3		—		—		—		—		—

Total	$	524.6	$	157.4	$	79.8	$	47.8	$	25.0	$	64.0

The Partnership and International Propane also enter into other contracts to purchase LPG to meet supply requirements. Generally, these contracts are one- to three-year agreements subject to annual price and quantity adjustments.

In addition, we have committed to invest upon request a total of up to an additional $8.5 in a limited partnership that focuses on investments in the alternative energy sector.

F-43

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Contingencies

Environmental Matters

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA terminates at the end of 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 and 2010, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $17.9 and $21.4, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

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 investigation 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.

South Carolina Electric & Gas Company v. UGI Utilities, Inc. On September 22, 2006, South Carolina Electric & Gas Company (“SCE&G”), a subsidiary of SCANA Corporation, filed a lawsuit against UGI Utilities in the District Court of South Carolina seeking contribution from UGI Utilities for past and future remediation costs related to the operations of a former MGP located in Charleston, South Carolina. SCE&G asserts that the plant operated from 1855 to 1954 and alleges that through control of a subsidiary that owned the plant UGI Utilities controlled operations of the plant from 1910 to 1926 and is liable for approximately 25% of the costs associated with the site. SCE&G asserts that it has spent approximately $22 in remediation costs and paid $26 in third-party claims relating to the site and estimates that future response costs, including a claim by the United States Justice Department for natural resource damages, could be as high as $14. Trial took place in March 2009 and the court’s decision is pending.

F-44

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens Communications Company, now known as Frontier Communications Company (“Frontier”), served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the City of Bangor, Maine (“City”) sued Frontier to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging that they are responsible for an equitable share of any clean up costs Frontier would be required to pay to the City. Frontier alleged that through ownership and control of a subsidiary, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. UGI Utilities filed a motion for summary judgment with respect to Frontier’s claims. On October 19, 2010, the magistrate judge recommended the Court grant UGI Utilities’ motion. On November 19, 2010, the Court affirmed the recommended decision of the magistrate judge granting summary judgment in favor of UGI Utilities. On July 1, 2011, Frontier appealed the Court’s decision to the United States Court of Appeals for the First Circuit.

Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10. KeySpan believes that the cost could be as high as $20. There have been no recent developments or facts indicating that this will have a material impact to our results of operations or financial condition.

Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies. The Northeast Companies alleged that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites in Waterbury, CT (“Waterbury North”). After a trial, on May 22, 2009, the District Court granted judgment in favor of UGI Utilities with respect to the remaining nine sites. On April 13, 2011, the United States Court of Appeals for the Second Circuit affirmed the District Court’s decision in favor of UGI Utilities. A second phase of the trial took place in August 2011 to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The District Court’s decision is pending. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25.

Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha (“City”) and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of UGI Utilities’ predecessor is identified as an owner and operator of the site. The City and MUD has requested that UGI Utilities participate in the clean up of this site. UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska and issued an information request to UGI Utilities. UGI Utilities is reviewing the EPA’s request and will cooperate with its investigation. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in Saranac Lake, New York on its Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by DEC disclosed contamination related to former MGP operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The Partnership has researched the history of the site and its ownership interest in the site. The Partnership has reviewed the preliminary site characterization study prepared by the DEC, the extent of contamination and the possible existence of other potentially responsible parties. The Partnership 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.

Other Matters

AmeriGas Cylinder Investigations. On or about October 21, 2009, the General Partner received a notice that the Offices of the District Attorneys of Santa Clara, Sonoma, Ventura, San Joaquin and Fresno Counties and the City Attorney of San Diego (the “District Attorneys”) have commenced an investigation into AmeriGas OLP’s cylinder labeling and filling practices in California and issued an administrative subpoena seeking documents and information relating to these practices. We have responded to the administrative subpoena. On or about July 20, 2011, the General Partner received a second subpoena from the District Attorneys. The subpoena seeks information and documents regarding AmeriGas OLP’s cylinder exchange program and alleges potential violations of California’s Unfair Competition Law. We reviewed and responded to the subpoena and will continue to cooperate with the District Attorneys.

F-45

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Swiger, et al. v. UGI/AmeriGas, Inc. et al. In 1996, a fire occurred at the residence of Samuel and Brenda Swiger (the “Swigers”) when propane that leaked from an underground line ignited. In July 1998, the Swigers filed a class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of Monongalia County, West Virginia, in which they sought to recover an unspecified amount of compensatory and punitive damages and attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants had installed propane gas lines, resulting from the defendants’ alleged failure to install underground propane lines at depths required by applicable safety standards. On December 14, 2010, AmeriGas OLP and its affiliates entered into a settlement agreement with the class. On August 12, 2011, the Circuit Court of Monongalia County entered a final order, dismissing all claims against AmeriGas.

In 2005, the Swigers also filed what purports to be a class action in the Circuit Court of Harrison County, West Virginia against UGI, an insurance subsidiary of UGI, certain officers of UGI and the General Partner, and their insurance carriers and insurance adjusters. In the Harrison County lawsuit, the Swigers are seeking compensatory and punitive damages on behalf of the putative class for alleged violations of the West Virginia Insurance Unfair Trade Practice Act, negligence, intentional misconduct, and civil conspiracy. The Swigers have also requested that the Court rule that insurance coverage exists under the policies issued by the defendant insurance companies for damages sustained by the members of the class in the Monongalia County lawsuit. The Circuit Court of Harrison County has not certified the class in the Harrison County lawsuit at this time and, in October 2008, stayed that lawsuit pending resolution of the class action lawsuit in Monongalia County. We believe we have good defenses to the claims in this action.

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 (€7.1) 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 net income by $9.4.

F-46

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

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

Note 16 — Fair Value Measurements

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of September 30, 2011 and 2010:


	Asset (Liability)
	Quoted Prices
	in Active			Significant
	Markets for			Other
	Identical Assets			Observable			Unobservable
	and Liabilities			Inputs			Inputs
	(Level 1)			(Level 2)			(Level 3)		Total
September 30, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	3.5		$	3.3		$	—	$	6.8
Foreign currency contracts	$	—		$	5.3		$	—	$	5.3
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(28.1	)	$	(16.1	)	$	—	$	(44.2	)
Foreign currency contracts	$	—		$	(3.3	)	$	—	$	(3.3	)
Interest rate contracts	$	—		$	(44.4	)	$	—	$	(44.4	)

September 30, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	1.1		$	10.7		$	—	$	11.8
Foreign currency contracts	$	—		$	0.8		$	—	$	0.8
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(49.4	)	$	(20.3	)	$	—	$	(69.7	)
Foreign currency contracts	$	—		$	(2.9	)	$	—	$	(2.9	)
Interest rate contracts	$	—		$	(18.5	)	$	—	$	(18.5	)

F-47

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

The fair values of our Level 1 exchange-traded commodity futures and option contracts and non exchange-traded commodity futures and forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The remainder of our derivative financial instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for and current maturities of long-term debt) approximate their fair values because of their short-term nature. At September 30, 2011, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $2,157.7 and $2,223.4, respectively. At September 30, 2010, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $2,005.8 and $2,144.7, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt.

Financial instruments other than derivative financial instruments, such as our short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit our credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative financial instruments, see Note 17.

Note 17 — Disclosures About Derivative Instruments and Hedging Activities

We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk, (2) interest rate risk and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Because most of our derivative instruments generally qualify as hedges under GAAP or are subject to regulatory rate recovery mechanisms, we expect that changes in the fair value of derivative instruments used to manage commodity, interest rate or currency exchange rate risk would be substantially offset by gains or losses on the associated anticipated transactions.

Commodity Price Risk

In order to manage market price risk associated with the Partnership’s fixed-price programs which permit customers to lock in the prices they pay for propane principally during the months of October through March, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units and our International Propane operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. In addition, from time to time, the Partnership enters into price swap agreements to provide market price risk support to some of its wholesale customers. These agreements are not designated as hedges for accounting purposes and the volumes of propane subject to these agreements were not material.

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At September 30, 2011 and 2010, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 15.1 million dekatherms and 19.5 million dekatherms, respectively. At September 30, 2011, the maximum period over which Gas Utility is hedging natural gas market price risk is 13 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets in accordance with FASB’s guidance in ASC 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 8).

F-48

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At September 30, 2011 and 2010, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $8.7 and $19.7, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Consolidated Balance Sheets. In accordance with ASC 980 related to rate regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At September 30, 2011 and 2010, the volumes of Electric Utility’s forward electricity purchase contracts was 788.6 million kilowatt hours and 990.7 million kilowatt hours, respectively. At September 30, 2011, the maximum period over which these contracts extend is 32 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 8). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At September 30, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 208.6 million kilowatt hours and 546.8 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At September 30, 2011 and 2010, the volumes associated with Midstream & Marketing’s FTRs totaled 1,418.6 million kilowatt hours and 1,026.4 million kilowatt hours, respectively.

In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas and electricity futures contracts. 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. 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. Because the contracts associated with the anticipated sale of stored natural gas or propane do not qualify for hedge accounting treatment, any gains or losses on the derivative contracts are recognized in earnings prior to gains or losses from the sale of the stored gas. Such derivative gains or losses during Fiscal 2011 were not material. At September 30, 2011, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 4.2 million dekatherms and 4.0 million gallons, respectively.

In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment. Associated volumes, fair values and effects on net income were not material for all periods presented.

F-49

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

At September 30, 2011 and 2010, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:


	Volumes
Commodity	2011		2010
LPG (millions of gallons)		138.0		160.0
Natural gas (millions of dekatherms, net)		26.1		36.3
Electricity calls (millions of kilowatt hours)		1,219.8		1,203.8
Electricity puts (millions of kilowatt hours)		204.9		—

At September 30, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 12 months with a weighted average of 5 months; the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 37 months with a weighted average of 9 months; and the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity price risk (excluding Electric Utility) is 22 months for electricity call contracts, with a weighted average of 7 months, and 27 months for electricity put contracts, with a weighted average of 14 months. At September 30, 2011, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 8 months.

We account for commodity price risk contracts (other than those contracts that are not eligible for hedge accounting and Gas Utility and Electric Utility contracts that are subject to regulatory treatment) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales on the Consolidated Statements of Income. At September 30, 2011, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $32.1.

Interest Rate Risk

Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on a substantial portion of its term loans, in each case through the respective scheduled maturity dates. As of September 30, 2011 and 2010, the total notional amounts of existing and anticipated variable-rate debt subject to interest rate swap agreements were €424.2 and €703.2, respectively.

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At September 30, 2011, the total notional amount of unsettled IRPAs was $173. There were no unsettled IRPAs outstanding at September 30, 2010. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt forecasted to occur in September 2012 and September 2013.

We account for interest rate swaps and IRPAs as cash flow hedges. Changes in the fair values of interest rate swaps and IRPAs are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At September 30, 2011, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $1.2.

F-50

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At September 30, 2011 and 2010, we were hedging a total of $133.9 and $108.6 of U.S. dollar-denominated LPG purchases, respectively. At September 30, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 30 months with a weighted average of 11 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At September 30, 2011 and 2010, we were hedging a total of €14.5 and €10.0, respectively, of our euro-denominated net investments. As of September 30, 2011, such foreign currency contracts extend through September 2012.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At September 30, 2011, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $2.5. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.

On October 14, 2011, the Company acquired certain European LPG businesses from Shell (see Note 22). 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 30, 2011, we were hedging a total of €120 of the euro-denominated purchase price. Losses recorded on these contracts through September 30, 2011 totaled $6.1.

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 or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and options contracts generally require cash deposits in margin accounts. At September 30, 2011 and 2010, restricted cash in brokerage accounts totaled $17.2 and $34.8, respectively. Although we have concentrations of credit risk associated with derivative financial instruments, the maximum amount of loss, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at September 30, 2011. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At September 30, 2011, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

F-51

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

The following table provides information regarding the balance sheet location and fair value of derivative assets and liabilities existing as of September 30, 2011 and 2010:


	Derivative Assets					Derivative Liabilities
		Fair Value					Fair Value
	Balance Sheet	September 30,				Balance Sheet	September 30,
	Location	2011		2010		Location	2011			2010
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments					Derivative financial instruments
	and Other assets	$	1.1	$	9.2	and Other noncurrent liabilities	$	(32.5	)	$	(48.6	)
Foreign currency contracts	Derivative financial instruments					Derivative financial instruments
	and Other assets		5.2		0.8	and Other noncurrent liabilities		—			(2.9	)
Interest rate contracts						Derivative financial instruments
						and Other noncurrent liabilities		(44.4	)		(18.5	)

Total Derivatives Designated as Hedging Instruments		$	6.3	$	10.0		$	(76.9	)	$	(70.0	)


Derivatives Accounted for Under ASC 980:
Commodity contracts	Derivative financial instruments	$	—	$	0.4	Derivative financial instruments and Other noncurrent liabilities	$	(11.7	)	$	(21.1	)

Derivatives Not Designated as Hedging Instruments:
Foreign currency contracts						Derivative financial instruments	$	(3.3	)	$	—
Commodity contracts	Derivative financial instruments
	and Other assets	$	5.8	$	2.2

Total Derivatives Not Designated as Hedging Instruments		$	5.8	$	2.2		$	(3.3	)	$	—


Total Derivatives		$	12.1	$	12.6		$	(91.9	)	$	(91.1	)

F-52

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

The following tables provide information on the effects of derivative instruments on the Consolidated Statement of Income and changes in AOCI and noncontrolling interest for Fiscal 2011 and 2010:


	Gain or (Loss)									Gain or (Loss)									Location of
	Recognized in									Reclassified from									Gain or (Loss)
	AOCI and									AOCI and Noncontrolling									Reclassified from
	Noncontrolling Interests									Interests into Income									AOCI and Noncontrolling
	2011			2010			2009			2011			2010			2009			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	2.2		$	(41.7	)	$	(241.1	)	$	(17.4	)	$	(21.0	)	$	(305.8	)	Cost of sales
Foreign currency contracts		6.9			3.2			(2.1	)		(0.8	)		0.7			5.0		Cost of sales
Interest rate contracts		(35.8	)		(12.6	)		(46.7	)		(14.1	)		(28.2	)		(7.0	)	Interest expense /other income

Total	$	(26.7	)	$	(51.1	)	$	(289.9	)	$	(32.3	)	$	(48.5	)	$	(307.8	)

Net Investment Hedges:
Foreign currency contracts	$	0.2		$	5.0		$	(2.0	)

Derivatives Not Designated as Hedging Instruments:


	Gain or (Loss)
	Recognized in Income								Location of Gain or (Loss)
	2011			2010		2009			Recognized in Income
Commodity contracts	$	2.1		$	1.3	$	(0.6	)	Cost of sales
Commodity contracts		0.3			0.2		0.7		Operating expenses / other income
Foreign currency contracts		(6.1	)		—		—		Other income

Total	$	(3.7	)	$	1.5	$	0.1

The amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material for Fiscal 2011, Fiscal 2010 and Fiscal 2009.

As a result of the Partnership’s refinancing of its 7.125% Senior Notes (see Note 5), during the three months ended September 30, 2011, the Partnership discontinued cash flow hedge accounting for settled but unamortized IRPA losses associated with the Senior Notes and recorded a loss of $2.6 which amount is included in “Loss on extinguishments of debt” on the Fiscal 2011 Consolidated Statement of Income. During the three months ended March 31, 2010, the Partnership’s management determined that it was likely that the Partnership would not issue $150 of long-term debt during the summer of 2010 due to the Partnership’s strong cash flow and anticipated extension of all or a portion of the 2009 AmeriGas Supplemental Credit Agreement. As a result, the Partnership discontinued cash flow hedge accounting treatment for IRPAs associated with this previously anticipated Fiscal 2010 $150 long-term debt issuance and recorded a $12.2 loss which is reflected in “other income, net” on the Fiscal 2010 Consolidated Statement of Income. During Fiscal 2009, the Partnership recorded a loss of $1.7 as a result of the discontinuance of cash flow hedge accounting associated with IRPAs which amount was also reflected in “other income, net”.

We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery, or sale, of natural gas, LPG and electricity, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although many of these contracts have the requisite elements of a derivative instrument, these contracts qualify for normal purchases and normal sales exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

F-53

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Note 18 — Energy Services Accounts Receivable Securitization Facility

Energy Services has a $200 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in April 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.

Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special-purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables following the FASB’s guidance for accounting for transfers of financial assets and extinguishments of liabilities. Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC.

Effective October 1, 2010, the Company adopted a new accounting standard that changes the accounting for the Receivables Facility on a prospective basis (see Note 3). Effective October 1, 2010, trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet; the Company reflects a liability equal to the amount advanced by the commercial paper conduit; and the Company records interest expense on amounts sold to the commercial paper conduit. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet and any losses on sales of accounts receivable were reflected in “other income, net.”

During Fiscal 2011, Fiscal 2010 and Fiscal 2009, Energy Services transferred trade receivables totaling $1,134.9, $1,147.3 and $1,247.1, respectively, to ESFC. During Fiscal 2011, Fiscal 2010 and Fiscal 2009, ESFC sold an aggregate $88.0, $254.6 and $596.9, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At September 30, 2011, the outstanding balance of ESFC trade receivables was $52.1 and there was $14.3 sold to the commercial paper conduit and reflected on the balance sheet as bank loans. At September 30, 2010, the outstanding balance of ESFC trade receivables was $44.0 which is net of $12.1 that was sold to the commercial paper conduit and removed from the balance sheet. Losses on sales of receivables to the commercial paper conduit during Fiscal 2011, which amounts are included in “Interest expense,” totaled $1.2. Losses on sales of receivables to the commercial paper conduit during Fiscal 2010 and Fiscal 2009, which amounts are included in “Other income, net,” were $1.5 and $2.3, respectively.

F-54

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Note 19 — Other Income, Net

Other income, net, comprises the following:


	2011			2010			2009
Interest and interest-related income	$	2.3		$	2.9		$	5.0
Antargaz Competition Authority Matter		9.4			—			(10.0	)
Utility non-tariff service income		6.4			2.4			3.2
Foreign currency hedge loss		(6.1	)		—			—
Gain on sale of Partnership LPG storage facility		—			—			39.9
Gain on sale of Atlantic Energy, LLC		—			36.5			—
Finance charges		15.1			11.3			11.7
Partnership interest rate protection agreement losses		—			(12.2	)		(1.7	)
Other, net		19.4			17.1			7.8

Total other income, net	$	46.5		$	58.0		$	55.9

Note 20 — Quarterly Data (unaudited)

The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) which we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results fluctuate because of the seasonal nature of our businesses.


	December 31,					March 31,					June 30,						September 30,
	2010 (a)			2009		2011 (b)			2010 (c)		2011			2010			2011 (d)			2010 (e)
Revenues	$	1,765.6		$	1,618.8	$	2,181.0		$	2,120.3	$	1,105.4		$	961.9		$	1,039.3		$	890.4
Operating income (loss)	$	252.3		$	243.2	$	357.0		$	366.0	$	17.2		$	31.2		$	(10.5	)	$	18.8
Loss from equity investees	$	(0.2	)	$	—	$	(0.4	)	$	—	$	(0.2	)	$	(1.9	)	$	(0.1	)	$	(0.2	)
Loss on extinguishments of debt	$	—		$	—	$	(18.8	)	$	—	$	—		$	—		$	(19.3	)	$	—
Net income (loss)	$	155.0		$	145.5	$	215.6		$	232.8	$	(13.5	)	$	(4.2	)	$	(48.9	)	$	(18.4	)
Net income (loss) attributable to UGI Corporation	$	113.1		$	98.4	$	149.4		$	157.1	$	(7.2	)	$	3.4		$	(22.4	)	$	2.1
Earnings (loss) per share attributable to UGI stockholders:
Basic	$	1.02		$	0.90	$	1.34		$	1.44	$	(0.06	)	$	0.03		$	(0.20	)	$	0.02
Diluted	$	1.01		$	0.90	$	1.32		$	1.43	$	(0.06	)	$	0.03		$	(0.20	)	$	0.02


(a)		Includes the reversal of previously recorded nontaxable accrual associated with the Antargaz Competition Authority Matter which increased operating income and net income attributable to UGI Corporation by $9.4 or $0.08 per diluted share (see Note 15).

(b)		Includes loss on extinguishment of Partnership long-tem debt which decreased net income attributable to UGI Corporation by $5.2 or $0.05 per diluted share (see Note 5).

(c)		Includes loss from discontinuance of cash flow hedge accounting treatment for Partnership IRPAs which decreased operating income by $12.2 and net income attributable to UGI Corporation by $3.3 or $0.03 per diluted share (see Note 17).

(d)		Includes loss on extinguishment of Partnership long-tem debt which decreased net income attributable to UGI Corporation by $5.2 or $0.05 per diluted share (see Note 5).

(e)		Includes a gain from the sale of Atlantic Energy, LLC which increased operating income by $36.5 and net income attributable to UGI Corporation by $17.2 or $0.16 per diluted share (see Note 4).

F-55

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Note 21 — Segment Information

We have organized our business units into six reportable segments generally based upon products sold, geographic location (domestic or international) and regulatory environment. Our reportable segments are: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment comprising Flaga and our other international propane businesses other than Antargaz (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Midstream & Marketing. We refer to both international segments collectively as “International Propane.”

AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers in all 50 states. Our International Propane segments’ revenues are derived principally from the distribution of LPG to retail customers in France and northern, central and eastern Europe including Austria and Denmark. Gas Utility’s revenues are derived principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania. Electric Utility derives its revenues principally from the distribution of electricity in two northeastern Pennsylvania counties. Midstream & Marketing revenues are derived from the sale of natural gas and, to a lesser extent, LPG, electricity and fuel oil to customers located primarily in the Mid-Atlantic region of the United States.

The accounting policies of our reportable segments are the same as those described in Note 2. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Our definition of Partnership EBITDA may be different from that used by other companies. We evaluate the performance of our International Propane, Gas Utility, Electric Utility and Midstream & Marketing segments principally based upon their income before income taxes.

No single customer represents more than ten percent of our consolidated revenues. In addition, all of our reportable segments’ revenues, other than those of our International Propane segments, are derived from sources within the United States, and all of our reportable segments’ long-lived assets, other than those of our International Propane segments, are located in the United States.

F-56

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)


							Reportable Segments
																			International Propane
				Elim-			AmeriGas						Electric			Midstream &						Flaga &			Corporate &
	Total			inations			Propane			Gas Utility			Utility			Marketing			Antargaz			Other (b)			Other (c)
2011
Revenues	$	6,091.3		$	(219.8)	(d)	$	2,538.0		$	1,026.4		$	109.1		$	1,059.7		$	1,050.6		$	438.1		$	89.2
Cost of sales	$	4,010.9		$	(215.3)	(d)	$	1,605.3		$	610.6		$	67.9		$	920.0		$	649.8		$	321.0		$	51.6
Operating income (loss)	$	616.0		$	—		$	242.9		$	199.6		$	11.4		$	82.9		$	89.2		$	(3.1	)	$	(6.9	)
Loss from equity investees		(0.9	)		—			—			—			—			—			(0.9	)		—			—
Loss on extinguishments of debt		(38.1	)		—			(38.1	)		—			—			—			—			—			—
Interest expense		(138.0	)		—			(63.5	)		(40.4	)		(2.4	)		(2.7	)		(25.5	)		(2.7	)		(0.8	)

Income (loss) before income taxes	$	439.0		$	—		$	141.3		$	159.2		$	9.0		$	80.2		$	62.8		$	(5.8	)	$	(7.7	)
Net income (loss) attributable to UGI	$	232.9		$	—		$	39.9		$	99.3		$	5.7		$	52.5		$	44.2		$	(3.2	)	$	(5.5	)
Depreciation and amortization	$	227.9		$	—		$	94.7		$	48.4		$	4.2		$	8.0		$	52.1		$	18.5		$	2.0
Noncontrolling interests’ net income	$	75.3		$	—		$	75.0		$	—		$	—		$	—		$	0.3		$	—		$	—
Partnership EBITDA (a)							$	297.1
Total assets	$	6,663.3		$	(93.3	)	$	1,800.4		$	2,028.7		$	140.6		$	580.7		$	1,636.6		$	428.8		$	140.8
Bank loans	$	138.7		$	—		$	95.5		$	—		$	—		$	24.3		$	—		$	18.9		$	—
Capital expenditures	$	355.6		$	—		$	77.2		$	91.3		$	7.5		$	112.8		$	48.9		$	16.5		$	1.4
Investments in equity investees	$	0.3		$	—		$	—		$	—		$	—		$	—		$	—		$	0.3		$	—
Goodwill	$	1,562.2		$	—		$	696.3		$	182.1		$	—		$	2.8		$	591.8		$	82.2		$	7.0


2010
Revenues	$	5,591.4		$	(186.0)	(d)	$	2,320.3		$	1,047.5		$	120.2		$	1,145.9		$	887.1		$	172.4		$	84.0
Cost of sales	$	3,584.0		$	(179.2)	(d)	$	1,395.1		$	653.4		$	77.1		$	1,010.7		$	465.9		$	116.2		$	44.8
Operating income (loss)	$	659.2		$	—		$	235.8		$	175.3		$	13.7		$	120.0		$	115.1		$	1.9		$	(2.6	)
Loss from equity investees		(2.1	)		—			—			—			—			—			(2.0	)		(0.1	)		—
Interest expense		(133.8	)		—			(65.1	)		(40.5	)		(1.8	)		(0.2	)		(22.4	)		(3.0	)		(0.8	)

Income (loss) before income taxes	$	523.3		$	—		$	170.7		$	134.8		$	11.9		$	119.8		$	90.7		$	(1.2	)	$	(3.4	)
Net income (loss) attributable to UGI	$	261.0		$	—		$	47.3		$	83.1		$	6.8		$	68.2		$	60.0		$	(1.2	)	$	(3.2	)
Depreciation and amortization	$	210.2		$	—		$	87.4		$	49.5		$	4.0		$	7.7		$	48.9		$	11.5		$	1.2
Noncontrolling interests’ net income	$	94.7		$	—		$	91.1		$	—		$	—		$	3.3		$	0.3		$	—		$	—
Partnership EBITDA (a)							$	321.0
Total assets	$	6,374.3		$	(81.1	)	$	1,690.9		$	1,996.3		$	143.3		$	450.8		$	1,678.3		$	320.2		$	175.6
Bank loans	$	200.4		$	—		$	91.0		$	17.0		$	—		$	—		$	68.2		$	24.2		$	—
Capital expenditures	$	352.9		$	—		$	83.2		$	73.5		$	8.1		$	116.4		$	51.4		$	7.6		$	12.7
Investments in equity investees	$	0.4		$	—		$	—		$	—		$	—		$	—		$	—		$	0.4		$	—
Goodwill	$	1,562.7		$	—		$	683.1		$	180.1		$	—		$	2.8		$	602.7		$	87.0		$	7.0


2009
Revenues	$	5,737.8		$	(172.5)	(d)	$	2,260.1		$	1,241.0		$	138.5		$	1,224.7		$	837.7		$	117.6		$	90.7
Cost of sales	$	3,670.6		$	(167.7)	(d)	$	1,316.5		$	853.2		$	91.6		$	1,098.5		$	362.4		$	67.1		$	49.0
Operating income (loss)	$	685.3		$	—		$	300.5		$	153.5		$	15.4		$	64.8		$	142.8		$	8.6		$	(0.3	)
Loss from equity investees		(3.1	)		—			—			—			—			—			(2.9	)		(0.2	)		—
Interest expense		(141.1	)		—			(70.3	)		(42.2	)		(1.7	)		—			(24.0	)		(2.6	)		(0.3	)

Income (loss) before income taxes	$	541.1		$	—		$	230.2		$	111.3		$	13.7		$	64.8		$	115.9		$	5.8		$	(0.6	)
Net income attributable to UGI	$	258.5		$	—		$	65.0		$	70.3		$	8.0		$	38.1		$	74.0		$	4.3		$	(1.2	)
Depreciation and amortization	$	200.9		$	—		$	83.9		$	47.2		$	3.9		$	8.5		$	47.7		$	8.8		$	0.9
Noncontrolling interests’ net income (loss)	$	123.5		$	0.2		$	123.6		$	—		$	—		$	—		$	(0.4	)	$	0.1		$	—
Partnership EBITDA (a)							$	381.4
Total assets	$	6,042.6		$	(115.5	)	$	1,647.7		$	1,917.1		$	113.2		$	344.1		$	1,705.6		$	260.1		$	170.3
Bank loans	$	163.1		$	—		$	—		$	145.9		$	8.1		$	—		$	—		$	9.1		$	—
Capital expenditures	$	301.7		$	—		$	78.7		$	73.8		$	5.3		$	66.2		$	70.5		$	5.8		$	1.4
Investments in equity investees	$	3.0		$	—		$	—		$	—		$	—		$	—		$	—		$	3.0		$	—
Goodwill	$	1,582.3		$	(4.1	)	$	670.1		$	180.1		$	—		$	11.8		$	646.9		$	70.4		$	7.1


(a)		The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:


Year ended September 30,	2011			2010			2009
Partnership EBITDA	$	297.1		$	321.0		$	381.4	(i)
Depreciation and amortization		(94.7	)		(87.4	)		(83.9	)
Loss on extinguishments of debt		38.1			—			—
Noncontrolling interests (ii)		2.4			2.2			3.0

Operating income	$	242.9		$	235.8		$	300.5


(i)		Includes $39.9 gain on the sale of California storage facility. See Note 4 to consolidated financial statements.

(ii)		Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

(b)		International Propane — Flaga & Other principally comprises FLAGA, including, prior to the January 29, 2009 purchase of the 50% equity interest it did not already own, its central and eastern European joint-venture ZLH, and our propane distribution businesses in China and Denmark.

(c)		Corporate & Other results principally comprise UGI Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC/R”), net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate and Other assets principally comprise cash, short-term investments, assets of HVAC/R and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.

(d)		Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.

F-57

UGI Corporation and Subsidiaries
Notes to Consolidated Financial Statements
(Millions of dollars and euros, except per share amounts and where indicated otherwise)

Note 22 — 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 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 $2,900, including $1,500 in cash, AmeriGas Partners Common Units valued at approximately $1,300 at the time of the execution of the agreement, and the assumption of $71 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 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. AmeriGas Partners expects to complete the Acquisition by March 31, 2012.

F-58

UGI CORPORATION AND SUBSIDIARIES

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)

BALANCE SHEETS
(Millions of dollars)


	September 30,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	0.4		$	1.0
Accounts and notes receivable		4.9			18.8
Deferred income taxes		0.4			0.4
Prepaid expenses and other current assets		1.4			0.3

Total current assets		7.1			20.5

Investments in subsidiaries		1,992.1			1,830.1
Derivative financial instruments		—			0.8
Deferred income taxes		22.3			20.9

Total assets	$	2,021.5		$	1,872.3


LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts and notes payable	$	11.4		$	15.8
Derivative financial instruments		3.3			—
Accrued liabilities		1.7			5.0

Total current liabilities		16.4			20.8

Noncurrent liabilities		27.4			27.0

Commitments and contingencies (Note 1)

Common stockholders’ equity:
Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,507,094 and 115,400,294 shares, respectively)		937.4			906.1
Retained earnings		1,085.8			966.7
Accumulated other comprehensive loss		(17.7	)		(10.1	)
Treasury stock, at cost		(27.8	)		(38.2	)

Total common stockholders’ equity		1,977.7			1,824.5


Total liabilities and common stockholders’ equity	$	2,021.5		$	1,872.3


Note 1		— Commitments and Contingencies:

In addition to the guarantees of Flaga’s and Antargaz’ debt as described in Note 5 to Consolidated Financial Statements, at September 30, 2011, UGI Corporation had agreed to indemnify the issuers of $32.7 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to $385.0 of obligations to suppliers and customers of UGI Energy Services, Inc. and subsidiaries of which $349.4 of such obligations were outstanding as of September 30, 2011. UGI Corporation has guaranteed the floating to fixed rate interest rate swaps at Flaga which amount totaled $2.5 at September 30, 2011.

S-1

UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)

STATEMENTS OF INCOME
(Millions of dollars, except per share amounts)


	Year Ended
	September 30,
	2011			2010			2009
Revenues	$	—		$	—		$	—

Costs and expenses:
Operating and administrative expenses		31.0			31.8			33.7
Other income, net (1)		(24.8	)		(31.7	)		(33.7	)

		6.2			0.1			—


Operating loss		(6.2	)		(0.1	)		—
Intercompany interest income		0.1			—			0.1


Loss (income) before income taxes		(6.1	)		(0.1	)		0.1
Income tax (benefit) expense		(1.1	)		0.7			0.8


Loss before equity in income of unconsolidated subsidiaries		(5.0	)		(0.8	)		(0.7	)
Equity in income of unconsolidated subsidiaries		237.9			261.8			259.2


Net income	$	232.9		$	261.0		$	258.5



Earnings per common share:
Basic	$	2.09		$	2.38		$	2.38


Diluted	$	2.06		$	2.36		$	2.36


Average common shares outstanding (thousands):
Basic		111,674			109,588			108,523

Diluted		112,944			110,511			109,339


(1)		UGI provides certain financial and administrative services to certain of its subsidiaries. UGI bills these subsidiaries monthly for all direct expenses incurred by UGI on behalf of its subsidiaries as well as allocated shares of indirect corporate expense incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to certain of its subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed and considers the relative percentage of such items for each subsidiary to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to its subsidiaries. These billed expenses are classified as “Other income, net” in the Statements of Income above.

S-2

UGI CORPORATION AND SUBSIDIARIES
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)

STATEMENTS OF CASH FLOWS
(Millions of dollars)


	Year Ended
	September 30,
	2011			2010			2009
NET CASH PROVIDED BY OPERATING ACTIVITIES (a)	$	201.6		$	173.0		$	124.7

CASH FLOWS FROM INVESTING ACTIVITIES:
Net investments in unconsolidated subsidiaries		(119.4	)		(106.6	)		(50.4	)


Net cash used by investing activities		(119.4	)		(106.6	)		(50.4	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends on Common Stock		(113.8	)		(98.6	)		(85.1	)
Issuance of Common Stock		31.0			31.8			10.8

Net cash used by financing activities		(82.8	)		(66.8	)		(74.3	)


Cash and cash equivalents decrease	$	(0.6	)	$	(0.4	)	$	—


Cash and cash equivalents:
End of year	$	0.4		$	1.0		$	1.4
Beginning of year		1.0			1.4			1.4

Decrease	$	(0.6	)	$	(0.4	)	$	—


(a)		Includes dividends received from unconsolidated subsidiaries of $188.9, $172.8 and $110.7, for the years ended September 30, 2011, 2010 and 2009, respectively.

S-3

UGI CORPORATION AND SUBSIDIARIES

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Millions of dollars)


			Charged
	Balance at		(credited)						Balance at
	beginning		to costs and						end of
	of year		expenses			Other			year
Year Ended September 30, 2011
Reserves deducted from assets in the consolidated balance sheet:

Allowance for doubtful accounts	$	34.6	$	20.0		$	(17.8)	(1)	$	36.8


Other reserves:
Property and casualty liability	$	65.7	$	22.5		$	(26.5)	(3)	$	65.3	(5)

							3.6	(2)

Environmental, litigation and other	$	65.8	$	(5.3	)	$	(25.4)	(3)	$	36.9

							1.8	(2)

Deferred tax assets valuation allowance	$	78.4	$	3.5					$	81.9



Year Ended September 30, 2010
Reserves deducted from assets in the consolidated balance sheet:

Allowance for doubtful accounts	$	38.3	$	27.1		$	(30.8)	(1)	$	34.6


Other reserves:
Property and casualty liability	$	72.3	$	15.2		$	(27.4)	(3)	$	65.7	(5)

							5.6	(2)

Environmental, litigation and other	$	66.3	$	5.4		$	(4.9)	(3)	$	65.8

							(1.0)	(2)

Deferred tax assets valuation allowance	$	87.8	$	(9.4	)				$	78.4

S-4

UGI CORPORATION AND SUBSIDIARIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS (continued)
(Millions of dollars)


Year Ended September 30, 2009
Reserves deducted from assets in the consolidated balance sheet:

Allowance for doubtful accounts	$	40.8	$	34.1	$	(42.3)	(1)	$	38.3

						5.7	(4)

Other reserves:
Property and casualty liability	$	77.4	$	22.7	$	(32.6)	(3)	$	72.3	(5)

						4.6	(4)
						0.2	(2)
Environmental, litigation and other	$	31.4	$	20.5	$	(5.5)	(3)	$	66.3

						13.9	(4)
						6.0	(2)

Deferred tax assets valuation allowance	$	56.5	$	31.3	$	—		$	87.8


(1)		Uncollectible accounts written off, net of recoveries.

(2)		Other adjustments.

(3)		Payments, net.

(4)		Acquisition.

(5)		At September 30, 2011, 2010 and 2009, the Company had insurance indemnification receivables associated with its property and casualty liabilities totaling $11.3, $7.2 and $1.0, respectively.

S-5