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, 2010

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(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, 2010 was $2,848,571,109.

At November 15, 2010 there were 110,466,049 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 20, 2011 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			20
Item 1B. Unresolved Staff Comments			26
Item 3. Legal Proceedings			26
Item 4. ( Removed and Reserved )			26
PART II:			27
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			27
Item 6. Selected Financial Data			28
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			57
Item 8. Financial Statements and Supplementary Data			57
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			57
Item 9A. Controls and Procedures			57
Item 9B. Other Information			57
PART III:			58
Item 10. Directors, Executive Officers and Corporate Governance			58
Item 11. Executive Compensation			58
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			58
Item 13. Certain Relationships and Related Transactions and Director Independence			58
Item 14. Principal Accounting Fees and Services			58
PART IV:			61
Item 15. Exhibits and Financial Statement Schedules			61
Signatures			73
Index to Financial Statements and Financial Statement Schedules			F-2
Exhibit 10.5
Exhibit 10.7
Exhibit 10.31a
Exhibit 10.31b
Exhibit 10.32a
Exhibit 10.33
Exhibit 10.37
Exhibit 10.39
Exhibit 10.42
Exhibit 10.46
Exhibit 10.47
Exhibit 10.48
Exhibit 10.51
Exhibit 10.52
Exhibit 10.60
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 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other 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 and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) large customer, counter-party or supplier defaults; (12) liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and 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; and (18) the timing and success of our acquisitions, commercial initiatives and investments to grow our businesses.

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

The AmeriGas Propane segment consists of the propane distribution business of AmeriGas Partners, L.P. (“AmeriGas Partners” or the “Partnership”) which is the nation’s largest retail propane distributor. The Partnership’s sole general partner is our subsidiary, AmeriGas Propane, Inc. (“AmeriGas Propane” or the “General Partner”). The common units of AmeriGas Partners represent limited partner interests in a Delaware limited partnership; they trade on the New York Stock Exchange under the symbol “APU.” We have an effective 44% ownership interest in the Partnership; the remaining interest is publicly held. See Note 1 to Consolidated Financial Statements.

The International Propane-Antargaz segment consists of the LPG distribution business of our wholly owned subsidiary Antargaz, a French société anonyme (“Antargaz”). The International Propane — Other segment consists of the LPG distribution businesses of Flaga GmbH, an Austrian corporation, and its subsidiaries (“Flaga”), Kosan Gas A/S, a Danish company managed by Flaga, and a majority-owned Delaware limited partnership, China Gas Partners, L.P. Antargaz is one of the largest retail distributors of LPG in France. Flaga is the largest retail LPG distributor in Austria and one of the largest in the Czech Republic, Slovakia and Hungary. Kosan Gas is the largest LPG distributor in Denmark. China Gas Partners is an LPG distributor in the Nantong region of China.

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 568,000 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 a small service territory, the Maryland Public Service Commission. Electric Utility is regulated by the PUC.

The Midstream & Marketing segment (formerly, Energy Services) consists of energy-related businesses conducted by UGI Energy Services, Inc. and a number of its subsidiaries. These businesses include (i) energy marketing in the eastern region of the United States under the trade name GASMARK ^® , (ii) generating electricity in Pennsylvania, including through solar 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 pipelines, gathering infrastructure and gas storage facilities to serve customers 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 as a marketer and distributor of energy products and services. We are utilizing our core competencies from our existing businesses and our national scope, international experience, extensive asset base and access to customers to accelerate both internal growth and growth through acquisitions in our existing businesses, as well as in related and complementary businesses. During fiscal year 2010, we completed a number of transactions in pursuit of this strategy and moved forward on a number of larger internally generated capital projects and renewable energy projects.

Corporate Information

UGI Corporation was incorporated in Pennsylvania in 1991. UGI Corporation is not subject to regulation by the PUC. UGI Corporation is a “holding company” under the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). PUHCA 2005 and the implementing regulations of the Federal Energy Regulatory Commission (“FERC”) give FERC access to certain holding company books and records and impose certain accounting, record-keeping, and reporting requirements on holding companies. PUHCA 2005 also provides state utility regulatory commissions with access to holding company books and records in certain circumstances. Pursuant to a waiver granted in accordance with FERC’s regulations on the basis of UGI Corporation’s status as a single-state holding company system, UGI Corporation is not subject to certain of the accounting, record-keeping, and reporting requirements prescribed by FERC’s regulations.

Our executive offices are located at 460 North Gulph Road, King of Prussia, Pennsylvania 19406, and our telephone number is (610) 337-1000. In this report, the terms “Company” and “UGI,” as well as the terms “our,” “we,” and “its,” are sometimes used as abbreviated references to UGI Corporation or, collectively, UGI Corporation and its consolidated subsidiaries. Similarly, the terms “AmeriGas Partners” and the “Partnership” are sometimes used as abbreviated references to AmeriGas Partners, L.P. or, collectively, AmeriGas Partners, L.P. and its subsidiaries and the term “UGI Utilities” is sometimes used as an abbreviated reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries. The terms “Fiscal 2010” and “Fiscal 2009” refer to the fiscal years ended September 30, 2010 and September 30, 2009, respectively.

The Company’s corporate website can be found at www.ugicorp.com. The Company makes available free of charge at this website (under the “Investor Relations and Corporate Governance — SEC Filings” caption) copies of its reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, including its Annual Reports on Form 10-K, its Quarterly Reports on Form 10-Q and its Current Reports on Form 8-K. The Company’s Principles of Corporate Governance, Code of Ethics for the Chief Executive Officer and Senior Financial Officers, Code of Business Conduct and Ethics for Directors, Officers and Employees, and charters of the Corporate Governance, Audit and Compensation and Management Development Committees of the Board of Directors are also available on the Company’s website, under the caption “Investor Relations and Corporate Governance-Corporate Governance.” All of these documents are also available free of charge by writing to Hugh J. Gallagher, Director, Treasury Services and Investor Relations, 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. In certain areas, the Partnership also installs and services propane fuel systems for motor vehicles. Typically, district locations are found in suburban and rural areas where natural gas is not readily available. Districts generally consist of an office, appliance showroom, warehouse, and service facilities, with one or more 18,000 to 30,000 gallon storage tanks on the premises. As part of its overall transportation and distribution infrastructure, the Partnership operates as an interstate carrier in 48 states throughout the continental United States. It is also licensed as a carrier in the Canadian Provinces of Ontario and Quebec.

The Partnership sells propane primarily to residential, commercial/industrial, motor fuel, agricultural and wholesale customers. The Partnership distributed over one billion gallons of propane in Fiscal 2010. Approximately 87% of the Partnership’s Fiscal 2010 sales (based on gallons sold) were to retail accounts and approximately 13% were to wholesale customers. Sales to residential customers in Fiscal 2010 represented approximately 40% of retail gallons sold; commercial/industrial customers 37%; motor fuel customers 13%; and agricultural customers 5%. Transport gallons, which are large-scale deliveries to retail customers other than residential, accounted for 5% of Fiscal 2010 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, 2010, ACE cylinders were available at approximately 30,000 retail locations throughout the United States. Sales of our ACE grill cylinders to retailers are included in commercial/industrial sales. The ACE program enables consumers to purchase or exchange their empty propane grill cylinders at various retail locations such as home centers, gas stations, mass merchandisers and grocery and convenience stores. We also supply retailers with large propane tanks to enable retailers to replenish customers’ propane grill cylinders directly at the retailer’s location.

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

Retail deliveries of propane are usually made to customers by means of bobtail and rack trucks. Propane is pumped from the bobtail truck, which generally holds 2,400 to 3,000 gallons of propane, into a stationary storage tank on the customer’s premises. The Partnership owns most of these storage tanks and leases them to its customers. The capacity of these tanks ranges from approximately 120 gallons to approximately 1,200 gallons. The Partnership also delivers propane in portable cylinders, including ACE propane grill 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 the year ended September 30, 2010, 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 2011. If supply from major sources were interrupted, however, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, margins could be affected. BP Products North America Inc. and BP Canada Energy Marketing Corp. (collectively), Enterprise Products Operating LP and Targa Midstream Services LP, supplied approximately 43% of the Partnership’s Fiscal 2010 propane supply. No other single supplier provided more than 10% of the Partnership’s total propane supply in Fiscal 2010. 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 government regulated rate caps on electricity. Additionally, high efficiency electric heat pumps have led to a decrease in the cost of electricity for heating. Fuel oil is also a major competitor of propane and is generally less expensive than propane. Furnaces and appliances that burn propane will not operate on fuel oil, and vice versa, and, therefore, a conversion from one fuel to the other requires the installation of new equipment. Propane serves as an alternative to natural gas in rural and suburban areas where natural gas is unavailable or portability of product is required. Natural gas is generally a less expensive source of energy than propane, although in areas where natural gas is available, propane is used for certain industrial and commercial applications and as a standby fuel during interruptions in natural gas service. The gradual expansion of the nation’s natural gas distribution systems has resulted in the availability of natural gas in some areas that previously depended upon propane. However, natural gas pipelines are not present in many regions of the country where propane is sold for heating and cooking purposes.

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

The retail propane industry is mature, with no growth in total demand 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 large, multi-location propane users to enter into a supply agreement with it rather than with many small suppliers), as well as the success of its sales and marketing programs designed to attract and retain customers. The failure of the Partnership to retain and grow its customer base would have an adverse effect on its long-term results.

The domestic propane retail distribution business is highly competitive. The Partnership competes in this business with other large propane marketers, including other full-service marketers, and thousands of small independent operators. Some rural electric cooperatives and fuel oil distributors have expanded their businesses to include propane distribution and the Partnership competes with them as well. The ability to compete effectively depends on providing high quality customer service, maintaining competitive retail prices and controlling operating expenses. The Partnership also offers customers various payment and service options, including fixed price and guaranteed price programs.

In Fiscal 2010, the Partnership’s retail propane sales totaled approximately 893 million gallons. Based on the most recent annual survey by the American Petroleum Institute, 2008 domestic retail propane sales (annual sales for other than chemical uses) in the United States totaled approximately 9.3 billion gallons. Based on LP-GAS magazine rankings, 2008 sales volume of the ten largest propane companies (including AmeriGas Partners) represented approximately 41% of domestic retail sales.

Properties

As of September 30, 2010, the Partnership owned approximately 86% of its district locations. 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, 2010, the Partnership operated a transportation fleet with the following assets:

Other assets owned at September 30, 2010 included approximately 837,000 stationary storage tanks with typical capacities ranging from 121 to 2,000 gallons and approximately 3.3 million portable propane cylinders with typical capacities of 1 to 120 gallons. The Partnership also owned approximately 5,700 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 historical information on national weather statistics, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Government Regulation

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

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

With respect to the transportation of propane by truck, the Partnership is subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the United States Department of Transportation (“DOT”). The Natural Gas Safety Act of 1968 required the DOT to develop and enforce minimum safety regulations for the transportation of gases by pipeline. The DOT’s pipeline safety regulations apply to, among other things, a propane gas system which supplies 10 or more residential customers or 2 or more commercial customers from a single source and a propane gas system any portion of which is located in a public place. The code requires operators of all gas systems to provide training and written instructions for employees, establish written procedures to minimize the hazards resulting from gas pipeline emergencies, and to conduct and keep records of inspections and testing. Operators are subject to the Pipeline Safety Improvement Act of 2002, which, among other things, protects employees who provide information to their employers or to the federal government as to pipeline safety from adverse employment actions.

Employees

The Partnership does not directly employ any persons responsible for managing or operating the Partnership. The General Partner provides these services and is reimbursed for its direct and indirect costs and expenses, including all compensation and benefit costs. At September 30, 2010, the General Partner had approximately 5,800 employees, including approximately 400 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 2010, Antargaz sold approximately 280 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 17,500 retail outlets, such as supermarkets, individually owned stores and gas stations. Supermarket sales represented approximately 58% of cylinder sales volume in Fiscal 2010. At September 30, 2010, Antargaz had approximately 200,000 bulk customers and approximately 6 million cylinders in circulation. Approximately 62% of Antargaz’ Fiscal 2010 sales (based on volumes) were cylinder and small bulk, 14% medium bulk, 18% large bulk, 3% 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. No single customer represents, or is anticipated to represent, more than 5% of total revenues for Antargaz.

Sales to small bulk customers represent the largest segment of Antargaz’ business in terms of volume, revenue and total margin. Small bulk customers are primarily residential and small business users, such as restaurants, that use LPG mainly for heating and cooking. Small bulk customers also include municipalities, which use LPG for heating sports arenas and swimming pools, and the poultry industry for use in chicken brooding.

The principal end-users of cylinders are residential customers who use LPG supplied in this form for domestic applications such as cooking and heating. Butane cylinders accounted for approximately 61% of all LPG cylinders sold in Fiscal 2010, with propane cylinders accounting for the remainder. Propane cylinders are also used to supply fuel for forklift trucks. The market demand for cylinders has been declining, due primarily to customers gradually changing to other household energy sources for heating and cooking, such as natural gas. Antargaz is seeking to increase demand for butane and propane cylinders through marketing and product innovations.

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

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 2010, Antargaz purchased almost 100% of its butane needs and approximately 10% of its propane 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 2010, 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 and conservation. Sales volumes are affected principally by the severity of the weather and customer migration to alternative energy forms, including natural gas and electricity. Like other businesses, it becomes more difficult for Antargaz to pass on product cost increases fully when product costs rise rapidly. Increased LPG prices may result in slower than expected growth due to customer conservation and customers seeking less expensive alternative energy sources. France derives a significant portion of its electricity from nuclear power plants. Due to the nuclear power plants as well as the regulation of electricity prices by the French government, electricity prices in France are generally less expensive than LPG. As a result, electricity has increasingly become a more significant competitor to LPG in France than in other countries where we operate. In addition, government policies and incentives that favor alternative energy sources can result in customers migrating to energy sources other than LPG.

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

On October 21, 2009, Antargaz responded to a Statement of Objections issued by the French competition authority, the General Division of Competition, Consumption and Fraud Punishment, in July of 2009. For more information on this matter, see “Legal Proceedings” and Note 15 to Consolidated Financial Statements, included under Item 8 of this Report.

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 general economic conditions. For historical information on weather statistics for Antargaz, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Government Regulation

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

Properties

Antargaz has 4 primary storage facilities in operation. One of these is a refrigerated facility. The table below sets forth details of each of these facilities.

Antargaz closed a fifth storage facility, Geovexin, during Fiscal 2010. Antargaz has 26 secondary storage facilities, 13 of which are wholly owned. The others are partially owned, through joint ventures.

Employees

At September 30, 2010, Antargaz had approximately 950 employees.

INTERNATIONAL PROPANE — OTHER

Our International Propane — Other LPG distribution business is conducted principally in Europe through our wholly owned subsidiary, Flaga. Flaga operates in Austria, Switzerland, the Czech Republic, Slovakia, Poland, Hungary and Romania. During Fiscal 2010, Flaga sold approximately 70 million gallons of LPG. Our majority-owned partnership in China sold approximately 12.3 million gallons of LPG during Fiscal 2010. Prior to February 2010, this partnership was a joint venture.

On September 23, 2010, we acquired Kosan Gas A/S, which operates in Denmark and is managed by Flaga. On October 15, 2010, we acquired Shell Gas Polska Sp. z.o.o, which operates in Poland and is being combined with Flaga’s existing business there.

FLAGA

Products, Services, Marketing and Storage

Flaga is referred to in this section collectively with Kosan Gas as “Flaga” unless the context otherwise requires. Flaga distributes LPG for residential, commercial, industrial, and auto gas applications in the following European countries: Austria, Switzerland, the Czech Republic, Denmark, Slovakia, Poland, Hungary and Romania. During Fiscal 2010, Flaga sold approximately 70 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.

Flaga’s customers primarily use LPG for heating, cooking, construction work, industrial processing, forklifts and autogas. The retail propane industry in Austria, Denmark and Switzerland is mature, with slight declines in overall demand in recent years, due primarily to the expansion of natural gas and renewable energy sources. Competition for customers is based on contract terms as well as on product prices. Flaga has 32 sales offices throughout the countries it serves. Much of Flaga’s cylinder business in Austria is conducted through approximately 600 local resellers with whom Flaga has a long business relationship. In its other countries, Flaga sells cylinders to distributors who resell the cylinders to end users under the distributor’s pricing and terms. Flaga utilizes approximately 60 storage facilities with 21 of those storage facilities in the Czech Republic and 16 in Austria.

Seasonality and Competition

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

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. 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, 2010, Flaga had approximately 850 employees.

GAS UTILITY

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 568,000 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 a small service territory, the Maryland Public Service Commission. Electric Utility is regulated by the PUC.

Service Area; Revenue Analysis

Gas Utility is authorized to distribute natural gas to approximately 568,000 customers in portions of 45 eastern and central Pennsylvania counties through its distribution system of approximately 11,900 miles of gas mains. The service area includes the cities of Allentown, Bethlehem, Easton, Harrisburg, Hazleton, Lancaster, Lebanon, Reading, Scranton, Wilkes-Barre, Lock Haven, Pittston, Pottsville and Williamsport, Pennsylvania, and the boroughs of Honesdale and Milford, Pennsylvania. Located in Gas Utility’s service area are major production centers for basic industries such as specialty metals, aluminum, glass and paper product manufacturing. 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 2010 was approximately 153.9 billion cubic feet (“bcf”). System sales of gas accounted for approximately 37% of system throughput, while gas transported for residential, commercial and industrial customers (who bought their gas from others) accounted for approximately 63% 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.” 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 2010, Gas Utility purchased approximately 91 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, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers) and off-system sales customers. Approximately 75% of the volumes purchased were supplied under agreements with 10 suppliers. The remaining 25% of gas purchased by Gas Utility was supplied by approximately 21 producers and marketers. Gas supply contracts for Gas Utility are generally no longer than 1 year. Gas Utility also has long-term contracts with suppliers for natural gas peaking supply during the months of November through March.

Seasonality

Because many of its customers use gas for heating purposes, Gas Utility sales are seasonal. Approximately 65% to 70% of Gas Utility’s sales volume is supplied, and approximately 85% to 90% of Gas Utility’s operating income is earned, during 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. In parts of Gas Utility’s service area, electricity may have a competitive price advantage over natural gas due to government regulated rate caps on electricity. Rate caps for electric utilities serving a significant portion of Gas Utility’s service territory expired at the end of 2009 or are scheduled to expire at the end of 2010 which will likely result in electricity losing all or some of its competitive price advantage. Additionally, high efficiency electric heat pumps have led to a decrease in the cost of heating with electricity. Government subsidies currently favor ground source heat pumps over fossil fueled systems. Fuel oil dealers compete for customers in all categories, including industrial customers. Gas Utility responds to this competition with marketing efforts designed to retain and grow its customer base.

In substantially all of its service territories, Gas Utility is the only regulated gas distribution utility having the right, granted by the PUC or by law, to provide gas distribution services. Since the 1980s, larger commercial and industrial customers have been able to purchase gas supplies from entities other than natural gas distribution utility companies. As a result of Pennsylvania’s Natural Gas Choice and Competition Act, effective July 1, 1999 all of Gas Utility’s customers, including 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 31% 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 28 customers, most of which are among the 10 largest customers for each of UGI Gas, PNG and CPG in terms of annual volumes. All of these customers have contracts, 22 of which extend beyond the 2011 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 2011. 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 2010, Gas Utility supplied transportation service to 2 major co-generation installations and 5 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 7,700 residential heating customers during Fiscal 2010. These customers consisted primarily of (i) customers converting from other energy sources, mainly oil and electricity, (ii) existing non-heating gas customers who added gas heating systems to replace other energy sources and (iii) new home construction customers.

UGI Utilities continues to monitor and participate, where appropriate, in rulemaking and individual rate and tariff proceedings before FERC affecting the rates and the terms and conditions under which Gas Utility transports and stores natural gas. Among these proceedings are those arising out of certain FERC orders and/or pipeline filings which relate to (i) the pricing of pipeline services in a competitive energy marketplace; (ii) the flexibility of the terms and conditions of pipeline service tariffs and contracts; and (iii) pipelines’ requests to increase their base rates, or change the terms and conditions of their storage and transportation services.

UGI Utilities’ objective in negotiations with interstate pipeline and natural gas suppliers, and in proceedings before regulatory agencies, is to assure availability of supply, transportation and storage alternatives to serve market requirements at the lowest cost possible, taking into account the need for security of supply. Consistent with that objective, UGI Utilities negotiates the terms of firm transportation capacity on all pipelines serving it, arranges for appropriate storage and peak-shaving resources, negotiates with producers for competitively priced gas purchases and aggressively participates in regulatory proceedings related to transportation rights and costs of service.

ELECTRIC UTILITY

Service Area; Sales Analysis

Electric Utility supplies electric service to approximately 62,000 customers in portions of Luzerne and Wyoming counties in northeastern Pennsylvania through a system consisting of approximately 2,120 miles of transmission and distribution lines and 13 transmission substations. For Fiscal 2010, approximately 54% of sales volume came from residential customers, 34% from commercial customers, and 12% from industrial and other customers. Sales of electricity for residential heating purposes accounted for approximately 18% of total sales of electricity during Fiscal 2010.

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, if any. As of September 30, 2010, 4 electric generation suppliers provided energy for customers representing 13% 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 2010, 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 UGI Utilities’ utility operations may charge for gas service come in two forms: 1) rates designed to recover costs other than purchased gas costs; and 2) rates designed to recover purchase gas costs. Rates designed to recover costs other than purchased gas costs are primarily established in general base rate proceedings. Rates designed to recover purchased gas costs are reviewed in a purchased gas costs (“PGC”) rate proceeding. 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 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. The increases became effective on August 28, 2009.

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

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

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

State Tax Surcharge Clauses

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

Utility Franchises

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

Other Government Regulation

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

Employees

At September 30, 2010, UGI Utilities had approximately 1,400 employees.

MIDSTREAM & MARKETING

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

Retail Energy Marketing

Energy Services conducts its energy marketing business under the trade name GASMARK ^® . Energy Services sells natural gas, liquid fuels and electricity to approximately 9,000 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 13 utility systems.

Gas and power marketing are high-revenue, low-margin businesses. 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 which are guaranteed by the New York Mercantile Exchange and have nominal credit risk, (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 2010, 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 we announced in August 2010, Energy Services is planning to make investments in infrastructure projects to support the development of natural gas in the Marcellus Shale region of Pennsylvania. These 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 it operated as a 44-megawatt coal-fired facility through May 2010. At that time, it ceased operations to facilitate conversion to a natural gas-fueled plant. Energy Services is in the process of building a 125-megawatt natural gas-fueled power plant to replace the Hunlock Station facility. The new plant is expected to be completed in late Fiscal 2011.

Energy Services owns and operates a landfill gas-fueled electricity generation plant in Hegins, Pennsylvania with gross generating capacity of 11 megawatts. The plant qualifies for renewable energy credits. During fiscal year 2010, Energy Services built a 1 megawatt solar-powered generation facility in Easton, Pennsylvania to supply electrical power to a third party and will receive solar renewable energy credits as a result of the project. 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. 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.”

Prior to suspending operations in May 2010 for conversion to natural gas-fueled generation, Hunlock Station generally complied with the air quality standards of the Pennsylvania Department of Environmental Protection (“DEP”) with respect to stack emissions. Under the Federal Water Pollution Control Act, Hunlock Station had a permit from the DEP to discharge water into the North Branch of the Susquehanna River. A permit for the gas-fired plant is pending. Energy Services is working with the DEP to develop a closure plan for the Hunlock Station following the permanent cessation of coal operations there in 2010. The federal Clean Air Act Amendments of 1990 impose emissions limitations for certain compounds, including sulfur dioxide and nitrous oxides. The Conemaugh Station is in material compliance with these current emission standards.

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, 2010, Energy Services and its subsidiaries had approximately 165 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 120,000 customers in residential, commercial, industrial and new construction markets. During Fiscal 2010, HVAC/R generated approximately $77 million in revenues and employed approximately 480 people.

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 warming. In addition to carbon dioxide, greenhouse gases include, among others, methane, a component of natural gas. While some states have adopted laws regulating the emission of GHGs for some industry sectors, there is currently no federal regulation mandating the reduction of GHG emissions in the United States. In June 2009, the United States House of Representatives passed the American Clean Energy and Security Act (“ACES Act”). The ACES Act would establish an economy-wide GHG cap-and-trade system to reduce GHG emissions over time. The United States Senate has been considering a number of related proposals, ranging from “energy only” bills to proposals that place an economy-wide cap on greenhouse gas emissions. No legislation can be enacted until a final reconciled bill is approved by both the House of Representatives and the Senate and signed by the President.

Even if Congress does not pass legislation mandating GHG emissions reductions, there continue to be regulatory developments under the Clean Air Act applicable to GHGs. 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. In December 2009, the EPA published its findings that emissions of GHGs constitute an endangerment to public health and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would limit GHG emissions from new motor vehicles and that would impose permit requirements for GHG emissions from certain stationary sources. Legal challenges have been filed against many of EPA’s rulemakings, and we are unable to predict the results of those challenges.

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

BUSINESS SEGMENT INFORMATION

The table stating the amounts of revenues, operating income (loss) and identifiable assets attributable to each of UGI’s reportable business segments, and to the geographic areas in which we operate, for the 2010, 2009 and 2008 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, 2010, UGI and its subsidiaries had approximately 9,800 employees.

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

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

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

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

When the Company enters into fixed-price sales contracts with customers, it typically enters into fixed-price purchase contracts with suppliers. Depending on changes in the market prices of products compared to the prices secured in our contracts with suppliers of LPG, 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 2010, 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 maturity 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 involve a number of risks, including, but not limited to, the assumption of material liabilities, the diversion of management’s attention from the management of daily operations to the integration of operations, difficulties in the assimilation and retention of employees and difficulties in the assimilation of different cultures and practices, as well as in the assimilation of broad and geographically dispersed personnel and operations. The failure to successfully integrate acquisitions could have an adverse effect on our business, financial condition and results of operations.

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 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.

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 warming. In addition to carbon dioxide, greenhouse gases include, among others, methane, a component of natural gas. While some states have adopted laws regulating the emission of GHGs for some industry sectors, there is currently no federal regulation mandating the reduction of GHG emissions in the United States. In June of 2009, the United States House of Representatives passed the American Clean Energy and Security Act (“ACES Act”). The ACES Act would establish an economy-wide GHG cap-and-trade system to reduce GHG emissions over time. The United States Senate has been considering a number of related proposals, ranging from “energy only” bills to proposals that place an economy-wide cap on greenhouse gas emissions. No legislation can be enacted until a final reconciled bill is approved by both the House of Representatives and the Senate and signed by the President.

Even if Congress does not pass legislation mandating GHG emissions reductions, there continue to be regulatory developments under the Clean Air Act applicable to GHGs. 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. In December 2009, the EPA published its findings that emissions of GHGs constitute an endangerment to public health and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would limit GHG emissions from new motor vehicles and that would impose permit requirements for GHG emissions from certain stationary sources. Legal challenges have been filed against many of EPA’s rulemakings, and we are unable to predict the results of those challenges.

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.

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

Our business operations in the U.S. and other countries are subject to all of the operating hazards and risks normally incidental to the handling, storage and distribution of combustible products, such as LPG, propane and natural gas, and the generation of electricity. As a result, we are sometimes a defendant in legal proceedings and litigation arising in the ordinary course of business. There can be no assurance that our insurance will be adequate to protect us from all material expenses related to pending and future claims or that such levels of insurance will be available in the future at economical prices.

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

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

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

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

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

We are investigating and remediating contamination at a number of present and former operating sites in the U.S., including former sites where we or our former subsidiaries operated manufactured gas plants. We have also received claims from third parties that allege that we are responsible for costs to clean up properties where we or our former subsidiaries operated a manufactured gas plant or conducted other operations. Costs we incur to remediate sites outside of Pennsylvania cannot 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 international operations could result in increased risks which may negatively affect our business results.

We currently operate LPG distribution businesses in Europe through our subsidiaries, Antargaz, Flaga and Kosan Gas 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 AmeriGas Order-to-Cash business processes. The efficient execution of AmeriGas’ business is dependent upon the proper functioning of its internal systems. Any significant failure or malfunction of AmeriGas’ 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.

PART II:

ITEM 6. SELECTED FINANCIAL DATA

		Year Ended September 30,
(Millions of dollars, except per share amounts)		2010				2009				2008				2007				2006
FOR THE PERIOD:
Income statement data:
Revenues		$	5,591.4			$	5,737.8			$	6,648.2			$	5,476.9			$	5,221.0
Net income		$	355.7			$	382.0	(a)		$	305.3	(a)		$	311.2	(a)		$	224.9	(a)
Less: net income attributable to noncontrolling interests, principally in AmeriGas Partners			(94.7	)			(123.5	)(a)			(89.8	)(a)			(106.9	)(a)			(48.7	)(a)
Net income attributable to UGI Corporation		$	261.0			$	258.5	(a)		$	215.5	(a)		$	204.3	(a)		$	176.2	(a)
Earnings per common share attributable to UGI stockholders:
Basic		$	2.38			$	2.38			$	2.01			$	1.92			$	1.67
Diluted		$	2.36			$	2.36			$	1.99			$	1.89			$	1.65
Cash dividends declared per common share		$	0.90			$	0.785			$	0.755			$	0.723			$	0.690
AT PERIOD END:
Balance sheet data:
Total assets		$	6,374.3			$	6,042.6			$	5,685.0			$	5,502.7			$	5,080.5
Capitalization:
Debt:
Bank loans — UGI Utilities		$	17.0			$	154.0			$	57.0			$	190.0			$	216.0
Bank loans — AmeriGas Propane			91.0				—				—				—				—
Bank loans — Antargaz			68.2				—				70.4				—				—
Bank loans — other			24.2				9.1				9.0				8.9				9.4
Long-term debt (including current maturities):
AmeriGas Propane			791.4				865.6				933.4				933.1				933.7
Antargaz			519.1				557.7				537.4				544.9				483.5
UGI Utilities			640.0				640.0				532.0				512.0				512.0
Other			55.3				69.8				66.3				63.5				67.7
Total debt			2,206.2				2,296.2				2,205.5				2,252.4				2,222.3
UGI Corporation stockholders’ equity			1,824.5				1,591.4				1,417.7				1,321.9				1,099.6
Noncontrolling interests, principally in AmeriGas Partners			237.1				225.4				159.2				192.2				139.5
Total capitalization		$	4,267.8			$	4,113.0			$	3,782.4			$	3,766.5			$	3,461.4
Ratio of capitalization:
Total debt			51.7	%			55.8	%			58.3	%			59.8	%			64.2	%
UGI Corporation stockholders’ equity			42.8	%			38.7	%			37.5	%			35.1	%			31.8	%
Noncontrolling interests, principally in AmeriGas Partners			5.5	%			5.5	%			4.2	%			5.1	%			4.0	%
			100.0	%			100.0	%			100.0	%			100.0	%			100.0	%

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

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. The business segment comprising Energy Services and its consolidated subsidiaries is referred to as “Midstream & Marketing” below.

Executive Overview

We recorded net income attributable to UGI Corporation of $261.0 million, equal to $2.36 per diluted share, in Fiscal 2010 compared to net income attributable to UGI Corporation of $258.5 million, equal to $2.36 per diluted share, in Fiscal 2009. Although Fiscal 2010 net income attributable to UGI Corporation and earnings per diluted share were comparable to those items in Fiscal 2009, the contribution to net earnings by business segment was significantly different.

Midstream & Marketing net income increased $30.1 million in Fiscal 2010 reflecting a $17.2 million gain from the sale of Energy Services’ Atlantic Energy, LLC (“Atlantic Energy”) subsidiary and the benefits of higher natural gas and electricity marketing total margin. Gas Utility’s contribution to net income attributable to UGI Corporation increased $12.8 million in Fiscal 2010 reflecting the full-year effects of the PNG Gas and CPG Gas August 2009 base rate increases and lower operating and administrative expenses. Substantially offsetting the increases in Midstream & Marketing and Gas Utility Fiscal 2010 results were lower contributions principally from our International Propane and AmeriGas Propane business segments. International Propane’s Fiscal 2010 contribution to net income attributable to UGI Corporation was significantly lower than in Fiscal 2009 as the prior-year’s results benefited from unit margins at Antargaz that were significantly higher than normal following a precipitous decline in LPG commodity costs that occurred as Antargaz entered the Fiscal 2009 winter heating season. AmeriGas Propane’s contribution to earnings was $17.7 million lower in Fiscal 2010 principally reflecting the absence of an after-tax gain from the sale of the Partnership’s California storage facility recorded in Fiscal 2009 ($10.4 million), the impact of after-tax losses on interest rate protection agreements recorded in Fiscal 2010 ($3.3 million) and the effects of lower Partnership total margin.

Looking ahead, we expect our results in Fiscal 2011 to be influenced by a number of factors including, among others, heating-season temperatures in our business units’ service territories; the strength of the economic recovery in the United States and Europe; declining LPG usage resulting from competition from other types of energy and ongoing customer conservation; and the level and volatility of commodity prices for natural gas, LPG and electricity.

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, an accounts receivable securitization facility to fund business operations in Fiscal 2011. We have € 380 million of Antargaz term loans and € 25.4 million of Flaga term loans maturing in Fiscal 2011. We intend to refinance this maturing debt on a long-term basis. Additionally, UGI Utilities expects to renew its revolving credit agreement prior to its expiration in August 2011 and AmeriGas OLP expects to renew its credit facilities, which are scheduled to expire in June 2011 and October 2011, during the second half of Fiscal 2011. Energy Services intends to extend its receivables securitization facility prior to its expiration in April 2011.

As further described in Note 3 to Consolidated Financial Statements, effective October 1, 2009, we adopted guidance regarding the accounting for and presentation of noncontrolling interests in consolidated financial statements. The new guidance significantly changed the accounting and reporting relating to noncontrolling interests in a consolidated subsidiary. Noncontrolling interests are now classified as a component of equity on the Consolidated Balance Sheets, a change from their prior classification between liabilities and stockholders’ equity. Earnings attributable to noncontrolling interests are now included in net income and deducted from net income to determine net income attributable to UGI Corporation. In accordance with the new guidance, prior-year periods have been adjusted. The new guidance had no effect on our basic or diluted earnings per share.

Results of Operations

The following analyses compare the Company’s results of operations for (1) Fiscal 2010 with Fiscal 2009 and (2) Fiscal 2009 with the year ended September 30, 2008 (“Fiscal 2008”). As previously mentioned, our consolidated results of operations for Fiscal 2009 and Fiscal 2008 reflect the retroactive effects of the Financial Accounting Standards Board’s (“FASB’s”) accounting guidance for the presentation of noncontrolling interests in consolidated financial statements.

Fiscal 2010 Compared with Fiscal 2009
Consolidated Results

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

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.

Based upon heating degree-day data, average temperatures in our service territories were 2.2% 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 a previously anticipated $150 million of long-term debt during the summer of 2010. 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) expense, 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.

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%.

Temperatures in the Gas Utility service territory based upon heating degree days were 5.3% warmer than normal in Fiscal 2010 compared with temperatures that were 4.1% 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’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 much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.

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. 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 $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.

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. Under DS rates, Electric Utility is no longer subject to electric generation 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 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).

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 generating station which ceased operating in May 2010 as it transitions 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.

Highlights — Fiscal 2009 versus Fiscal 2008

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Higher unit margins at AmeriGas Propane and Antargaz in Fiscal 2009 reflect significant declines in LPG commodity prices entering our critical heating season.

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

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

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AmeriGas Partners’ sale of its California LPG storage terminal generated net income of $10.4 million in Fiscal 2009.

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

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International Propane Fiscal 2009 results reflect a $10.0 million charge for the Antargaz Competition Authority Matter.

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Midstream & Marketing’s Fiscal 2009 results were adversely impacted by lower income from electricity generation.

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Electric Utility Fiscal 2009 results were lower reflecting the effects of higher cost of sales and lower demand as a result of the recession.

Based upon heating degree-day data, average temperatures in our service territories during Fiscal 2009 were 3.1% warmer than normal compared with temperatures in the prior year that were 3.0% warmer than normal. Fiscal 2009 retail gallons sold were 6.5% lower than Fiscal 2008 reflecting, among other things, the adverse effects of the significant deterioration in general economic activity which occurred over the last year and continued customer conservation. During Fiscal 2009, average wholesale propane commodity prices at Mont Belvieu, Texas, one of the major supply points in the U.S., were more than 50% lower than such prices in Fiscal 2008. The decrease in the average wholesale commodity prices in Fiscal 2009 reflects the effects of a precipitous decline in commodity propane prices principally during the first quarter of Fiscal 2009 following a substantial increase in prices during most of the second half of Fiscal 2008. Although wholesale propane prices in Fiscal 2009 rebounded modestly from prices experienced earlier in the year, at September 30, 2009 such prices remained approximately 35% lower than at September 30, 2008.

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

Total margin was $36.7 million greater in Fiscal 2009 reflecting the beneficial impact of higher than normal retail unit margins resulting from the previously mentioned rapid decline in propane commodity costs that occurred primarily as we entered the critical winter heating season in the first quarter of Fiscal 2009.

The $68.4 million increase in Fiscal 2009 Partnership EBITDA reflects the effects of a pre-tax gain from the November 2008 sale of the Partnership’s California LPG storage facility ($39.9 million) and the previously mentioned increase in total margin ($36.7 million). These increases were partially offset by slightly higher operating and administrative expenses ($4.7 million) and slightly lower other income ($2.8 million). The slightly higher operating and administrative expenses reflects, in large part, an increase in compensation and benefit expenses ($9.1 million) and higher costs associated with facility maintenance projects ($6.4 million) offset principally by lower vehicle fuel expenses ($14.2 million) due to lower propane, diesel and gasoline prices.

Operating income increased $65.5 million in Fiscal 2009 reflecting the previously mentioned increase in EBITDA ($68.4 million) partially offset by slightly higher depreciation and amortization expense ($3.4 million) reflecting acquisitions and plant and equipment expenditures made since the prior year.

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

During Fiscal 2009, the average currency translation rate was $1.35 per euro compared to a rate of $1.51 per euro during Fiscal 2008. Although the stronger dollar resulted in lower translated International Propane operating results, the effects of the stronger dollar on reported International Propane net income attributable to UGI Corporation were substantially offset by gains on forward currency contracts used to hedge purchases of dollar-denominated LPG.

International Propane euro-based revenues decreased € 37.1 million or 4.9% in Fiscal 2009 reflecting a decline in revenues from Antargaz ( € 82.2 million), principally lower retail propane revenues ( € 61.9 million) from lower average selling prices, and lower Antargaz wholesale revenues ( € 20.4 million). Partially offsetting the decline in revenues from Antargaz was an increase in Flaga revenues ( € 45.1 million) resulting from the consolidation of ZLH beginning in January 2009. The lower average selling prices reflect the previously mentioned year-over-year decrease in wholesale LPG product costs. In U.S. dollars, revenues declined $169.5 million or 15.1% reflecting the previously mentioned total lower euro-based revenues and the effects of the stronger U.S. dollar. International Propane’s total cost of sales decreased to € 320.0 million in Fiscal 2009 from € 434.9 million in Fiscal 2008, a 26.4% decline, principally reflecting the lower per-unit LPG commodity costs. On a U.S. dollar basis, cost of sales decreased $222.4 million or 34.1%.

International Propane euro-based total margin increased € 77.8 million or 24.7% in Fiscal 2009 largely the result of higher total margin at Antargaz ( € 57.9 million) reflecting the beneficial impact of higher than normal retail unit margins resulting from the rapid and sharp decline in LPG commodity costs that occurred as Antargaz entered the winter heating season in the first quarter of Fiscal 2009 and, to lesser extent, incremental total margin at Flaga from the consolidation of ZLH beginning in January 2009 ($25.5 million). Also affecting the year-over-year comparison was the fact that Antargaz was adversely affected by lower unit margins in Fiscal 2008 as a result of the rapid increase in LPG product costs which occurred in Fiscal 2008. In U.S. dollars, total margin increased $52.9 million or 11.2% reflecting the effects of the stronger dollar on translated euro base-currency revenues and cost of sales.

International Propane euro-based operating income increased € 45.9 million or 65.2% in Fiscal 2009 principally reflecting the previously mentioned increase in total margin ( € 77.8 million) reduced by a charge related to a French Competition Authority Matter ( € 7.1 million) and an increase in operating and administrative costs ( € 21.4 million). The higher operating and administrative costs principally reflect higher operating and administrative costs at Flaga ( € 14.4 million) resulting from the consolidation of the operations of ZLH and, to lesser extent, higher operating expenses at Antargaz ( € 7.0 million). On a U.S. dollar basis, operating income increased $44.6 million or 41.8% principally reflecting the previously mentioned increase in U.S. dollar-denominated total margin ($52.9 million) partially offset by the charge related to the Antargaz Competition Authority Matter ($10.0 million). Euro-based income before income taxes was € 46.5 million (95.3%) greater than in the prior year principally reflecting the higher operating income. In U.S. dollars, income before income taxes increased $49.0 million (67.1%) principally reflecting the benefit of the higher dollar-denominated operating income. Loss from International Propane equity investees was higher in Fiscal 2009 due to expenditures associated with the anticipated closure of an LPG storage facility.

Temperatures in the Gas Utility service territory based upon heating degree days were 4.1% colder than normal in Fiscal 2009 compared with temperatures that were 2.7% warmer than normal in Fiscal 2008. Total distribution system throughput increased 16.0 bcf in Fiscal 2009 principally reflecting the effects of the October 1, 2008 CPG Acquisition (22.2 bcf) and increases in core-market volumes resulting from the colder Fiscal 2009 weather and year-over-year customer growth. These increases in system throughput were partially offset by the effects on volumes sold and transported due to lower demand from commercial and industrial customers as a result of the deterioration in general economic activity and customer conservation.

Gas Utility revenues increased $102.7 million in Fiscal 2009 principally reflecting incremental revenues from CPG Gas ($187.4 million) somewhat offset by lower revenues from low-margin off-system sales ($90.3 million). Gas Utility’s cost of gas was $853.2 million in Fiscal 2009 compared with $831.1 million in Fiscal 2008 principally reflecting incremental cost of sales associated with CPG Gas ($117.0 million) partially offset principally by the cost of sales effect of the lower off-system revenues ($89.1 million).

Gas Utility total margin increased $80.6 million in Fiscal 2009 principally reflecting incremental margin from CPG Gas ($70.4 million) and higher total core-market margin from UGI Gas and PNG Gas ($11.3 million) resulting principally from the higher core-market volumes sold.

The increase in Gas Utility operating income during Fiscal 2009 principally reflects the previously mentioned greater total margin ($80.6 million) partially offset by higher operating and administrative and depreciation expenses ($59.3 million), principally incremental expenses associated with CPG Gas ($47.2 million), higher costs associated with environmental matters ($4.1 million) and, to a lesser extent, higher pension and distribution system maintenance expenses. Income before income taxes also increased reflecting the previously mentioned higher operating income partially offset by higher interest expense associated with $108 million Senior Notes issued to finance a portion of the CPG Acquisition ($7.2 million).

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

Electric Utility total margin decreased $7.7 million during Fiscal 2009 principally reflecting the higher cost of sales and, to a much lesser extent, the effects of the lower sales volumes.

Electric Utility operating income and income before income taxes in Fiscal 2009 were $9.0 million and $8.7 million lower than in Fiscal 2008, respectively, principally reflecting the previously mentioned lower total margin ($7.7 million) and higher operating and administrative costs ($0.9 million).

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

Total margin from Midstream & Marketing increased $2.1 million in Fiscal 2009 reflecting greater total margin principally from peaking supply services ($4.4 million) and retail electricity sales ($2.8 million) partially offset by lower electric generation total margin ($4.6 million). The decrease in electric generation total margin reflects lower spot-market prices for electricity and, to a much lesser extent, lower volumes generated due in large part to electricity generation facility outages. The decreases in Midstream & Marketing operating income and income before income taxes in Fiscal 2009 largely reflects the previously mentioned increase in total margin ($2.1 million) more than offset by higher electric generation operating and maintenance costs ($5.9 million) including charges related to obligations associated with its ongoing Hunlock Station repowering project and an increase in asset management costs ($3.4 million). The decrease in operating income and income before income taxes also reflects greater costs associated with Energy Service’s receivables securitization facility ($1.4 million) as a result of higher amounts needed to fund futures brokerage account margin calls and greater facility fees subsequent to the renewal of the securitization facility in April 2009.

Interest Expense and Income Taxes. Consolidated interest expense decreased slightly to $141.1 million in Fiscal 2009 from $142.5 million in Fiscal 2008 principally due to a decline in International Propane interest expense ($3.1 million), principally attributable to lower effective interest rates and the stronger U.S. dollar, a decline in interest on UGI Utilities revolving credit agreement borrowings ($2.4 million) and lower interest expense on AmeriGas Propane long-term debt ($2.3 million). These decreases were largely offset by incremental interest expense on CPG Acquisition debt ($7.2 million). Our effective income tax rate was slightly lower in Fiscal 2009 principally reflecting the effects of a higher percentage of pretax income from noncontrolling interests, principally in AmeriGas Partners, 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 $260.7 million at September 30, 2010 compared with $280.1 million at September 30, 2009. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at September 30, 2010 and 2009 UGI had $111.6 million and $102.7 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, 2010, 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 2010, Fiscal 2009 and Fiscal 2008, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:

Dividends in Fiscal 2010 from Midstream & Marketing resulted from the sale of Atlantic Energy LLC. Dividends from AmeriGas Propane in Fiscal 2009 include the benefit of a one-time $0.17 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 2010 and 2009, Midstream & Marketing received capital contributions from UGI totaling $51.0 million and $46.8 million, respectively, to fund major LNG storage and electric generation capital projects.

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 reflects our confidence in UGI’s future prospects and strong cash flows. We expect that the increase in the UGI dividend rate in Fiscal 2011 will be closer to UGI’s long-term goal of increasing the dividend by approximately 4% a year.

On April 26, 2010, the General Partner’s Board of Directors approved a quarterly distribution of $0.705 per Common Unit equal to an annual rate of $2.82 per Common Unit. This distribution reflects an approximate 5% increase from the previous quarterly rate of $0.67 per Common Unit. The new quarterly rate was effective with the distribution payable on May 18, 2010 to unitholders of record on May 10, 2010. Our targeted annual distribution increase is approximately 5%.

Long-term Debt and Credit Facilities

The Company’s total debt outstanding at September 30, 2010 totaled $2,206.2 million (including current maturities of long-term debt of $573.6 million and bank loan borrowings of $200.4 million) compared to $2,296.2 million of total debt outstanding at September 30, 2009 (including current maturities of long-term debt of $94.5 million and bank loan borrowings of $163.1 million). The significantly higher current maturities of long-term debt at September 30, 2010 primarily reflects the scheduled maturity of Antargaz’ € 380 million term loan ($518.1 million) in March 2011 and Fiscal 2011 scheduled repayments under Flaga’s two term loans ($34.6 million). Total debt outstanding at September 30, 2010 principally consists of $882.4 million of Partnership debt, $653.6 million ( € 479.4 million) of International Propane debt, $657 million of UGI Utilities’ debt, and $13.2 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, entered into in August 2010, which it can use for working capital and general corporate purposes of it and its subsidiaries. There were no borrowings under this facility during Fiscal 2010. During Fiscal 2010, Fiscal 2009 and Fiscal 2008, Antargaz generally funded its operating cash flow needs without using its revolving credit facility.

AmeriGas Partners. AmeriGas Partners’ total debt at September 30, 2010 includes $779.7 million of AmeriGas Partners’ Senior Notes, $11.7 million of other long-term debt and $91 million of AmeriGas OLP bank loan borrowings.

AmeriGas OLP’s short-term borrowing needs are seasonal and are typically greatest during the fall and winter heating-season months due to the need to fund higher levels of working capital. In order to meet its short-term cash needs, AmeriGas OLP has a $200 million unsecured credit agreement (“Credit Agreement”) which expires on October 15, 2011. AmeriGas OLP also has a $75 million unsecured revolving credit facility (“2009 Supplemental Credit Agreement”) which expires on June 30, 2011. AmeriGas OLP expects to renew these credit agreements prior to their expiration. AmeriGas OLP’s Credit Agreement consists of (1) a $125 million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 million to finance the purchase of propane businesses or propane business assets or, to the extent it is not so used, for working capital and general purposes. The 2009 Supplemental Credit Agreement permits AmeriGas OLP to borrow up to $75 million for working capital and general purposes.

At September 30, 2010, there were $91 million of borrowings outstanding under the Credit Agreement at an average interest rate of 1.31% and there were no amounts outstanding under the 2009 Supplemental Credit Agreement. There were no borrowings under AmeriGas OLP’s credit agreements at September 30, 2009. Borrowings under AmeriGas OLP credit agreements are classified as bank loans on the Consolidated Balance Sheets. Issued and outstanding letters of credit under the Revolving Credit Facility, which reduce the amount available for borrowings, totaled $35.7 million at September 30, 2010 and $37.0 million at September 30, 2009. The average daily and peak bank loan borrowings outstanding under the credit agreements during Fiscal 2010 were $43.9 million and $135 million, respectively. The average daily and peak bank loan borrowings outstanding under the credit agreements during Fiscal 2009 were $43.8 million and $184.5 million, respectively. The higher peak bank loan borrowings in Fiscal 2009 resulted from amounts borrowed to fund counterparty cash collateral obligations associated with derivative financial instruments used by the Partnership to manage propane price risk associated with fixed sales price commitments to customers. These collateral obligations resulted from the precipitous decline in propane commodity prices that occurred early in Fiscal 2009. At September 30, 2010, the Partnership’s available borrowing capacity under the credit agreements was $148.3 million.

Based upon existing cash balances, cash expected to be generated from operations and borrowings available under AmeriGas OLP’s credit agreements, the Partnership’s management believes that the Partnership will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2011.

International Propane. International Propane’s total debt at September 30, 2010 includes $518.1 million ( € 380 million) outstanding under Antargaz’ Senior Facilities term loan and a combined $40.4 million ( € 29.6 million) outstanding under Flaga’s two term loans. Total International Propane debt outstanding at September 30, 2010 also includes (1) $68.2 million ( € 50.0 million) outstanding under Antargaz’ revolving credit facility; (2) combined borrowings of $24.2 million ( € 17.8 million) outstanding under Flaga’s working capital facilities and (3) $2.7 million ( € 2.0 million) of other long-term debt.

Antargaz . Antargaz has a Senior Facilities Agreement that expires on March 31, 2011. The Senior Facilities Agreement consists of (1) a € 380 million variable-rate term loan and (2) a € 50 million revolving credit facility. The Senior Facilities Agreement also provides Antargaz a € 50 million letter of credit guarantee agreement. Antargaz has executed interest rate swap agreements to fix the underlying euribor rate for the duration of the term loan. The € 380 million variable-rate term loan matures on March 31, 2011. Antargaz intends to refinance this maturing debt. Antargaz has entered into forward-starting interest rate swaps to hedge the underlying euribor rate of interest relating to 4 ¹ / ₂  years of quarterly interest payments on € 300 million notional amount of long-term debt commencing March 31, 2011 associated with the anticipated refinancing. In order to minimize the interest margin it pays on Senior Facilities Agreement borrowings, on September 23, 2010, Antargaz borrowed € 50 million ($68.2 million), the total amount available under its revolving credit facility, which amount remained outstanding at September 30, 2010. This borrowing was repaid by Antargaz on October 25, 2010.

Antargaz’ management believes that it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2011 with cash generated from operations, borrowings under its existing or new revolving credit facilities and guarantees under letter of credit facilities.

Flaga . Flaga has two euro-based, amortizing variable-rate term loans. The principal outstanding on the first term loan was € 24.0 million ($32.7 million) at September 30, 2010. Flaga has effectively fixed the euribor component of its interest rate on this term loan through September 2011 at 3.91% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2010 was 4.21%. The second term loan, executed in August 2009, had an outstanding principal balance of € 5.6 million ($7.6 million) on September 30, 2010. This term loan matures through June 2014. Flaga has effectively fixed the euribor component of its interest rate on this term loan at 2.16% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2010 was 5.03%.

Flaga has two working capital facilities totaling € 24 million. Flaga has a multi-currency working capital facility that provides for borrowings and issuances of guarantees totaling € 16 million of which € 9.8 million ($13.4 million) was outstanding at September 30, 2010 at an average interest rate of 3.64%. Flaga also has an € 8 million euro-denominated working capital facility of which € 7.9 million ($10.8 million) was outstanding at September 30, 2010 at an average interest rate of 2.01%. Issued and outstanding guarantees, which reduce available borrowings under the working capital facilities, totaled € 5.4 million ($7.4 million) at September 30, 2010. Amounts outstanding under the working capital facilities are classified as bank loans. During Fiscal 2010, average and peak bank loan borrowings totaled € 12.7 million and € 17.8 million, respectively. During Fiscal 2009, average and peak bank loan borrowings totaled € 11.5 million and € 18.6 million, respectively. For a more detailed discussion of Flaga’s debt, see Note 5 to Consolidated Financial Statements. In order to provide for additional borrowing capacity, in November 2010, Flaga entered into an additional € 8 million multi-currency working capital facility and an additional € 4 million euro-denominated working capital facility both of which expire in June 2011. Flaga expects to combine and extend these new facilities along with the other working capital facilities described above prior to their expiration in June 2011.

Based upon cash generated from operations, borrowings under its working capital facilities and capital contributions from UGI, Flaga’s management believes it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2011.

UGI Utilities. UGI Utilities’ total debt at September 30, 2010 includes long-term debt comprising $383 million of Senior Notes and $257 million of Medium-Term Notes. Total debt outstanding at September 30, 2010 also includes $17 million outstanding under UGI Utilities’ Revolving Credit Agreement.

UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement which expires in August 2011. UGI Utilities expects to renew this facility before its expiration. At September 30, 2010 and 2009, there were $17 million and $154 million of borrowings outstanding under the Revolving Credit Agreement having average interest rates of 3.25% and 0.59%, respectively. The higher average interest rate at September 30, 2010 is the result of a prime rate borrowing compared to LIBOR borrowings at September 30, 2009. Borrowings under the Revolving Credit Agreement are classified as bank loans on the Consolidated Balance Sheets. During Fiscal 2010 and Fiscal 2009, average daily bank loan borrowings were $69.9 million and $180.0 million, respectively, and peak bank loan borrowings totaled $203 million and $312 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January. During Fiscal 2009, average daily and peak bank loan borrowings were higher than during Fiscal 2010 due in large part to higher margin deposits associated with natural gas futures accounts as a result of declines in wholesale natural gas prices and higher Fiscal 2009 borrowings needed to fund working capital.

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

Midstream & Marketing. In August 2010, Energy Services entered into 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, 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 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 2011, 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 and capital expenditures. Energy Services intends to extend its Receivables Facility prior to its scheduled expiration in April 2011.

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. 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. At September 30, 2009, the outstanding balance of ESFC trade receivables was $38.2 million which is net of $31.3 million that was sold to the commercial paper conduit and removed from the balance sheet. During Fiscal 2010 and Fiscal 2009, peak sales of receivables were $45.7 million and $139.7 million, respectively.

Effective October 1, 2010, the Company will adopt a new accounting standard that will change the accounting for the Receivables Facility. Beginning October 1, 2010, trade receivables transferred to the commercial paper conduit will remain on the Company’s balance sheet and the Company will reflect a liability equal to the amount advanced by the commercial paper conduit. Additionally, the Company will record interest expense on amounts owed to the commercial paper conduit. For further information on the effects of the accounting change, see Note 3 to Consolidated Financial Statements.

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 2011.

Cash Flows

Operating Activities. Year-to-year variations in cash flow from operations can be significantly affected by changes in operating working capital especially during periods of volatile energy commodity prices. During Fiscal 2010, commodity prices for LPG rose compared with LPG commodity price declines experienced in Fiscal 2009. During Fiscal 2009, commodity prices of LPG and natural gas decreased significantly compared with significant price increases experienced during most of the second half of Fiscal 2008. The increase in Fiscal 2010 LPG prices resulted in increased cash invested in accounts receivable and LPG inventories. The decline in Fiscal 2009 commodity prices compared with Fiscal 2008 resulted in reduced investments in accounts receivable and LPG inventories which had the effect of significantly increasing cash flow from operating activities in Fiscal 2009 compared to Fiscal 2008.

Cash flow provided by operating activities was $598.8 million in Fiscal 2010, $665.0 million in Fiscal 2009 and $464.4 million in Fiscal 2008. Cash flow from operating activities before changes in operating working capital was $663.8 million in Fiscal 2010, $611.7 million in Fiscal 2009 and $525.3 million in Fiscal 2008. The increase in the Fiscal 2010 amount reflects in large part higher noncash charges for deferred income taxes ($35.8 million) due primarily to a change in tax accounting for distribution system repair and maintenance costs at UGI Utilities (see below and Note 6 to Consolidate Financial Statements). The increase in Fiscal 2009 cash flow from operating activities before changes in working capital compared with Fiscal 2008 reflects the improved operating results. Changes in operating working capital (used) provided operating cash flow of $(65.0) million in Fiscal 2010, $53.3 million in Fiscal 2009 and $(60.9) million in Fiscal 2008. Cash flow from changes in operating working capital principally reflects the impacts of changes in LPG and natural gas prices on cash receipts from customers as reflected in changes in accounts receivable and accrued utility revenues; the timing of purchases and changes in LPG and natural gas prices on our investments in inventories; the timing of natural gas cost recoveries through Gas Utility’s PGC recovery mechanism; and the effects of the timing of payments and changes in purchase price per gallon of LPG and natural gas on accounts payable. The 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 in Fiscal 2009. The greater Fiscal 2009 cash provided by changes in operating working capital compared with cash provided by such changes in Fiscal 2008 principally reflects the effects on net cash receipts from customers and cash expenditures for purchases of inventories resulting from significantly lower Fiscal 2009 LPG commodity prices compared with Fiscal 2008.

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 $399.3 million in Fiscal 2010, $519.9 million in Fiscal 2009 and $289.5 million in Fiscal 2008. Fiscal 2010 expenditures for property, plant and equipment were greater than in Fiscal 2009 primarily due to higher Midstream & Marketing cash capital expenditures (an increase of $45.1 million) principally associated with natural gas storage and electric generation projects. 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. The primary reasons for the increase in cash used by investing activities in Fiscal 2009 compared to Fiscal 2008 were the acquisition of CPG ($292.6 million) and greater cash expenditures for property, plant and equipment ($69.6 million). Fiscal 2010, Fiscal 2009 and Fiscal 2008 investing activity cash flows also reflect cash (used for) provided by changes in restricted cash in natural gas futures brokerage accounts of $(27.8) million, $63.3 million and $(57.5) million, respectively. Changes in restricted cash in futures and options brokerage accounts are the result of the timing of settlement of natural gas futures contracts and changes in natural gas prices. During Fiscal 2010 and Fiscal 2009, we received $66.6 million and $42.4 million in cash proceeds from the sale of Atlantic Energy and the sale of the Partnership’s California LPG storage facility, respectively.

Financing Activities. Cash flow used by financing activities was $213.6 million, $114.6 million and $180.1 million in Fiscal 2010, Fiscal 2009 and Fiscal 2008, respectively. Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; net bank loan borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units and issuances of UGI and AmeriGas Partners equity instruments.

During Fiscal 2010, AmeriGas OLP repaid $80 million of maturing First Mortgage Notes using borrowings under its revolving credit facilities and cash from operations and Flaga made scheduled payments on its term loans of € 7.4 million ($10.4 million) using cash from operations, UGI cash contributions and borrowings under working capital facilities. Changes in bank loans during Fiscal 2010 principally reflect € 50 million ($67.7 million) borrowed by Antargaz in September 2010 (repaid in October 2010) in order to minimize the interest margin it pays on its Senior Facilities Agreement; Partnership revolving credit facility borrowings of $91 million; and higher revolving credit facility borrowings at Flaga ($16.2 million). These increases were largely offset by a $137 million decrease in bank loan borrowings at UGI Utilities due primarily to cash flow generated from changes in operating working capital.

Capital Expenditures

In the following table, we present capital expenditures (which exclude acquisitions but include capital leases) by our business segments for Fiscal 2010, Fiscal 2009 and Fiscal 2008. We also provide amounts we expect to spend in Fiscal 2011. We expect to finance Fiscal 2011 capital expenditures principally from cash generated by operations, borrowings under credit facilities and cash on hand.

AmeriGas Propane capital expenditures in Fiscal 2010 and Fiscal 2009 include expenditures associated with a system software replacement. The decline in International Propane capital expenditures in Fiscal 2010 is principally due to lower expenditures for cylinders. The increases in Midstream & Marketing’s capital expenditures in Fiscal 2010 and Fiscal 2009 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 higher “other” capital expenditures in Fiscal 2010 principally reflects capital improvements at UGI Corporation’s headquarters’ facility following a fire. Midstream & Marketing’s estimated expenditures in Fiscal 2011, principally relating to the completion of its Hunlock Station repowering project, the continued expansion 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 August 2010, the Company announced that it plans to invest approximately $300 million over the next two years on infrastructure projects to support the development of natural gas in the Marcellus Shale region. This anticipated investment includes Midstream & Marketing’s potential participation in the Pennsylvania natural gas pipeline project being jointly developed with NiSource Gas Transmission and Storage Company (“NiSource”) described below under “Contractual Cash Obligations and Commitments.” In addition the Company plans to pursue the enhancement of its existing underground storage fields located in north-central Pennsylvania, as well as to pursue additional projects to acquire and construct gas gathering facilities that would make locally produced gas available to Pennsylvania and interstate markets. 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. Such investment is expected to be financed with a combination of debt and UGI equity.

Contractual Cash Obligations and Commitments

The Company has contractual cash obligations that extend beyond Fiscal 2010. 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, 2010:

Other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2010 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 the UGI Utilities’ pension plans in Fiscal 2011 of approximately $20 million. Contributions to the pension plans in years beyond Fiscal 2011 will depend in large part on future returns on pension plans assets. In addition, at September 30, 2010 we were committed to invest over the next several years an additional $9.6 million in a limited partnership that focuses on investments in the alternative energy sector.

In August 2010, Energy Services entered into a Joint Marketing and Development Agreement with NiSource to evaluate the feasibility of constructing a natural gas pipeline in the Marcellus Shale gas production region of north-central Pennsylvania. The parties are currently working cooperatively and sharing preliminary costs in developing a route, engineering design and cost estimate for the pipeline and in marketing the project to potential customers.

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 borrowings under UGI Utilities’ Revolving Credit Agreement. AmeriGas OLP funded the acquisition of the assets of CPP with borrowings under the AmeriGas Credit Agreement, and UGI Utilities used the $33.6 million of cash proceeds from the sale of the assets of CPP to reduce its revolving credit agreement borrowings.

On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated above-ground LPG storage facility located on leased property in California for net cash proceeds of $42.4 million. The 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 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 (“DGCCRF”). A Statement of Objections (“Statement”) is part of French competition proceedings and generally follows an investigation under French competition laws. The Statement sets forth the Competition Authority’s findings; it is not a judgment or final decision. The Statement alleges that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through 2004. The alleged violations occurred principally during periods prior to March 31, 2004, when UGI first obtained a controlling interest in Antargaz. Based on an assessment of the information contained in the Statement, during the quarter ended June 30, 2009 we recorded a provision of $10.0 million ( € 7.1 million) related to this matter which amount is reflected in “Other income, net” on the Fiscal 2009 Consolidated Statement of Income.

We filed our written response to the Statement of Objections with the Competition Authority on October 21, 2009. The Competition Authority completed its review of Antargaz’ response and issued its report on April 26, 2010. Antargaz filed its response to this report on June 28, 2010. A hearing before the Competition Authority was held on September 21, 2010 and a decision is not expected before the end of 2010. Based on our assessment of the information contained in the report and the hearing, we believe that we have good defenses to the objections and that the reserve established by management for this matter is adequate. However, the final resolution could result in payment of an amount significantly different from the amount we have recorded (see Note 15 to Consolidated Financial Statements).

Pension Plans

As of September 30, 2010, we sponsor two defined benefit pension plans (“Pension Plans”) for employees hired prior to January 1, 2009 of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans. The Antargaz plans’ assets and benefit obligations are not material.

The fair value of Pension Plans’ assets totaled $287.9 million and $276.4 million at September 30, 2010 and 2009, respectively. At September 30, 2010 and 2009, the underfunded position of Pension Plans, defined as the excess of the projected benefit obligations (“PBOs”) over the Pension Plans’ assets, was $177.1 million and $145.6 million, respectively.

We believe we are in compliance with regulations governing defined benefit pension plans, including Employee Retirement Income Security Act of 1974 (“ERISA”) rules and regulations. We anticipate that we will be required to make contributions to Pension Plans during Fiscal 2011 of approximately $20 million. Pre-tax pension cost associated with Pension Plans in Fiscal 2010 was $11.5 million. Pre-tax pension cost associated with Pension Plans in Fiscal 2011 is expected to be approximately $14.9 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. Based upon an August 2010 PUC order issued in response to UGI Utilities’ and PNG’s joint petition regarding the regulatory treatment of the funded status of their combined pension plan, effective September 30, 2010, UGI Utilities recorded a regulatory asset of $142.4 million associated with the underfunded position of the combined pension plan (see below and Note 8 to Consolidated Financial Statements). Previously, the effects of such underfunded position were reflected in accumulated other comprehensive income. Through September 30, 2010, we have recorded cumulative after-tax charges to UGI Corporation’s stockholders’ equity of $12.8 million and recorded regulatory assets totaling $159.2 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.

Change in Tax Method of Accounting

The Company received Internal Revenue Service (“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. 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 million which was used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 stand alone Pennsylvania income tax return also produced a $43.4 million state net operating loss (“NOL”) carryforward. Under current Pennsylvania state income tax law, the NOL stated above can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. 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. For more information on the change in tax method of accounting, see Note 6 to Consolidated Financial Statements.

Related Party Transactions

During Fiscal 2010, Fiscal 2009 and Fiscal 2008, 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 accounting principles generally accepted in the United States of America “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 28, 2009, PNG and CPG filed separate requests with the PUC to increase base operating revenues by $38.1 million annually for PNG and $19.6 million annually for CPG to fund system improvements and operations necessary to maintain safe and reliable natural gas service and energy assistance for low income customers as well as energy conservation programs for all customers. On July 2, 2009, PNG and CPG each filed joint settlement petitions with the PUC based on agreements with the opposing parties regarding the requested base operating revenue increases. On August 27, 2009, the PUC approved the settlement agreements which resulted in a $19.8 million base operating revenue increase for PNG Gas and a $10.0 million base operating revenue increase for CPG Gas. The increases became effective August 28, 2009. The full-year effects of these rate increases are reflected in Gas Utility’s Fiscal 2010 results.

Electric Utility

As a result of Pennsylvania’s ECC Act, all of Electric Utility’s customers are permitted to acquire their electricity from entities other than Electric Utility. Electric Utility remains the default service provider for its customers that are not served by an alternate electric generation provider.

On July 17, 2008, the PUC approved Electric Utility’s DS procurement, implementation and contingency plans, as modified by the terms of a May 2, 2008 settlement, filed in accordance with the PUC’s DS regulations. The approved plans specify how Electric Utility will solicit and acquire DS supplies for residential customers for the period January 1, 2010 through May 31, 2014, and for commercial and industrial customers for the period January 1, 2010 through May 31, 2011 (collectively, the “Settlement Term”). UGI Utilities filed a rate plan on August 29, 2008 for the Settlement Term. On January 22, 2009, the PUC approved a settlement of the rate filing that provides for Electric Utility to fully recover its DS costs. On October 1, 2009, UGI Utilities filed a DS plan to establish procurement rules applicable to the period after May 31, 2011 for its commercial and industrial customers. Because Electric Utility is assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010 Electric Utility is no longer subject to the risk that actual costs for purchased power will exceed POLR revenues. However, beginning January 1, 2010, Electric Utility no longer has the opportunity to recover revenues in excess of actual costs. On May 6, 2010, the PUC approved the plan, as modified by the terms of a March 2010 settlement.

Prior to January 1, 2010, the terms and conditions under which Electric Utility provided POLR service, and rules governing the rates that could 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. Consistent with the terms of the POLR Settlement, Electric Utility increased its POLR rates effective January 1, 2009, which increased the average cost to a residential heating customer by approximately 1.5% over such costs in effect during calendar year 2008. Effective January 1, 2008, Electric Utility increased its POLR rates which increased the average cost to a residential heating customer by approximately 5.5% over such costs in effect during calendar year 2007.

Regulatory Asset — UGI Utilities Pension Plan

On April 14, 2010, UGI Utilities, Inc. and PNG filed a petition with the PUC requesting permission to record a regulatory asset or liability for amounts relating to their combined pension plan that otherwise would be recorded to accumulated other comprehensive income under the FASB’s Accounting Standards Codification (“ASC”) 715, “Compensation — Retirement Benefits.” On August 23, 2010, the PUC issued an order permitting UGI Utilities and PNG to establish regulatory assets for such amounts relating to their regulated operations. Effective September 30, 2010, UGI Utilities recorded a regulatory asset totaling $142.4 million associated with the underfunded position of the combined pension plan.

Subsequent Event — Approval of Transfer of CPG Storage Assets

On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved 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 a special purpose entity, UGI Storage Company, a subsidiary of Energy Services. CPG will transfer the natural gas storage facilities on or before April 1, 2011. The net book value of the storage facility assets was approximately $11.0 million as of September 30, 2010.

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 2011 for the MGP Properties and at the end of 2013 for well plugging activities. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At September 30, 2010 and 2009, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $21.4 million and $25.0 million, respectively. 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 manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility.

UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. At September 30, 2010, neither UGI Gas’ undiscounted nor its accrued liability for environmental investigation and cleanup costs was material.

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

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

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

AmeriGas OLP

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

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

Market Risk Disclosures

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

Commodity Price Risk

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

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for a periodic adjustment for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments 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. At September 30, 2010, the net fair value of Gas Utility’s natural gas futures and option contracts was a loss of $1.4 million. There were no gains or losses at September 30, 2009.

Beginning January 1, 2010, Electric Utility’s DS tariffs contain clauses which permit recovery of all prudently incurred power costs through the application of DS rates. The clauses provide for periodic adjustments to DS rates for differences between the total amount of power costs collected from customers and recoverable power costs incurred. Because of this ratemaking mechanism, beginning January 1, 2010 there is limited power cost risk, including the cost of financial transmission rights (“FTRs”), associated with our Electric Utility operations. FTRs are financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electricity transmission grid. Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) auction process and, to a lesser extent, through purchases at monthly PJM auctions. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states.

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, 2010 were not material.

Midstream & Marketing purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. Although Midstream & Marketing’s FTRs are economically effective as hedges of congestion charges, 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 purchases over-the-counter as well as exchange-traded natural gas and electricity futures contracts or enters into fixed-price supply arrangements. 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 such electricity on the spot market or under contract with other electricity suppliers. Accordingly, increases in the cost of replacement power could negatively impact the Company’s results.

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 currently includes borrowings under AmeriGas OLP’s credit agreements, UGI Utilities’ Revolving Credit Agreement and a substantial portion of Antargaz’ and Flaga’s debt. These debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has effectively fixed the underlying euribor interest rate on its variable-rate debt through its March 2011 maturity date and Flaga has fixed the underlying euribor interest rate on a substantial portion of its term loans through their scheduled maturity dates through the use of interest rate swaps. At September 30, 2010 combined borrowings outstanding under these agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled $200.4 million. Excluding the fixed portions of Antargaz’ and Flaga’s variable-rate debt, and based upon weighted average borrowings outstanding under variable-rate agreements during Fiscal 2010 and Fiscal 2009, an increase in short-term interest rates of 100 basis points (1%) would have increased our Fiscal 2010 and Fiscal 2009 interest expense by $1.3 million and $2.3 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 $94.7 million and $91.0 million at September 30, 2010 and 2009, respectively. A 100 basis point decrease in market interest rates would result in increases in the fair value of this fixed-rate debt of $104.8 million and $100.7 million at September 30, 2010 and 2009, respectively.

Antargaz intends to refinance its variable-rate term loan maturing debt, subject to market conditions, on a long-term basis by March 2011. As of September 30, 2010, Antargaz has entered into forward-starting interest rate swaps to hedge the underlying euribor rate of interest relating to 4 ¹ / ₂  years of quarterly interest payments on € 300 million notional amount of long-term debt commencing March 31, 2011.

Our long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. 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-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, 2010, the fair value of unsettled net investment hedges was a gain of $0.8 million which is included in foreign currency exchange rate risk in the table below. 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 by approximately $65.8 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 represents approximately 20%-30% of estimated dollar-denominated purchases to occur during the heating-season months of October to March.

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise major energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. 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, 2010 and 2009, restricted cash in brokerage accounts totaled $34.8 million and $7.0 million, respectively.

The following table summarizes the fair values of unsettled market risk sensitive derivative instruments assets and (liabilities) held at September 30, 2010 and 2009. 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 LIBOR and the three- and nine-month Euribor; and (3) the value of the euro versus the U.S. dollar. Gas Utility’s and Electric Utility’s derivative instruments 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.

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 accounting principles generally accepted in the United States of America, the Company establishes reserves for pending claims and legal actions or environmental remediation obligations when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Reasonable estimates involve management judgments based on a broad range of information and prior experience. These judgments are reviewed quarterly as more information is received and the amounts reserved are updated as necessary. Such estimated reserves may differ materially from the actual liability and such reserves may change materially as more information becomes available and estimated reserves are adjusted.

Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to regulation by the PUC. In accordance with accounting guidance associated with rate-regulated entities, we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. Based upon GAAP related to rate-regulated entities and an August 2010 PUC order issued in response to UGI Utilities’ and PNG’s April 2010 joint petition regarding the regulatory treatment of their combined pension plan, effective September 30, 2010, UGI Utilities recorded a $142.4 million regulatory asset associated with amounts that would otherwise be recorded in accumulated other comprehensive income under GAAP. As of September 30, 2010, our regulatory assets totaled $306.7 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, 2010, our net property, plant and equipment totaled $3,053.2 million and we recorded depreciation expense of $187.6 million during Fiscal 2010. As of September 30, 2010, our net intangible assets other than goodwill totaled $150.1 million and we recorded amortization expense on intangible assets of $19.9 million during Fiscal 2010.

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, 2010, our goodwill totaled $1,562.7 million. We did not record any impairments of goodwill in Fiscal 2010, Fiscal 2009 and Fiscal 2008.

Pension Plan Assumptions. The cost of providing benefits under our Pension Plans is dependent on historical information such as employee age, length of service, level of compensation and the actual rate of return on plan assets. In addition, certain assumptions relating to the future are used to determine pension expense including the discount rate applied to benefit obligations, the expected rate of return on plan assets and the rate of compensation increase, among others. Assets of the Pension Plans are held in trust and consist principally of equity and fixed income mutual funds. Changes in plan assumptions as well as fluctuations in actual equity or fixed income market returns could have a material impact on future pension costs. We believe the two most critical assumptions are (1) the expected rate of return on plan assets and (2) the discount rate. A decrease in the expected rate of return on Pension Plans assets of 50 basis points to a rate of 8.0% would result in an increase in pre-tax pension cost of approximately $1.5 million in Fiscal 2011. A decrease in the discount rate of 50 basis points to a rate of 4.5% would result in an increase in pre-tax pension cost of approximately $2.5 million in Fiscal 2011.

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. In Fiscal 2008, we adopted new guidance which establishes standards for recognition and measurement of positions taken or expected to be taken by an entity in its tax returns. Positions taken by an entity in its tax returns must satisfy a more-likely-than-not recognition threshold assuming the position will be examined by tax authorities with full knowledge of relevant information. We use assumptions, judgments and estimates to determine our current provision for income taxes. We also use assumptions, judgments and estimates to determine our deferred tax assets and liabilities and any valuation allowance to be recorded against a deferred tax asset. Our assumptions, judgments and estimates relative to the current provision for income tax give consideration to current tax laws, our interpretation of current tax laws and possible outcomes of current and future audits conducted by foreign and domestic tax authorities. Changes in tax law or our interpretation of such and the resolution of current and future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. Our assumptions, judgments and estimates relative to the amount of deferred income taxes take into account estimates of the amount of future taxable income. Actual taxable income or future estimates of taxable income could render our current assumptions, judgments and estimates inaccurate. Changes in the assumptions, judgments and estimates mentioned above could cause our actual income tax obligations to differ significantly from our estimates. As of September 30, 2010, our net deferred tax liabilities totaled $568.8 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 2010 as well as recently issued accounting guidance not yet adopted.

PART III: