Business description of UGI-CORP-PA

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

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

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

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

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

Our profitability is subject to LPG pricing and inventory risk.

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

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

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

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

The 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

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 and European Union civil competition laws related to the cylinder market during the period from 1999 through 2004. The alleged violations occurred principally during periods prior to March 31, 2004, when UGI first obtained a controlling interest in Antargaz.

We 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 (“Report”). The Report is the third pleading typically filed in a competition proceeding, preceded first by a Statement of Objections filed by the Competition Authority, and then the Answer to the Statement filed by the defendant in the proceeding. The Report is, in essence, a revised version of the Statement which takes into consideration both the evidence and arguments made by a defendant in its Answer to the Statement. Similarly, in response to the Report, a defendant has the opportunity to file an Answer to the Report. Following submission of the two rounds of pleadings, a hearing is scheduled to allow the respective parties to present oral argument on the allegations contained in the Statement and Report.

In its Report, the Competition Authority stated its intent to prosecute two of the alleged violations of French competition (antitrust) law. The alleged violations were that Antargaz abused its collective dominant position by: (i) refusing to provide a new competitor with access to liquid petroleum gas filling centers; and (ii) exerting pressure on a cylinder manufacturer not to do business with that competitor. The Report also recommended the abandonment of the third and final alleged violation, which involved an alleged illegal sharing of pricing information by Antargaz. The Report did not contain any new allegations. Although the Report and the Statement did not specify the nature or amount of relief being sought by the Competition Authority, the applicable statutes provide for maximum penalties of up to 10% of a company’s or parent company’s consolidated annual revenues, levied on the highest annual revenue beginning with the fiscal year immediately preceding the year in which the alleged violations first occurred. Based on our understanding of cases of this nature, we have recorded a reserve of $10 million, which we based on the revenues of Antargaz, rather than on the consolidated revenues of UGI, because UGI has not been named as a party to these proceedings.

Antargaz filed its Answer to the Report on June 28, 2010 and a hearing before the Competition Authority was held on September 21, 2010 (“Hearing”). Based on our review of the Report and participation in oral argument at the Hearing, we continue to believe that the $10 million reserve previously established by management is adequate. Notwithstanding our view, the final resolution could result in payment of an amount significantly different from the amount we have recorded. The relief to be awarded in this matter, if any, will not be known until a decision on the action has been issued.

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

ITEM 4. (REMOVED AND RESERVED)

EXECUTIVE OFFICERS

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

PART II:

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our Common Stock is traded on the New York Stock Exchange under the symbol “UGI.” The following table sets forth the high and low sales prices for the Common Stock on the New York Stock Exchange Composite Transactions tape as reported in The Wall Street Journal for each full quarterly period within the two most recent fiscal years:

4th Quarter

3rd Quarter

2nd Quarter

1st Quarter

Dividends

Quarterly dividends on our Common Stock were paid in Fiscal 2010 and Fiscal 2009 as follows:

Record Holders

On November 15, 2010, UGI had 7,780 holders of record of Common Stock.

ITEM 6. SELECTED FINANCIAL DATA

FOR THE PERIOD:

Income statement data:

Revenues

Net income

Less: net income attributable to noncontrolling interests, principally in AmeriGas Partners

Net income attributable to UGI Corporation

Earnings per common share attributable to UGI stockholders:

Basic

Diluted

Cash dividends declared per common share

AT PERIOD END:

Balance sheet data:

Total assets

Capitalization:

Debt:

Bank loans — UGI Utilities

Bank loans — AmeriGas Propane

Bank loans — Antargaz

Bank loans — other

Long-term debt (including current maturities):

AmeriGas Propane

Antargaz

UGI Utilities

Other

Total debt

UGI Corporation stockholders’ equity

Noncontrolling interests, principally in AmeriGas Partners

Total capitalization

Ratio of capitalization:

Total debt

UGI Corporation stockholders’ equity

Noncontrolling interests, principally in AmeriGas Partners

As adjusted in accordance with the transition provisions for accounting for and presentation of noncontrolling interests in consolidated subsidiaries (see Note 3 to Consolidated Financial Statements).

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:

AmeriGas Propane

International Propane

Gas Utility

Electric Utility

Midstream & Marketing

Corporate & Other

Net income attributable to UGI Corporation

N.M. — Variance is not meaningful.

Highlights — Fiscal 2010 versus Fiscal 2009

Gas Utility results in Fiscal 2010 reflect the full-year impact of the PNG Gas and CPG Gas August 2009 base rate revenue increases.

Midstream & Marketing’s Fiscal 2010 net income includes a $17.2 million after-tax gain on the sale of Midstream & Marketing’s Atlantic Energy subsidiary.

AmeriGas Propane Fiscal 2010 results include a $3.3 million after-tax loss on interest rate hedges while Fiscal 2009 results include a $10.4 million after-tax gain from the sale of its California LPG storage terminal.

Fiscal 2010 International Propane results reflect lower average unit margins compared with the higher than normal unit margins in Fiscal 2009.

Midstream & Marketing’s Fiscal 2010 results benefited from greater natural gas and retail power margin.

The lingering effects of the global economic recession continued to impact overall business activity in all of our business units.

Revenues

Total margin (a)

Partnership EBITDA (b)

Operating income

Retail gallons sold (millions)

Degree days — % (warmer) than normal (c)

Total margin represents total revenues less total cost of sales.

Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements). Partnership EBITDA (and operating income) in Fiscal 2010 includes a pre-tax loss of $12.2 million associated with the discontinuance of interest rate hedges and a loss of $7 million associated with an increase in a litigation accrual. Partnership EBITDA (and operating income) in Fiscal 2009 includes a pre-tax gain of $39.9 million associated with the sale of the Partnership’s California LPG storage facility.

Deviation from average heating degree-days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska. Fiscal 2009 data has been adjusted to correct a NOAA error.

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.

(Millions of euros) (a)

Total margin (b)

Income before income taxes

(Millions of dollars) (a)

Antargaz retail gallons sold

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

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

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

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

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

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

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

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

System throughput — billions of cubic feet (“bcf”)

Degree days — % (warmer) colder than normal (b)

Deviation from average heating degree days for the 15-year period 1990-2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

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

Distribution sales — millions of kilowatt hours (“gwh”)

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

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

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

Fiscal 2009 Compared with Fiscal 2008 Consolidated Results

Highlights — Fiscal 2009 versus Fiscal 2008

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

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

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

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

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

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

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

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

Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements). Partnership EBITDA and operating income in Fiscal 2009 includes a pre-tax gain of $39.9 million associated with the sale of the Partnership’s California LPG storage facility.

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.

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

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.

Degree days — % colder (warmer) than normal (b)

Deviation from average heating degree days for the 15-year period 1990–2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

Temperatures in the Gas Utility service territory based upon heating degree days were 4.1% 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).

Distribution sales — millions of kilowatt hours (“gwh”)

Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $7.6 million and $7.9 million during Fiscal 2009 and Fiscal 2008, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Consolidated Statements of Income.

Electric Utility’s kilowatt-hour sales in Fiscal 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:

UGI Utilities

Total

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.

Other

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:

Long-term debt (a)

Interest on long-term fixed rate debt (b)

Operating leases

AmeriGas Propane supply contracts

International Propane supply contracts

Midstream & Marketing supply contracts

Gas Utility and Electric Utility supply, storage and transportation contracts

Derivative financial instruments (c)

Other purchase obligations (d)

Based upon stated maturity dates.

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

Represents the sum of amounts due from us if derivative financial instrument liabilities were settled at the September 30, 2010 amounts reflected in the Consolidated Balance Sheet (but excluding amounts associated with interest rate swaps).

Includes material capital expenditure obligations.

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.

September 30, 2010:

Commodity price risk

Interest rate risk

Foreign currency exchange rate risk

September 30, 2009:

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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

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

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

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

ITEM 9B. OTHER INFORMATION

None.

PART III:

ITEMS 10 THROUGH 14.

In accordance with General Instruction G(3), and except as set forth below, the information required by Items 10, 11, 12, 13 and 14 is incorporated in this Report by reference to the following portions of UGI’s Proxy Statement, which will be filed with the Securities and Exchange Commission by December 31, 2010.

Item 10.

Item 11.

Item 12.

Item 13.

Item 14.

Equity Compensation Table

The following table sets forth information as of the end of Fiscal 2010 with respect to compensation plans under which our equity securities are authorized for issuance.

Equity compensation plans approved by security holders

Equity compensation plans not approved by security holders

Represents 7,392,720 stock options under the 1997 Stock Option and Dividend Equivalent Plan, the 2000 Directors’ Stock Option Plan, the 2000 Stock Incentive Plan and the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006.

Represents 930,493 phantom share units under the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006.

Column (a) represents 164,325 stock options under the 1992 and 2002 Non-Qualified Stock Option Plans. Under the 1992 and 2002 Non-Qualified Stock Option Plans, the option exercise price is not less than 100% of the fair market value of the Company’s common stock on the date of grant. Generally, options become exercisable in three equal annual installments beginning on the first anniversary of the grant date. All options are non-transferable and generally exercisable only while the holder is employed by the Company or an affiliate, with exceptions for exercise following retirement, disability and death. Options are subject to adjustment in the event of recapitalization, stock splits, mergers and other similar corporate transactions affecting the Company’s common stock.

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

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

Lon R. Greenberg

John L. Walsh

Davinder S. Athwal

Eugene V.N. Bissell

Bradley C. Hall

Peter Kelly

Robert H. Knauss

François Varagne

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

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

Lon R. Greenberg

Mr. Greenberg was elected Chairman of the Board of Directors of UGI effective August 1, 1996, having been elected Chief Executive Officer effective August 1, 1995. He held the office of President of UGI from 1994 to 2005. He was elected Director of UGI and UGI Utilities in July 1994. He was elected a Director of AmeriGas Propane, Inc. in 1994 and has been Chairman since 1996. He also served as President and Chief Executive Officer of AmeriGas Propane (1996 to 2000). Mr. Greenberg was Senior Vice President — Legal and Corporate Development (1989 to 1994). He joined the Company in 1980 as Corporate Development Counsel. Mr. Greenberg also serves on the board of directors and the audit and compensation committees of Aqua America, Inc.

John L. Walsh

Mr. Walsh is President and Chief Operating Officer and a Director (since April 2005). He is also Vice Chairman and Director of AmeriGas Propane, Inc., and Director, Vice Chairman, (since April 2005), President and Chief Executive Officer (since July 2009) of UGI Utilities, Inc. He previously served as Chief Executive of the Industrial and Special Products division and executive director of BOC Group PLC, an industrial gases company (2001 to 2005). From 1986 to 2001, he held various senior management positions with the BOC Group. Prior to joining BOC Group, Mr. Walsh was a Vice President of UGI’s industrial gas division prior to its sale to BOC Group in 1989. From 1981 until 1986, Mr. Walsh held several management positions with affiliates of UGI.

Davinder S. Athwal

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

Eugene V.N. Bissell

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

Bradley C. Hall

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

Peter Kelly

Mr. Kelly is Vice President — Finance and Chief Financial Officer (since September 2007). He previously served as Executive Vice President and Chief Financial Officer of Agere Systems, Inc., a global manufacturer of semiconductors, a position in which he served from 2005 to 2007. Mr. Kelly served as Executive Vice President-Global Operations for Agere Systems, Inc. (2001 to 2005). Mr. Kelly currently serves on the board of directors and the audit and compensation and leadership development committees of Plexus Corp., an electronics manufacturing services company. Mr. Kelly is planning to retire in early 2011.

Robert H. Knauss

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

François Varagne

Mr. Varagne is Chairman of the Board and Chief Executive Officer of Antargaz (since 2001). Before joining Antargaz, Mr. Varagne was Chairman of the Board and Chief Executive Officer of VIA GTI, a common carrier in France (1998 to 2001). Prior to that, Mr. Varagne was Chairman of the Board and Chief Executive Officer of Brink’s France, a funds carrier (1997 to 1998).

PART IV:

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents filed as part of this report:

(1) Financial Statements:

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

Management’s Report on Internal Control over Financial Reporting

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of September 30, 2010 and 2009

Consolidated Statements of Income for the years ended September 30, 2010, 2009 and 2008

Consolidated Statements of Comprehensive Income for the years ended September 30, 2010, 2009 and 2008

Consolidated Statements of Cash Flows for the years ended September 30, 2010, 2009 and 2008

Consolidated Statements of Changes in Equity for the years ended September 30, 2010, 2009 and 2008

Notes to Consolidated Financial Statements

(2) Financial Statement Schedules:

I — Condensed Financial Information of Registrant (Parent Company)

II — Valuation and Qualifying Accounts for the years ended September 30, 2010, 2009 and 2008

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

(3) List of Exhibits:

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

(Second) Amended and Restated Articles of Incorporation of the Company as amended through June 6, 2005

Bylaws of UGI as amended through September 28, 2004

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

The description of the Company’s Common Stock contained in the Company’s registration statement filed under the Securities Exchange Act of 1934, as amended

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

Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. dated as of July 27, 2009

Indenture, dated May 3, 2005, by and among AmeriGas Partners, L.P., a Delaware limited partnership, AmeriGas Finance Corp., a Delaware corporation, and Wachovia Bank, National Association, as trustee

Indenture, dated January 26, 2006, by and among AmeriGas Partners, L.P., a Delaware limited partnership, AP Eagle Finance Corp., a Delaware corporation, and U.S. Bank National Association, as trustee

Indenture, dated as of August 1, 1993, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, as successor trustee, incorporated by reference to the Registration Statement on Form S-3 filed on April 8, 1994

Supplemental Indenture, dated as of September 15, 2006, by and between UGI Utilities, Inc., as Issuer, and U.S. Bank National Association, successor trustee to Wachovia Bank, National Association

Form of Fixed Rate Medium-Term Note

Form of Fixed Rate Series B Medium-Term Note

Form of Floating Rate Series B Medium-Term Note

Officer’s Certificate establishing Medium-Term Notes Series

Form of Officer’s Certificate establishing Series B Medium-Term Notes under the Indenture

Form of Officers’ Certificate establishing Series C Medium-Term Notes under the Indenture

Forms of Floating Rate and Fixed Rate Series C Medium-Term Notes

UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006

UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 — Terms and Conditions as amended and restated effective January 1, 2009

UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees effective December 6, 2005

UGI Corporation Amended and Restated 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers effective May 20, 2008

UGI Corporation Amended and Restated Directors’ Deferred Compensation Plan as of January 1, 2005

UGI Corporation 2000 Directors’ Stock Option Plan Amended and Restated as of May 24, 2005

UGI Corporation 1997 Stock Option and Dividend Equivalent Plan Amended and Restated as of May 24, 2005

UGI Corporation 2000 Stock Incentive Plan Amended and Restated as of May 24, 2005

UGI Corporation 2009 Deferral Plan As Amended and Restated Effective June 1, 2010

UGI Corporation Senior Executive Employee Severance Plan as in effect as of January 1, 2008

UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan, as Amended and Restated effective January 1, 2009

Amendment 2009-1 to the UGI Corporation Supplemental Executive Retirement Plan and Supplemental Savings Plan as Amended and Restated effective January 1, 2009

UGI Corporation 2009 Supplemental Executive Retirement Plan For New Employees

UGI Corporation Executive Annual Bonus Plan effective as of October 1, 2006

AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., as amended and restated effective January 1, 2005

AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Effective July 30, 2010

AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. — Terms and Conditions

AmeriGas Propane, Inc. Non-Qualified Deferred Compensation Plan, as amended and restated effective January 1, 2009

AmeriGas Propane, Inc. Senior Executive Employee Severance Plan, as in effect January 1, 2008

AmeriGas Propane, Inc. Executive Employee Severance Plan, as in effect January 1, 2008

AmeriGas Propane, Inc. Supplemental Executive Retirement Plan, as Amended and Restated Effective January 1, 2009

AmeriGas Propane, Inc. Executive Annual Bonus Plan, effective as of October 1, 2006

Summary of Antargaz Supplemental Retirement Plans effective as of September 1, 2009

UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for Non Employee Directors, dated January 8, 2010

UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for UGI Employees, dated January 1, 2009

UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for Utilities Employees, dated January 1, 2009

UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 8, 2010

UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2010

UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for AmeriGas Employees, dated January 1, 2010

UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Utilities Employees, dated January 1, 2010

UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Employees, dated January 1, 2010

UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2010

AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., as amended and restated effective January 1, 2005, Restricted Unit Grant Letter dated as of December 31, 2009

Amended and Restated UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Stock Option Grant Letter effective January 1, 2010

Amended and Restated UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Performance Unit Grant Letter effective January 1, 2010

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

Description of oral compensation arrangement for Mr. Bissell

Summary of Director Compensation as of October 1, 2010

Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Messrs. Greenberg, Hall, Kelly, Knauss and Walsh

Form of Change in Control Agreement Amended and Restated as of May 12, 2008 for Mr. Bissell

Form of Confidentiality and Post-Employment Activities Agreement with AmeriGas Propane, Inc. for Mr. Bissell

Trademark License Agreement dated April 19, 1995 among UGI Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P.

Trademark License Agreement, dated April 19, 1995 among AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P.

Credit Agreement, dated as of April 17, 2009, among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as Guarantor, Petrolane Incorporated, as Guarantor, Citizens Bank of Pennsylvania, as Syndication Agent, JPMorgan Chase, N.A., as Documentation Agent and Wachovia Bank, National Association, as Administrative Agent

Amendment No. 1 to Credit Agreement, dated as of July 1, 2010, among the Partnership, as Borrower, AmeriGas Propane, Inc., as Guarantor, Petrolane Incorporated, as Guarantor, Citizens Bank of Pennsylvania, as Syndication Agent, JPMorgan Chase Bank, N.A., as Documentation Agent and Wells Fargo Bank, N.A., as Administrative Agent

Restricted Subsidiary Guarantee by the Restricted Subsidiaries of AmeriGas Propane, L.P., as Guarantors, for the benefit of Wachovia Bank, National Association and the Banks, dated as of April 17, 2009

Credit Agreement dated as of November 6, 2006 among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as Guarantor, Petrolane Incorporated, as Guarantor, Citigroup Global Markets Inc., as Syndication Agent, J.P. Morgan Securities Inc. and Credit Suisse Securities (USA) LLC, as Co-Documentation Agents, Wachovia Bank, National Association, as Agent, Issuing Bank and Swing Line Bank, and the other financial institutions party thereto

Release of Liens and Termination of Security Documents dated as of November 6, 2006 by and among AmeriGas Propane, Inc., Petrolane Incorporated, AmeriGas Propane, L.P., AmeriGas Propane Parts & Service, Inc. and Wachovia Bank, National Association, as Collateral Agent for the Secured Creditors, pursuant to the Intercreditor and Agency Agreement dated as of April 19, 1995

Credit Agreement, dated as of August 11, 2006, among UGI Utilities, Inc., as borrower, and Citibank, N.A., as agent, Wachovia Bank, National Association, as syndication agent, and Citizens Bank of Pennsylvania, Credit Suisse, Cayman Islands Branch, Deutsche Bank AG New York Branch, JPMorgan Chase Bank, N.A., Mellon Bank, N.A., PNC Bank, National Association, and the other financial institutions from time to time parties thereto

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

Purchase and Sale Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 3 thereto dated August 26, 2010, by and between UGI Energy Services, Inc. and Energy Services Funding Corporation

Credit Agreement, dated as of August 26, 2010, among UGI Energy Services, Inc., as borrower, and JPMorgan Chase Bank, N.A., as administrative agent, PNC Bank, National Association, as syndication agent, and Wells Fargo Bank, National Association and Credit Suisse AG, Cayman Islands Branch, as co-documentation agents

Senior Facilities Agreement dated December 7, 2005 by and among AGZ Holding, as Borrower and Guarantor, Antargaz, as Borrower and Guarantor, Calyon, as Mandated Lead Arranger, Facility Agent and Security Agent and the Financial Institutions named therein

Amendment Agreement dated October 6, 2008 to Senior Facilities Agreement dated December 7, 2005 by and among AGZ Holding, Antargaz, Calyon and the Financial Institutions named therein

Pledge of Financial Instruments Account relating to Financial Instruments held by AGZ Holding in Antargaz, dated December 7, 2005, by and among AGZ Holding, as Pledgor, Calyon, as Security Agent, and the Lenders

Pledge of Financial Instruments Account relating to Financial Instruments held by Antargaz in certain subsidiary companies, dated December 7, 2005, by and among Antargaz, as Pledgor, Calyon, as Security Agent, and the Revolving Lenders

Letter of Undertakings dated December 7, 2005, by UGI Bordeaux Holding to AGZ Holding, the Parent of Antargaz, and Calyon, the Facility Agent, acting on behalf of the Lenders, (as defined within the Senior Facilities Agreement)

Security Agreement for the Assignment of Receivables dated as of December 7, 2005 by and among AGZ Holding, as Assignor, Calyon, as Security Agent, and the Lenders named therein

Security Agreement for the Assignment of Receivables dated as of December 7, 2005 by and among Antargaz, as Assignor, Calyon, as Security Agent, and the Lenders named therein

Seller’s Guarantee dated February 16, 2001 among Elf Antar France, Elf Aquitaine and AGZ Holding

AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. Effective July 30, 2010

AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. Effective July 30, 2010 — Terms and Conditions

Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, Inc. effective as of May 1, 2007

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

Firm Storage and Delivery Service Agreement (Rate GSS) dated July 1, 1996 between Transcontinental Gas Pipe Line Corporation and PG Energy

SST Service Agreement No. 79133 dated November 1, 2004 between Columbia Gas Transmission Corporation and UGI Utilities, Inc.

Code of Ethics for principal executive, financial and accounting officers

Subsidiaries of the Registrant

Consent of PricewaterhouseCoopers LLP

Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2010 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2010 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-K for the fiscal year ended September 30, 2010, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

The following materials from UGI Corporation’s Annual Report on Form 10-K for the year ended September 30, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets; (ii) the Consolidated Statements of Income; (iii) the Consolidated Statements of Comprehensive Income; (iv) the Consolidated Statements of Cash Flows; (v) the Consolidated Statements of Changes in Equity; and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text. This Exhibit 101 is deemed not filed for purposes of Section 11 or 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

Filed herewith.

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

SIGNATURES

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

Date: November 19, 2010

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on November 19, 2010, by the following persons on behalf of the Registrant in the capacities indicated.

/s/ Lon R. Greenberg

Lon R. Greenberg

/s/ John L. Walsh

John L. Walsh

/s/ Peter Kelly

Peter Kelly

/s/ Davinder S. Athwal

Davinder S. Athwal

/s/ Stephen D. Ban

Stephen D. Ban

/s/ Richard C. Gozon

Richard C. Gozon

/s/ Ernest E. Jones

Ernest E. Jones

/s/ Anne Pol

Anne Pol

/s/ M. Shawn Puccio

M. Shawn Puccio

/s/ Marvin O. Schlanger

Marvin O. Schlanger

/s/ Roger B. Vincent

Roger B. Vincent

UGI CORPORATION AND SUBSIDIARIES

FINANCIAL INFORMATION

FOR INCLUSION IN ANNUAL REPORT ON FORM 10-K

YEAR ENDED SEPTEMBER 30, 2010

UGI CORPORATION

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

Financial Statement Schedules:

For the years ended September 30, 2010, 2009 and 2008:

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

Report of Management

Financial Statements

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

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

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

Management’s Report on Internal Control over Financial Reporting

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

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

Based on its assessment, management has concluded that the Company’s internal control over financial reporting was effective as of September 30, 2010, based on the COSO Framework. PricewaterhouseCoopers LLP, our independent registered public accounting firm, audited the effectiveness of the Company’s internal control over financial reporting as of September 30, 2010, as stated in their report, which appears herein.

/s/ Lon R. Greenberg
Chief Executive Officer

/s/ Peter Kelly
Chief Financial Officer

/s/ Davinder S. Athwal
Chief Accounting Officer

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of UGI Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, changes in equity and cash flows present fairly, in all material respects, the financial position of UGI Corporation and its subsidiaries at September 30, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15 (a)(2) present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2010 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedules and the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 3 to the consolidated financial statements, the Company adopted new accounting guidance regarding the accounting for and presentation of noncontrolling interests effective October 1, 2009.

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

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

/s/ PricewaterhouseCoopers
Philadelphia, Pennsylvania
November 19, 2010

UGI CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Millions of dollars)

ASSETS

Current assets

Cash and cash equivalents

Restricted cash

Accounts receivable (less allowances for doubtful accounts of $34.6 and $38.3, respectively)

Accrued utility revenues

Inventories

Deferred income taxes

Utility regulatory assets

Derivative financial instruments

Prepaid expenses and other current assets

Total current assets

Property, plant and equipment

Utilities

Non-utility

Accumulated depreciation and amortization

Net property, plant, and equipment

Goodwill

Intangible assets, net

Other assets

Total assets

LIABILITIES AND EQUITY

Current liabilities

Current maturities of long-term debt

Bank loans

Accounts payable

Employee compensation and benefits accrued

Deposits and advances

Other current liabilities

Total current liabilities

Debt and other liabilities

Long-term debt

Deferred investment tax credits

Other noncurrent liabilities

Total liabilities

Commitments and contingencies (note 15)

Equity:

UGI Corporation stockholders’ equity:

UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,400,294 and 115,261,294 shares, respectively)

Retained earnings

Accumulated other comprehensive loss

Treasury stock, at cost

Total UGI Corporation stockholders’ equity

Total equity

Total liabilities and equity

As adjusted in accordance with the transition provisions for accounting for noncontrolling interests in consolidated subsidiaries (Note 3).

See accompanying notes to consolidated financial statements.

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

Non-utility and other

Costs and Expenses

Cost of sales (excluding depreciation shown below):

Utilities

Non-utility and other

Operating and administrative expenses

Utility taxes other than income taxes

Depreciation

Amortization

Other income, net

Loss from equity investees

Interest expense

Income taxes

Net income

Less: net income attributable to noncontrolling interests, principally in AmeriGas Partners

Earnings per common share attributable to UGI Corporation stockholders:

Basic

Diluted

Average common shares outstanding (thousands):

Basic

Diluted

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of dollars)

Net losses on derivative instruments (net of tax of $(29.2), $82.1 and $21.6, respectively)

Reclassifications of net losses (gains) on derivative instruments (net of tax of $(25.3), $(78.6) and $2.1, respectively)

Foreign currency translation adjustments (net of tax of $7.9, $(8.4) and $1.2, respectively)

Benefit plans (net of tax of $12.7, $31.1 and $20.3, respectively)

Reclassification of benefit plans actuarial losses and prior service costs (net of tax of $(2.9), $(1.6) and $(0.1), respectively) to net income

Reclassification of pension plans actuarial losses and prior service costs (net of tax of $(59.1)) to regulatory assets

Cumulative effect from initial adoption of new accounting for uncertain tax positions

Comprehensive income

Less: comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners

Comprehensive income attributable to UGI Corporation

See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)

CASH FLOWS FROM OPERATING ACTIVITIES

Reconcile to net cash provided by operating activities:

Depreciation and amortization

Gains on sales of LPG storage facilities

Deferred income taxes, net

Provision for uncollectible accounts

Stock-based compensation expense

Net change in realized gains and losses deferred as cash flow hedges

Other, net

Net change in:

Accounts receivable and accrued utility revenues

Inventories

Utility deferred fuel costs, net of changes in unsettled derivatives

Accounts payable

Other current assets

Other current liabilities

Net cash provided by operating activities

CASH FLOWS FROM INVESTING ACTIVITIES

Expenditures for property, plant and equipment

Acquisitions of businesses, net of cash acquired

Net proceeds from sale of Partnership LPG storage facility

Net proceeds from sale of Atlantic Energy, LLC

(Increase) decrease in restricted cash

Other, net

Net cash used by investing activities

CASH FLOWS FROM FINANCING ACTIVITIES

Dividends on UGI Common Stock

Distributions on AmeriGas Partners publicly held Common Units

Issuances of debt

Repayments of debt

Increase (decrease) in bank loans

Issuances of UGI Common Stock

Other

Net cash used by financing activities

EFFECT OF EXCHANGE RATE CHANGES ON CASH

Cash and cash equivalents (decrease) increase

Cash and cash equivalents:

End of year

Beginning of year

(Decrease) increase

SUPPLEMENTAL CASH FLOW INFORMATION:

Cash paid for:

Interest

Income taxes

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Millions of dollars, except per share amounts)

Common stock, without par value

Balance, beginning of year

Common Stock issued:

Employee and director plans

Dividend reinvestment plan

Excess tax benefits realized on equity-based compensation

Stock-based compensation expense

Balance, end of year

Retained earnings

Cumulative effect from initial adoption of new accounting for uncertain tax positions

Cash dividends on Common Stock ($0.90, $0.785 and $0.755 per share, respectively)

Accumulated other comprehensive income (loss)

Net losses on derivative instruments, net of tax

Reclassification of net losses (gains) on derivative instruments, net of tax

Benefit plans, principally actuarial losses, net of tax

Reclassification of benefit plans actuarial losses and prior service costs, net of tax, to net income

Reclassifications of pension plans actuarial losses and prior service cost, net of tax, to regulatory assets

Foreign currency translation adjustments, net of tax

Treasury stock

Total UGI Corporation stockholders’ equity

Noncontrolling interests

Net income attributable to noncontrolling interests, principally in AmeriGas Partners

Net gains (losses) on derivative instruments

Reclassification of net (gains) losses on derivative instruments

Dividends and distributions

Total equity

UGI Corporation and Subsidiaries

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

Index to Notes

Note 1 — Nature of Operations

Note 2 — Significant Accounting Policies

Note 3 — Accounting Changes

Note 4 — Acquisitions and Dispositions

Note 5 — Debt

Note 6 — Income Taxes

Note 7 — Employee Retirement Plans

Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters

Note 9 — Inventories

Note 10 — Property, Plant and Equipment

Note 11 — Goodwill and Intangible Assets

Note 12 — Series Preferred Stock

Note 13 — Common Stock and Equity-Based Compensation

Note 14 — Partnership Distributions

Note 15 — Commitments and Contingencies

Note 16 — Fair Value Measurements

Note 17 — Disclosures About Derivative Instruments and Hedging Activities

Note 18 — Energy Services Accounts Receivable Securitization Facility

Note 19 — Other Income, Net

Note 20 — Quarterly Data (unaudited)

Note 21 — Segment Information

Note 1 — Nature of Operations

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

We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”), a publicly traded limited partnership, and its principal operating subsidiaries AmeriGas Propane, L.P. (“AmeriGas OLP”) and AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (together with AmeriGas OLP, the “Operating Partnerships”). AmeriGas Eagle Propane, L.P. merged with and into AmeriGas OLP on October 1, 2010. AmeriGas Partners and the Operating Partnerships are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30, 2010, the General Partner held a 1% general partner interest and 42.8% limited partner interest in AmeriGas Partners and an effective 44.4% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners Common Units (“Common Units”). The remaining 56.2% interest in AmeriGas Partners comprises 32,397,300 Common Units held by the general public as limited partner interests. Effective October 1, 2010, AmeriGas Eagle Propane, L.P. merged with and into AmeriGas OLP.

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

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

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

Note 2 — Significant Accounting Policies

Basis of Presentation

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

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

Certain prior-year amounts have been reclassified to conform to the current-year presentation. As discussed in Note 3, the consolidated financial statements have been adjusted to comply with recently adopted Financial Accounting Standards Board’s (“FASB’s”) accounting guidance regarding the presentation of noncontrolling interests in consolidated financial statements.

Principles of Consolidation

The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the general public’s interests in the Partnership and other parties’ interests in consolidated but less than 100% owned subsidiaries as noncontrolling interests. We eliminate all significant intercompany accounts and transactions when we consolidate. Investments in business entities in which we do not have control, but have significant influence over operating or financial policies, are accounted for under the equity method of accounting and our proportionate share of income or loss is recorded in loss from equity investees on the Consolidated Statements of Income. Undistributed net earnings of our equity investees included in consolidated retained earnings were not material at September 30, 2010. Investments in business entities that are not publicly traded and in which we hold less than 20% of voting rights are accounted for using the cost method. Such investments are recorded in other assets and totaled $68.8 and $55.0 at September 30, 2010 and 2009, respectively.

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

Effects of Regulation

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

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

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity, foreign currency and interest rate derivative instruments. We adopted new accounting guidance with respect to determining fair value measurements effective October 1, 2008. The new guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The new guidance clarifies that fair value should be based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. The new guidance requires fair value measurements to assume that the transaction occurs in the principal market for the asset or liability or in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

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

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

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

Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any derivative financial instruments categorized as Level 3 at September 30, 2010 or 2009.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. The adoption of the new fair value guidance effective October 1, 2008 did not have a material impact on our financial statements. See Note 16 for additional information on fair value measurements.

Derivative Instruments

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

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

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

Foreign Currency Translation

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

Revenue Recognition

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

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

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

LPG Delivery Expenses

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

Income Taxes

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

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

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

We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income. For Fiscal 2010, Fiscal 2009 and Fiscal 2008, interest (income) expense of $(0.2), $(0.4) and $0.2, respectively, was recognized in income taxes in the Consolidated Statements of Income.

Effective October 1, 2007, we adopted new interpretive guidance issued by the FASB on accounting for uncertainty related to income taxes. The cumulative effect from the adoption of the new guidance was recorded as a $1.2 decrease to the October 1, 2007 retained earnings.

Earnings Per Common Share

Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2010, Fiscal 2009 and Fiscal 2008:

Average common shares outstanding for basic computation

Incremental shares issuable for stock options and common stock awards

Average common shares outstanding for diluted computation

Comprehensive Income

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

The components of AOCI at September 30, 2010 and 2009 follow:

Balance, September 30, 2010

Balance, September 30, 2009

Cash and Cash Equivalents

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

Restricted Cash

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

Inventories

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

Property, Plant and Equipment and Related Depreciation

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

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

We record depreciation expense for Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. Depreciation expense as a percentage of the related average depreciable base for Gas Utility was 2.5% in Fiscal 2010, and 2.4% in Fiscal 2009 and Fiscal 2008. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.6% in Fiscal 2010, 2.9% in Fiscal 2009 and 2.6% in Fiscal 2008. When Utilities retire depreciable utility plant and equipment, we charge the original cost, net of removal costs and salvage value, to accumulated depreciation for financial accounting purposes.

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

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

Goodwill and Intangible Assets

In accordance with GAAP relating to goodwill and other intangibles, we amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. Goodwill and other intangible assets with indefinite lives are not amortized but are subject to tests for impairment at least annually. We perform impairment tests more frequently than annually if events or circumstances indicate that the value of goodwill or intangible assets with indefinite lives might be impaired. When performing our impairment tests, we use quoted market prices or, in the absence of quoted market prices, discounted estimates of future cash flows. No provisions for goodwill or other intangible asset impairments were recorded during Fiscal 2010, Fiscal 2009 or Fiscal 2008.

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

Impairment of Long-Lived Assets

We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No provisions for impairments were recorded during Fiscal 2010, Fiscal 2009 or Fiscal 2008.

Refundable Tank and Cylinder Deposits

Included in “Other noncurrent liabilities” on our Consolidated Balance Sheets are customer paid deposits on Antargaz owned tanks and cylinders of $211.8 and $230.3 at September 30, 2010 and 2009, respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms.

Environmental Matters

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

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

Employee Retirement Plans

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

Equity-Based Compensation

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

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

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

Note 3 — Accounting Changes

Adoption of New Accounting Standards

Noncontrolling Interests. Effective October 1, 2009, we adopted new guidance regarding the accounting for and presentation of noncontrolling interests in consolidated financial statements. The new guidance changed the accounting and reporting relating to noncontrolling interests in a consolidated subsidiary. Noncontrolling interests are now classified within equity on the Consolidated Balance Sheets, a change from their prior classification between liabilities and stockholders’ equity. Earnings (losses) attributable to noncontrolling interests are now included in net income (loss) and deducted from net income (loss) to determine net income (loss) attributable to UGI Corporation. In addition, changes in a parent’s ownership interest while retaining control are accounted for as equity transactions and any retained noncontrolling equity investments in a former subsidiary are initially measured at fair value. In accordance with the new guidance, previous periods have been adjusted to conform to the new presentation.

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

Intangible Asset Useful Lives. Effective October 1, 2009, we adopted new accounting guidance which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under GAAP. The intent of the new guidance is to improve the consistency between the useful life of a recognized intangible asset under GAAP relating to intangible asset accounting and the period of expected cash flows used to measure the fair value of the asset under GAAP relating to business combinations and other applicable accounting literature. The new guidance must be applied prospectively to intangible assets acquired after the effective date. The adoption of the new guidance did not impact our financial statements.

Enhanced Disclosures of Postretirement Plan Assets. Effective September 30, 2010, we adopted accounting guidance requiring more detailed disclosures about employers’ postretirement plan assets, including employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets, and valuation techniques used to measure the fair value of plan assets. Because this new guidance relates to disclosures only, it did not impact the financial statements. The enhanced disclosures are presented in Note 7.

Fair Value Measurements. In January 2010, the FASB issued new guidance with respect to fair value measurements disclosures. The new guidance requires additional disclosure related to transfers between Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements related to Level 3. The new guidance clarifies existing disclosure guidance about inputs and valuation techniques for fair value measurements and levels of disaggregation. We apply fair value measurements to certain assets and liabilities, principally commodity, foreign currency and interest rate derivative instruments. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009 except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2009 (Fiscal 2011) and interim periods thereafter. The adoption of the new guidance that became effective during Fiscal 2010 did not have a material effect on our disclosures. See Notes 2 and 16 for further information on fair value measurements.

New Accounting Standards Not Yet Adopted

Transfers of Financial Assets. In June 2009, the FASB issued new guidance regarding accounting for transfers of financial assets. Among other things, the new guidance eliminates the concept of Qualified Special Purpose Entities (“QSPEs”). It also amends previous derecognition guidance. The new guidance is effective for financial asset transfers occurring after the beginning of an entity’s fiscal year that begins after November 15, 2009 (Fiscal 2011). The adoption of the new accounting guidance will change the accounting for transfers of accounts receivable to a commercial paper conduit of a major bank under the Energy Services Receivables Facility (see Note 18). 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. Under current accounting guidance, trade accounts receivable sold to the commercial paper conduit are removed from the balance sheet. Additionally, the Company will record interest expense on amounts owed to the commercial paper conduit. Currently, losses on sales of accounts receivable are reflected in other income, net.

Note 4 — Acquisitions & Dispositions

During Fiscal 2010, AmeriGas OLP acquired a number of domestic retail propane distribution businesses for $34.3 cash, and our International Propane operations acquired propane distribution businesses in Denmark, Hungary and Switzerland, and an additional 46% interest in our retail business in China, for total cash consideration of $48.7. During Fiscal 2009, AmeriGas OLP, in addition to the acquisition of the assets of CPP described below, acquired several retail propane distribution businesses for total cash consideration of $17.9 and Flaga acquired the 50% of ZLH it did not already own for $18.2. During Fiscal 2008, AmeriGas OLP acquired several retail propane distribution businesses for total cash consideration of $2.5.

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

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

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

Current assets less current liabilities

Utility regulatory assets

Noncurrent liabilities

The goodwill above is primarily the result of synergies between the acquired businesses and our existing utility and propane businesses. Substantially all of the goodwill is deductible for income tax purposes over a fifteen-year period.

The operating results of CPG and CPP are included in our consolidated results beginning October 1, 2008. The following table presents pro forma income statement and basic and diluted per share data for Fiscal 2008 as if the CPG Acquisition had occurred as of October 1, 2007:

Earnings per share:

The pro forma results of operations reflect CPG’s and CPP’s historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The pro forma amounts are not necessarily indicative of the operating results that would have occurred had the CPG Acquisition been completed as of the date indicated, nor are they necessarily indicative of future operating results.

On July 30, 2010, Energy Services sold all of its interest in its second-tier, wholly owned subsidiary Atlantic Energy, LLC (“Atlantic Energy”) to DCP Midstream Partners, L.P. for $49.0 in cash plus an amount for inventory and other working capital. Atlantic Energy owns and operates a 20 million gallon marine import and transshipment facility located in the port of Chesapeake, Virginia. The Company recorded a $36.5 pre-tax gain on the sale which amount is included in “Other income, net” in the Fiscal 2010 Consolidated Statement of Income. The gain increased Fiscal 2010 net income attributable to UGI Corporation by $17.2 or $0.16 per diluted share. Atlantic Energy’s income from operations was not material in Fiscal 2010, 2009 and 2008.

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

Note 5 — Debt

Long-term debt comprises the following at September 30:

AmeriGas Propane:

AmeriGas Partners Senior Notes:

8.875% Note, due May 2011

7.25% Note, due May 2015

7.125% Note, due May 2016

AmeriGas OLP Series E First Mortgage

Notes, 8.5%, due July 2010

Total AmeriGas Propane

International Propane:

Antargaz Senior Facilities term loan, due March 2011

Flaga term loan, due through September 2011

Flaga term loan, due through June 2014

Total International Propane

UGI Utilities:

Senior Notes:

6.375% Notes, due September 2013

5.75% Notes, due October 2016

6.21% Notes, due October 2036

Medium- Term Notes:

5.53% Notes, due September 2012

5.37% Notes, due August 2013

5.16% Notes, due May 2015

7.37% Notes, due October 2015

5.64% Notes, due December 2015

6.17% Notes, due June 2017

7.25% Notes, due November 2017

5.67% Notes, due January 2018

6.50% Notes, due August 2033

6.13% Notes, due October 2034

Total UGI Utilities

Total long-term debt

Less: current maturities

Total long-term debt due after one year

Scheduled principal repayments of long-term debt due in fiscal years 2011 to 2015 follow:

AmeriGas Propane

AmeriGas Partners Senior Notes. The 8.875% and 7.25% Senior Notes may be redeemed at our option. The 7.125% Senior Notes generally cannot be redeemed at our option prior to May 20, 2011. AmeriGas Partners may, under certain circumstances involving excess sales proceeds from the disposition of assets not reinvested in the business or a change of control, be required to offer to prepay its 7.25% and 7.125% Senior Notes.

AmeriGas OLP Credit Agreements. AmeriGas OLP has an unsecured credit agreement (“AmeriGas Credit Agreement”) consisting of (1) a Revolving Credit Facility and (2) an Acquisition Facility. AmeriGas OLP also has a $75 unsecured revolving credit facility (“2009 AmeriGas Supplemental Credit Agreement”). The General Partner and Petrolane Incorporated, a wholly owned subsidiary of the General Partner, are guarantors of amounts outstanding under the AmeriGas Credit Agreement and the 2009 AmeriGas Supplemental Credit Agreement.

Under the Revolving Credit Facility, AmeriGas OLP may borrow up to $125 (including a $100 sublimit for letters of credit) which is subject to restrictions in the Senior Notes indentures (see “Restrictive Covenants” below). The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The Revolving Credit Facility expires on October 15, 2011, but may be extended for additional one-year periods with the consent of the participating banks representing at least 80% of the commitments thereunder. The AmeriGas Credit Agreement Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 to finance the purchase of propane businesses or propane business assets or, to the extent it is not so used, for working capital and general purposes, subject to restrictions in the Senior Notes indentures. The AmeriGas Credit Agreement Acquisition Facility operates as a revolving facility through October 15, 2011, at which time amounts then outstanding will be immediately due and payable. At September 30, 2010, there was $56 of borrowings outstanding under the Revolving Credit Facility and $35 outstanding under the Acquisition Facility which amounts are reflected as “Bank loans” on the Consolidated Balance Sheet. The weighted-average interest rate on AmeriGas Credit Agreement borrowings at September 30, 2010 was 1.31%. There were no AmeriGas Credit Agreement borrowings at September 30, 2009. Issued and outstanding letters of credit, which reduce available borrowings under the Credit Agreement Revolving Credit Facility, totaled $35.7 and $37.0 at September 30, 2010 and 2009, respectively.

The AmeriGas Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate (3.25% at September 30, 2010), or at a two-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Credit Agreement, plus a margin. The margin on Eurodollar Rate borrowings (which ranges from 1.00% to 1.75%) and the AmeriGas Credit Agreement facility fee rate (which ranges from 0.25% to 0.375%) are dependent upon AmeriGas OLP’s ratio of funded debt to earnings before interest expense, income taxes, depreciation and amortization (“EBITDA”), each as defined in the AmeriGas Credit Agreement.

The 2009 AmeriGas Supplemental Credit Agreement expires on June 30, 2011 and permits AmeriGas OLP to borrow up to $75 for working capital and general purposes subject to restrictive covenants in the Senior Notes indentures. The 2009 AmeriGas Supplemental Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate equal to the higher of the Federal Funds rate plus 0.50%, the agent bank’s prime rate (3.25% at September 30, 2010), or a libor market index rate (0.26% at September 30, 2010) plus 1%, or at a one-week, two-week or one-month Eurodollar rate, as defined in the 2009 AmeriGas Supplemental Credit Agreement, plus a margin. The margin on base rate loans is 2.00% and the margin on Eurodollar loans is 3.00%. There were no amounts outstanding under the 2009 AmeriGas Supplemental Credit Agreement at September 30, 2010 and 2009.

Restrictive Covenants. The 7.25% and 7.125% Senior Notes of AmeriGas Partners restrict the ability of the Partnership and AmeriGas OLP to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets. Under the 7.25% and 7.125% Senior Note Indentures, AmeriGas Partners is generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. At September 30, 2010, these restrictions did not limit the amount of Available Cash AmeriGas Partners could distribute pursuant to the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P. (“Partnership Agreement”) (see Note 14).

The AmeriGas OLP credit agreements restrict the incurrence of additional indebtedness and also restrict certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas OLP credit agreements require that AmeriGas OLP not exceed a ratio of total indebtedness, as defined, to EBITDA, as defined; maintain a minimum ratio of EBITDA to interest expense, as defined; and maintain a minimum EBITDA. Generally, as long as no default exists or would result, the Partnership and AmeriGas OLP are permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter.

International Propane

Antargaz has a Senior Facilities Agreement with a bank group that expires on March 31, 2011. The Senior Facilities Agreement consists of (1) a €380 variable-rate term loan and a €50 revolving credit facility. The Senior Facilities Agreement also provides Antargaz a €50 letter of credit guarantee facility. Antargaz’ term loan and revolving credit facility bear interest at one-, two-, three- or six-month euribor or libor, plus a margin, as defined by the Senior Facilities Agreement. Antargaz has executed interest rate swap agreements with a member of the same bank group to fix the underlying euribor or libor rate of interest on the term loan at approximately 3.25% for the duration of the loan (see Note 17). The effective interest rates on Antargaz’ term loan at September 30, 2010 and 2009 was 3.94%. Antargaz’ revolving credit facility permits Antargaz to borrow up to €50 for working capital or general corporate purposes. In order to minimize the interest margin it pays on its Senior Facilities Agreement borrowings, in September 2010 Antargaz borrowed €50 ($68.2), the total amount available under its revolving credit facility, which amount remained outstanding at September 30, 2010. This amount was repaid in October 2010. There were no amounts outstanding under the revolving credit facility at September 30, 2009. The margin on the term loan and revolving credit facility borrowings (which ranges from 0.70% to 1.15%) is dependent upon Antargaz’ ratio of total net debt (excluding bank loans) to EBITDA, each as defined by the Senior Facilities Agreement. The Senior Facilities Agreement debt is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivable.

At September 30, 2010, Flaga had two euro-based variable-rate term loans. The principal outstanding on the first term loan was €24 ($32.7) and €30 ($43.9) at September 30, 2010 and 2009, respectively. This first term loan bears interest at one- to twelve-month euribor rates (as chosen by Flaga from time to time) plus a margin. The margin on such borrowings ranges from 0.52% to 1.45% and is based upon certain equity, return on assets and debt to EBITDA ratios as determined on a UGI consolidated basis. Principal payments totaling €3.0, €6.4 and €14.6 are due in March, August and September 2011, respectively. 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 rates on this term loan at September 30, 2010 and 2009 were 4.21% and 4.28%, respectively. Flaga may prepay this term loan, in whole or in part, without incurring any penalty.

Flaga’s second euro-based variable-rate term loan had an outstanding principal balance of €5.6 ($7.6) and €7.0 ($10.2) on September 30, 2010 and 2009, respectively. This term loan matures in June 2014 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 2.625% to 3.50% and is based upon certain equity, return on assets and debt to EBITDA ratios as determined on a UGI consolidated basis. Semi-annual principal payments of €0.7 are due on December 31 and June 30 each year through June 2014. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 2.16% by entering into an interest rate swap agreement. The effective interest rate on this term loan at September 30, 2010 and 2009 was 5.03%.

Flaga has two working capital facilities totaling €24. Flaga has a multi-currency working capital facility currently scheduled to expire in June 2011 that provides for borrowings and issuances of guarantees totaling €16 of which €9.8 ($13.4) and €2.1 ($3.0) was outstanding at September 30, 2010 and 2009, respectively. Flaga also has an €8 euro-denominated working capital facility currently scheduled to expire in June 2011 of which €7.9 ($10.8) and €4.1 ($6.1) was outstanding at September 30, 2010 and 2009, respectively. Issued and outstanding guarantees, which reduce available borrowings under the working capital facilities, totaled €5.4 ($7.4) at September 30, 2010 and €2.7 ($3.9) at September 30, 2009. Amounts outstanding under the working capital facilities are classified as bank loans. Borrowings under the working capital facilities generally bear interest at market rates (a daily euro-based rate or three-month euribor rates) plus a margin. The weighted-average interest rates on Flaga’s working capital loans were 2.91% at September 30, 2010 and 4.94% at September 30, 2009. In order to provide for additional borrowing capacity, in November 2010 Flaga entered into an additional €8 multi-currency working capital facility and an additional €4 euro-denominated working capital facility both of which expire in June 2011.

Restrictive Covenants and Guarantees. The Senior Facilities Agreement restricts the ability of Antargaz, to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets. Under this agreement, Antargaz is generally permitted to make restricted payments, such as dividends, if the ratio of net debt to EBITDA on a French generally accepted accounting basis, as defined in the agreement, is less than 3.75 to 1.00 and if no event of default exists or would exist upon payment of such restricted payment.

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

Revolving Credit Agreement. UGI Utilities has a revolving credit agreement (“UGI Utilities Revolving Credit Agreement”) with a group of banks providing for borrowings of up to $350 which expires in August 2011. Under the UGI Utilities Revolving Credit Agreement, UGI Utilities may borrow at various prevailing interest rates, including LIBOR and the banks’ prime rate. UGI Utilities had borrowings outstanding under the UGI Utilities Revolving Credit Agreement, which we classify as bank loans, totaling $17 at September 30, 2010 and $154 at September 30, 2009. The weighted-average interest rates on UGI Utilities’ Revolving Credit Agreement borrowings at September 30, 2010 and 2009 were 3.25% and 0.59%, respectively. The higher rate at September 30, 2010 is the result of a prime rate borrowing compared to LIBOR borrowings at September 30, 2009.

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

Energy Services

Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings up to $170 (including a $50 sublimit for letters of credit) which expires in August 2013. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries. In addition, Energy Services may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement, does not exceed 2.00 to 1.00.

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

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

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

Restricted Net Assets

At September 30, 2010, the amount of net assets of UGI’s consolidated subsidiaries that was restricted from transfer to UGI under debt agreements, subsidiary partnership agreements and regulatory requirements under foreign laws totaled approximately $1,500.

Note 6 — Income Taxes

Income before income taxes comprises the following:

Domestic

Foreign

Total income before income taxes

The provisions for income taxes consist of the following:

Current expense:

Federal

State

Foreign

Investment tax credit

Total current expense

Deferred expense (benefit):

Investment tax credit amortization

Total deferred expense (benefit)

Total income tax expense

Federal income taxes for Fiscal 2010, Fiscal 2009 and Fiscal 2008 are net of foreign tax credits of $2.1, $34.9 and $4.3, respectively.

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

U.S. federal statutory tax rate

Difference in tax rate due to:

Noncontrolling interests not subject to tax

State income taxes, net of federal benefit

Effects of international operations

Effective tax rate

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

Excess book basis over tax basis of property, plant and equipment

Investment in AmeriGas Partners

Intangible assets and goodwill

Foreign currency translation adjustment

Gross deferred tax liabilities

Pension plan liabilities

Employee-related benefits

Operating loss carryforwards

Foreign tax credit carryforwards

Utility regulatory liabilities

Derivative financial instruments

Gross deferred tax assets

Deferred tax assets valuation allowance

Net deferred tax liabilities

At September 30, 2010, foreign net operating loss carryforwards principally relating to Flaga and certain operations of Antargaz totaled $32.9 and $5.5, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries which approximate $150.2 and expire through 2030. We also have operating loss carryforwards of $5.1 for certain operations of AmeriGas Propane that expire through 2029. At September 30, 2010, deferred tax assets relating to operating loss carryforwards include $7.4 for Flaga, $1.9 for Antargaz, $1.0 for UGI International Holdings (BV), $1.8 for AmeriGas Propane and $13.4 for certain other subsidiaries. A valuation allowance of $14.2 has been provided for deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries because, on a state reportable basis, it is more likely than not that these assets will expire unused. A valuation allowance of $2.9 was also provided for deferred tax assets related to certain operations of Antargaz and UGI International Holdings, B.V. Operating activities and tax deductions related to the exercise of non-qualified stock options contributed to the state net operating losses disclosed above. We first recognize the utilization of state net operating losses from operations (which exclude the impact of tax deductions for exercises of non-qualified stock options) to reduce income tax expense. Then, to the extent state net operating loss carryforwards, if realized, relate to non-qualified stock option deductions, the resulting benefits will be credited to UGI Corporation stockholders’ equity.

We have foreign tax credit carryforwards of approximately $61.3 expiring through 2021 resulting from the actual and planned repatriation of Antargaz’ accumulated earnings since acquisition which are includable in U.S. taxable income. Because we expect that these credits will expire unused, a valuation allowance has been provided for the entire foreign tax credit carryforward amount. The valuation allowance for all deferred tax assets decreased by $8.3 in Fiscal 2010 due primarily to a decrease in the foreign tax credit carryforwards of $8.3.

We conduct business and file tax returns in the U.S., numerous states, local jurisdictions and in France and certain central and eastern European countries. Our U.S. federal income tax returns are settled through the 2007 tax year and our French tax returns are settled through the 2005 tax year. Our Austrian tax returns are settled through 2007 and our other central and eastern European tax returns are effectively settled for various years from 2004 to 2009. UGI Corporation’s federal income tax return for Fiscal 2008 is currently under audit. Although it is not possible to predict with certainty the timing of the conclusion of the pending U.S. federal tax audit in progress, we anticipate that the Internal Revenue Service’s (“IRS’s”) audit of our Fiscal 2008 U.S. federal income tax return will likely be completed during Fiscal 2011. State and other income tax returns in the U.S. are generally subject to examination for a period of three to five years after the filing of the respective returns.

As of September 30, 2010, we have unrecognized income tax benefits totaling $5.4 including related accrued interest of $0.1. If these unrecognized tax benefits were subsequently recognized, $1.5 would be recorded as a benefit to income taxes on the consolidated statement of income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. The amount of reasonably possible changes in unrecognized tax benefits and related interest in the next twelve months is a net reduction of approximately $0.5.

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

Balance at October 1, 2007

Additions for tax positions of the current year

Additions for tax positions of prior years

Settlements with tax authorities

Balance at September 30, 2008

Reductions as a result of tax positions taken in prior years

Balance at September 30, 2009

Balance at September 30, 2010

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

Note 7 — Employee Retirement Plans

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

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the Pension Plans and the Antargaz pension plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets, and the funded status of the pension and other postretirement plans as of September 30, 2010 and 2009. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation.

Change in benefit obligations:

Benefit obligations — beginning of year

Service cost

Interest cost

Actuarial loss

Acquisitions

Plan amendments

Plan settlements

Foreign currency

Benefits paid

Benefit obligations — end of year

Change in plan assets:

Fair value of plan assets — beginning of year

Actual gain on plan assets

Employer contributions

Settlement payments

Fair value of plan assets — end of year

Funded status of the plans — end of year

Assets (liabilities) recorded in the balance sheet:

Unfunded liabilities — included in other current liabilities

Unfunded liabilities — included in other noncurrent liabilities

Net amount recognized

Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):

Prior service (credit) cost

Net actuarial loss (gain)

Amounts recorded in regulatory assets and liabilities (pre-tax):

Prior service cost (credit)

Net actuarial loss

In Fiscal 2011, we estimate that we will amortize $9.2 of net actuarial losses and $0.4 of prior service credits from UGI stockholders’ equity and regulatory assets into retiree benefit cost.

Actuarial assumptions for our domestic plans are described below. Assumptions for the Antargaz plans are based upon market conditions in France. The discount rates at September 30 are used to measure the year-end benefit obligations and the earnings effects for the subsequent year. The discount rate is based upon market-observed yields for high-quality fixed income securities with maturities that correlate to the anticipated payment of benefits. The expected rate of return on assets assumption is based on the current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below).

Weighted-average assumptions:

Discount rate

Expected return on plan assets

Rate of increase in salary levels

The ABO for the Pension Plans was $417.8 and $377.7 as of September 30, 2010 and 2009, respectively.

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

Service cost

Interest cost

Expected return on assets

Curtailment gain

Settlement loss

Amortization of:

Transition obligation

Prior service benefit

Actuarial loss (gain)

Net benefit cost (income)

Change in associated regulatory liabilities

Net benefit cost after change in regulatory liabilities

Pension Plans’ assets are held in trust. It is our general policy to fund amounts for pension benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2010, we made cash contributions of $3.4 to the Pension Plans. We did not make any contributions to the Pension Plans in Fiscal 2009 or Fiscal 2008. In conjunction with the settlement of obligations under a subsidiary retirement benefit plan, Antargaz made a settlement payment of €4.1 ($5.7) during Fiscal 2009. We believe that we will be required to make contributions to the Pension Plans in Fiscal 2011 of approximately $20.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs determined under GAAP. The difference between such amounts and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. The required contributions to the VEBA during Fiscal 2011 are not expected to be material.

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

Fiscal 2011

Fiscal 2012

Fiscal 2013

Fiscal 2014

Fiscal 2015

Fiscal 2016 – 2020

The assumed domestic health care cost trend rates are 7.5% for Fiscal 2011, decreasing to 5.0% in Fiscal 2016. A one percentage point change in the assumed health care cost trend rate would increase (decrease) the Fiscal 2010 postretirement benefit cost and obligation as follows:

Service and interest costs in Fiscal 2010

ABO at September 30, 2010

We also sponsor unfunded and non-qualified supplemental executive retirement plans. At September 30, 2010 and 2009, the PBOs of these plans were $23.9 and $20.7, respectively. We recorded net costs for these plans of $2.6 in Fiscal 2010, $3.1 in Fiscal 2009 and $3.0 in Fiscal 2008. These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $4.7 and $4.2 at September 30, 2010 and 2009, respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $0.5 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2011.

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

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

Equity investments:

Domestic

International

Total

Fixed income funds & cash equivalents

Total

VEBA

Domestic equity investments

Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and actively managed mid- and small-cap mutual funds. Investments in international equity mutual funds are indexed to various Morgan Stanley Composite indices. The fixed income investments comprise investments designed to match the duration of the Barclays Capital Aggregate Bond Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 8.3% and 7.5% of Pension Plans assets at September 30, 2010 and 2009, respectively. At September 30, 2010, there were no significant concentrations of risk (defined as greater than 10% of the fair value of total assets) associated with any individual company, industry sector or international geographic region.

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

The fair values of the Pension Plans’ assets at September 30, 2010 and 2009 by asset class are as follows:

September 30, 2010:

Fixed income

Cash equivalents

September 30, 2009:

The fair values of the VEBA trust assets at September 30, 2010 and 2009 by asset class are as follows:

Domestic equity

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

Defined Contribution Plans. We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for employer matching contributions at various rates. The cost of benefits under the savings plans totaled $9.8 in Fiscal 2010, $10.1 in Fiscal 2009 and $9.4 in Fiscal 2008.

Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters

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

Regulatory assets:

Income taxes recoverable

Underfunded pension and postretirement plans

Environmental costs

Deferred fuel and power costs

Total regulatory assets

Regulatory liabilities:

Postretirement benefits

Environmental overcollections

Deferred fuel and power refunds

State tax benefits — distribution system repairs

Total regulatory liabilities

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

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

Based upon the FASB’s guidance 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 (see “Other Regulatory Matters” below), effective September 30, 2010, UGI Utilities recorded a regulatory asset for the amounts associated with regulated operations that would otherwise be recorded in AOCI under ASC 715, “Compensation — Retirement Benefits.” Based upon established rate treatment, CPG historically has recorded regulatory assets associated with its underfunded pension and other postretirement plans.

Environmental costs. Environmental costs represents amounts actually spent by UGI Gas to clean up sites in Pennsylvania as well as the portion of estimated probable future environmental remediation and investigation costs principally at manufactured gas plant (“MGP”) sites that CPG Gas and PNG Gas expect to incur in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection (see Note 15). UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of prudently incurred remediation costs at Pennsylvania sites. PNG Gas and CPG Gas are currently recovering and expect to continue to recover environmental remediation and investigation costs in base rate revenues. At September 30, 2010, the period over which PNG Gas and CPG Gas expect to recover these costs will depend upon future remediation activity.

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

Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Net unrealized losses on such contracts at September 30, 2010 were $1.4. There were no such unrealized gains or losses at September 30, 2009.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. As more fully described in Note 17 to Consolidated Financial Statements, during Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value, with an associated adjustment to regulatory assets or liabilities in accordance with ASC 980 and Electric Utility’s DS procurement, implementation and contingency plans (as further described below). At September 30, 2010, the fair values of Electric Utility’s electricity supply contracts was a loss of $19.7 which amount is reflected in current derivative financial instruments and other noncurrent liabilities on the September 30, 2010 Consolidated Balance Sheet with an equal and offsetting amount reflected in deferred fuel and power costs in the table above.

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

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

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

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

Other. Other regulatory assets comprise a number of items including, among others, deferred postretirement costs, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2010, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 years.

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

Other Regulatory Matters

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

Electric Utility. As a result of Pennsylvania’s Electricity Generation Customer Choice and Competition Act that became effective January 1, 1997, all of Electric Utility’s customers are permitted to acquire their electricity from entities other than Electric Utility. Electric Utility remains the DS 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. These plans did not affect Electric Utility’s existing POLR settlement effective through December 31, 2009. 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. 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 provider of last resort (“POLR”) service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006. In accordance with the POLR Settlement, Electric Utility could increase its POLR rates up to certain limits through December 31, 2009. 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 AOCI under 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 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 as of September 30, 2010.

Note 9 — Inventories

Inventories comprise the following at September 30:

Non-utility LPG and natural gas

Gas Utility natural gas

Materials, supplies and other

Total inventories

At September 30, 2010, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”) two of which expire in October 2012 and one of which expires in October 2010. Pursuant to these and predecessor SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above. The carrying value of gas storage inventories released under the SCAAs to non-affiliates at September 30, 2010 and 2009 comprising 8.0 billion cubic feet (“bcf”) and 1.3 bcf of natural gas was $41.9 and $10.5, respectively. Effective November 1, 2010, UGI Utilities entered into a new SCAA having a term of three years.

Note 10 — Property, Plant and Equipment

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

Utilities:

Distribution

Transmission

General and other, including work in process

Total Utilities

Non-utility:

Land

Buildings and improvements

Transportation equipment

Equipment, primarily cylinders and tanks

Electric generation

Other, including work in process

Total non-utility

Total property, plant and equipment

Note 11 — Goodwill and Intangible Assets

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

Goodwill (not subject to amortization)

Other intangible assets:

Customer relationships, noncompete agreements and other

Trademark (not subject to amortization)

Gross carrying amount

Accumulated amortization

Net carrying amount

Changes in the carrying amount of goodwill are as follows:

Balance September 30, 2008

Goodwill acquired

Purchase accounting adjustments

Foreign currency translation

Balance September 30, 2009

Dispositions

Balance September 30, 2010

We amortize customer relationships and noncompete agreement intangibles over their estimated periods of benefit which do not exceed 15 years. Amortization expense of intangible assets was $19.9 in Fiscal 2010, $18.4 in Fiscal 2009 and $18.8 in Fiscal 2008. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2011 — $20.0; Fiscal 2012 — $20.5; Fiscal 2013 — $20.3; Fiscal 2014 — $19.3; Fiscal 2015 — $14.5. There were no accumulated impairment losses at September 30, 2010.

Note 12 — Series Preferred Stock

UGI has 10,000,000 shares of UGI Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2010 or 2009.

UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. At September 30, 2010 and 2009, there were no shares of UGI Utilities Series Preferred Stock outstanding.

Note 13 — Common Stock and Equity-Based Compensation

UGI Common Stock share activity for Fiscal 2008, Fiscal 2009 and Fiscal 2010 follows:

Balance, September 30, 2007

Issued:

Employee and director plans

Dividend reinvestment plan

Balance, September 30, 2008

Equity-Based Compensation

The Company grants equity-based awards to employees and non-employee directors comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners Common Unit-based equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $13.2 ($8.7 after-tax), $17.6 ($11.4 after-tax) and $11.8 ($7.7 after-tax) in Fiscal 2010, Fiscal 2009 and Fiscal 2008, respectively.

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

Under the OECP, awards representing up to 15,000,000 shares of UGI Common Stock may be granted. The maximum number of shares that may be issued pursuant to grants other than stock options or SARs is 3,200,000. Dividend equivalents on UGI Unit awards to employees will be paid in cash. Dividend equivalents on non-employee director awards are accumulated in additional Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of Common Stock and cash. UGI Unit awards granted to Antargaz employees are settled in shares of Common Stock. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance goals and service conditions. It is our practice to issue treasury shares to satisfy substantially all option exercises and UGI Unit awards. We do not expect to repurchase shares for such purposes during Fiscal 2011.

In June 2008, the Company cancelled and regranted UGI Unit awards and UGI stock option awards previously granted to certain key employees of Antargaz. The cancellation and regrants did not affect the number of UGI Units or stock options awarded and we did not record any incremental expense as a result of these cancellations and regrants.

UGI Stock Option Awards. Stock option transactions under the OECP and predecessor plans for Fiscal 2008, Fiscal 2009 and Fiscal 2010 follow:

Shares under option — September 30, 2007

Granted

Cancelled

Exercised

Shares under option — September 30, 2008

Shares under option — September 30, 2009

Shares under option — September 30, 2010

Options exercisable — September 30, 2008

Options exercisable — September 30, 2009

Options exercisable — September 30, 2010

Non-vested options — September 30, 2010

Cash received from stock option exercises and associated tax benefits were $23.1 and $4.3, $6.3 and $2.2, and $15.4 and $3.7 in Fiscal 2010, Fiscal 2009 and Fiscal 2008, respectively. As of September 30, 2010, there was $3.6 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 1.8 years.

The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2010:

Options outstanding at September 30, 2010:

Number of options

Weighted average remaining contractual life (in years)

Weighted average exercise price

Options exercisable at September 30, 2010:

UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $4.49 in Fiscal 2010, $4.13 in Fiscal 2009 and $5.06 in Fiscal 2008. These amounts were determined using a Black-Scholes option pricing model which values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, expected dividend payments and the risk-free interest rate over the expected life of the option. The expected life of option awards represents the period of time during which option grants are expected to be outstanding and is derived from historical exercise patterns. Expected volatility is based on historical volatility of the price of UGI’s Common Stock. Expected dividend yield is based on historical UGI dividend rates. The risk free interest rate is based on U.S. Treasury bonds with terms comparable to the options in effect on the date of grant.

The assumptions we used for valuing option grants during Fiscal 2010, Fiscal 2009 and Fiscal 2008 are as follows:

Expected life of option

Weighted average volatility

Weighted average dividend yield

Expected volatility

Expected dividend yield

Risk free rate

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

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

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

Expected life

Dividend yield

The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $22.51 for Units granted in Fiscal 2010, $27.91 for Units granted in Fiscal 2009 and $29.70 for Units granted in Fiscal 2008.

The following table summarizes UGI Unit award activity for Fiscal 2010:

September 30, 2009

UGI Performance Units:

Granted

Forfeited

Vested

Unit awards paid

Performance criteria not met

UGI Stock Units:

Granted(a)

September 30, 2010

Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2009 and Fiscal 2008 were 52,767 and 37,732, respectively.

During Fiscal 2010, Fiscal 2009 and Fiscal 2008, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:

UGI Performance Unit awards:

Number of original awards granted

Fiscal year granted

Payment of awards:

Shares of UGI Common Stock issued

Cash paid

UGI Stock Unit awards:

During Fiscal 2010, Fiscal 2009 and Fiscal 2008, we granted UGI Unit awards representing 231,710, 269,017 and 253,325 shares, respectively, having weighted-average grant date fair values per Unit of $22.69, $27.26 and $29.34, respectively.

As of September 30, 2010, there was a total of approximately $5.1 of unrecognized compensation cost associated with 930,493 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.8 years. The total fair values of UGI Units that vested during Fiscal 2010, Fiscal 2009, and Fiscal 2008 were $5.0, $7.6 and $7.1, respectively. As of September 30, 2010 and 2009, total liabilities of $8.7 and $8.9, respectively, associated with UGI Unit awards are reflected in “Other current liabilities” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.

At September 30, 2010, 4,076,522 shares of Common Stock were available for future grants under the OECP, of which up to 1,687,347 may be issued pursuant to future grants other than stock options or SARs.

AmeriGas Partners Equity-Based Compensation Plans and Awards. On July 30, 2010, holders of AmeriGas Partners Common Units approved the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. (“2010 Propane Plan”). Under the 2010 Propane Plan, the General Partner may award to employees and non-employee directors grants of Common Units, performance units, options, phantom units, unit appreciation rights and other Common Unit-based awards. The total aggregate number of Common Units that may be issued under the Plan is 2,800,000. The exercise price for options may not be less than the fair market value on the date of grant. Awards granted under the 2010 Propane Plan may vest immediately or ratably over a period of years, and options can be exercised no later than ten years from the grant date. In addition, the 2010 Propane Plan provides that Common Unit-based awards may also provide for the crediting of Common Unit distribution equivalents to participants’ accounts.

The 2010 Propane Plan succeeds the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan (“2000 Propane Plan”) which expired on December 31, 2009, and replaces the AmeriGas Propane, Inc. Discretionary Long-Term Incentive Plan for Non-Executive Key Employees (“Nonexecutive Propane Plan”). Under the 2000 Propane Plan, the General Partner could award to key employees the right to receive Common Units (comprising performance units), or cash equivalent to the fair market value of such Common Units. In addition, the 2000 Propane Plan authorizes the crediting of Common Unit distribution equivalents to participants’ accounts. Under the Nonexecutive Propane Plan, the General Partner could grant awards to key employees who did not participate in the 2000 Propane Plan. Generally, awards under the Nonexecutive Propane Plan vest at the end of a three-year period and are paid in Common Units and cash. Effective January 1, 2010, no additional grants will be made under the 2000 Propane Plan. Effective July 30, 2010, no additional grants will be made under the Nonexecutive Propane Plan.

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

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

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

Risk-free rate

The General Partner granted awards under the 2010 Propane Plan, the 2000 Propane Plan and the Nonexecutive Propane Plan (collectively, “Awards”) representing 57,750, 60,200 and 40,050 Common Units in Fiscal 2010, Fiscal 2009 and Fiscal 2008, respectively, having weighted-average grant date fair values per Common Unit subject to award of $41.39, $31.94 and $37.91, respectively. At September 30, 2010, 2,796,550 Common Units were available for future award grants under the 2010 Propane Plan.

The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2010:

Forfeited

Vested

Awards paid

During Fiscal 2010, Fiscal 2009 and Fiscal 2008, the Partnership paid AmeriGas Common Unit-based awards in Common Units and cash as follows:

Number of Common Units subject to original Awards granted

Fiscal year granted

Payment of Awards:

AmeriGas Partners Common Units issued

Cash paid

As of September 30, 2010, there was a total of approximately $2.3 of unrecognized compensation cost associated with 146,600 Common Units subject to award that is expected to be recognized over a weighted-average period of 1.7 years. The total fair value of Common Unit-based awards that vested during Fiscal 2010, Fiscal 2009 and Fiscal 2008 was $2.0, $1.6 and $2.1, respectively. As of September 30, 2010 and 2009, total liabilities of $1.3 and $1.4 associated with Common Unit-based awards are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.

Note 14 — Partnership Distributions

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

all cash on hand at the end of such quarter,

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

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

The General Partner may establish reserves for the proper conduct of the Partnership’s business and for distributions during the next four quarters. In addition, certain of the Partnership’s debt agreements require reserves be established for the payment of debt principal and interest.

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

The Partnership has made quarterly distributions to Common Unitholders in excess of $0.605 per limited partner unit beginning with the quarterly distribution paid May 18, 2007. As a result, beginning with the quarterly distribution paid May 18, 2007 the General Partner has received a greater percentage of the total Partnership distribution than its aggregate 2% general partner interest in AmeriGas OLP and AmeriGas Partners. The General Partner distribution based on its aggregate 2% general partner ownership interests totaled $6.9 in Fiscal 2010, $8.5 in Fiscal 2009 and $4.3 in Fiscal 2008. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2010, Fiscal 2009 and Fiscal 2008 of $3.0, $4.5 and $0.7, respectively.

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

Note 15 — Commitments and Contingencies

Commitments

We lease various buildings and other facilities and vehicles, computer and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such leases was $70.6 in Fiscal 2010, $70.1 in Fiscal 2009 and $71.2 in Fiscal 2008.

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

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

The following table presents contractual obligations under Gas Utility, Electric Utility, Midstream & Marketing, AmeriGas Propane and International Propane supply, storage and service contracts existing at September 30, 2010:

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

In addition, we have committed to invest upon request a total of up to an additional $9.6 in a limited partnership that focuses on investments in the alternative energy sector.

Contingencies

Environmental Matters

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA terminates at the end of 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 and $25.0, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because 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 the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

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

Frontier Communications Company v. UGI Utilities, Inc. et al. In April 2003, Citizens Communications Company, now known as Frontier Communications Company (“Frontier”), served a complaint naming UGI Utilities as a third-party defendant in a civil action pending in the United States District Court for the District of Maine. In that action, the City of Bangor, Maine (“City”) sued Frontier to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of any costs Frontier would be required to pay to the City for cleaning up tar deposits in the Penobscot River. Frontier alleged that through ownership and control of a subsidiary, Bangor Gas Light Company, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Frontier made similar allegations of control against another third-party defendant, CenterPoint Energy Resources Corporation (“CenterPoint”), whose predecessor owned the Bangor subsidiary from 1928 to 1944. Frontier’s third-party claims were stayed pending a resolution of the City’s suit against Frontier, which was tried in September 2005. On June 27, 2006, the court issued an order finding Frontier responsible for 60% of the cleanup costs, which were estimated at $18. On February 14, 2007, Frontier and the City entered into a settlement agreement pursuant to which Frontier agreed to pay $7.6. Frontier subsequently filed the current action against the original third-party defendants, repeating its claims for contribution. On September 22, 2009, the court granted summary judgment in favor of co-defendant CenterPoint. UGI Utilities believes that it also has good defenses and has filed a motion for summary judgment with respect to Frontier’s claims. The court referred the motion to a magistrate judge for findings and a recommendation. On October 19, 2010, the magistrate judge entered an order recommending that the court grant UGI Utilities’ motion.

Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10. KeySpan believes that the cost could be as high as $20. UGI Utilities is in the process of reviewing the information provided by KeySpan and is investigating this claim.

Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of former subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs for all of the sites could total approximately $215 and asserted that UGI Utilities is responsible for approximately $103 of this amount. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites, Waterbury North, pursuant to a lease. In April 2009, the court conducted a trial to determine whether UGI Utilities operated any of the nine remaining sites that were owned and operated by former subsidiaries. On May 22, 2009, the court granted judgment in favor of UGI Utilities with respect to all nine sites. The Northeast Companies have appealed the decision. With respect to Waterbury North, the Northeast Companies are expected to complete additional environmental investigations by the end of 2010, after which there will be a second phase of the trial to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25.

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

Other Matters

Purported AmeriGas Class Action Lawsuits. On May 27, 2009, the General Partner was named as a defendant in a purported class action lawsuit in the Superior Court of the State of California in which plaintiffs are challenging AmeriGas OLP’s weight disclosure with regard to its portable propane grill cylinders. The complaint purports to be brought on behalf of a class of all consumers in the state of California during the four years prior to the date of the California complaint, who exchanged an empty cylinder and were provided with what is alleged to be only a partially filled cylinder. The plaintiffs seek restitution, injunctive relief, interest, costs, attorneys’ fees and other appropriate relief.

Since that initial suit, various AmeriGas entities have been named in more than a dozen similar suits that have been filed in various courts throughout the United States. These complaints purport to be brought on behalf of nationwide classes, which are loosely defined as including all purchasers of liquefied propane gas cylinders marketed or sold by AmeriGas OLP and another unaffiliated entity nationwide. The complaints claim that defendants’ conduct constituted unfair and deceptive practices that injured consumers and violated the consumer protection statutes of at least thirty-seven states and the District of Columbia, thereby entitling the class to damages, restitution, disgorgement, injunctive relief, costs and attorneys’ fees. Some of the complaints also allege violation of state “slack filling” laws. Additionally, the complaints allege that defendants were unjustly enriched by their conduct and they seek restitution of any unjust benefits received, punitive or treble damages, and pre-judgment and post-judgment interest. A motion to consolidate the purported class action lawsuits was heard by the Multidistrict Litigation Panel (“MDL Panel”) on September 24, 2009 in the United States District Court for the District of Kansas. By Order, dated October 6, 2009, the MDL Panel transferred the pending cases to the United States District Court for the Western District of Missouri. The AmeriGas entities named in the consolidated class action lawsuits have entered into a settlement agreement with the class. On May 19, 2010, the United States District Court for the District of Kansas granted the classes’ motion seeking preliminary approval of the settlement. On October 4, 2010, the District Court ruled that the settlement was fair, reasonable and adequate to the class and granted final approval of the settlement.

AmeriGas Cylinder Investigations. On or about October 21, 2009, the General Partner received a notice that the Offices of the District Attorneys of Santa Clara, Sonoma, Ventura, San Joaquin and Fresno Counties and the City Attorney of San Diego have commenced an investigation into AmeriGas OLP’s cylinder labeling and filling practices in California and issued an administrative subpoena seeking documents and information relating to these practices. We are cooperating with these California governmental investigations.

Swiger, et al. v. UGI/AmeriGas, Inc. et al. Samuel and Brenda Swiger and their son (the “Swigers”) sustained personal injuries and property damage as a result of a fire that occurred when propane that leaked from an underground line ignited. In July 1998, the Swigers filed a class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of Monongalia County, West Virginia, in which they sought to recover an unspecified amount of compensatory and punitive damages and attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants had installed propane gas lines, resulting from the defendants’ alleged failure to install underground propane lines at depths required by applicable safety standards. In 2003, AmeriGas OLP settled the individual personal injury and property damage claims of the Swigers. In 2004, the court granted the plaintiffs’ motion to include customers acquired from Columbia Propane Corporation in August 2001 as additional potential class member and the plaintiffs amended their complaint to name additional parties pursuant to such ruling. Subsequently, in March 2005 AmeriGas OLP filed a crossclaim against Columbia Energy Group, former owner of Columbia Propane Corporation, seeking indemnification for conduct undertaken by Columbia Propane Corporation prior to AmeriGas OLP’s acquisition. In June 2010, Columbia Energy Group filed a complaint in the Delaware Court of Chancery seeking to enjoin AmeriGas OLP from pursuing its cross-claims in the West Virginia litigation and asking the court to find that AmeriGas OLP’s cross-claims are without merit and barred. Class counsel has indicated that the class is seeking compensatory damages in excess of $12 plus punitive damages, civil penalties and attorneys’ fees. The Circuit Court of Monongalia County has tentatively scheduled a trial for the class action for the Spring of 2011.

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

French Business Tax. French tax authorities levy various taxes on legal entities and individuals regularly operating a business in France which are commonly referred to collectively as “business tax.” The amount of business tax charged annually is generally dependent upon the value of the entity’s tangible fixed assets. Antargaz has recorded liabilities for business taxes related to various classes of equipment. Changes in the French government’s interpretation of the tax laws or in the tax laws themselves could have either an adverse or a favorable effect on our results of operations.

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 (€7.1) 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.

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

Note 16 — Fair Value Measurements

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of September 30, 2010 and 2009:

Assets:

Derivative financial instruments:

Commodity contracts

Foreign currency contracts

Liabilities:

Interest rate contracts

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

Other Financial Instruments

The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt at September 30, 2010 were $2,005.8 and $2,144.7, respectively. The carrying amount and estimated fair value of our long-term debt at September 30, 2009 were $2,133.1 and $2,170.3, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt.

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

Note 17 — Disclosures About Derivative Instruments and Hedging Activities

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

Commodity Price Risk

In order to manage market price risk associated with the Partnership’s fixed-price programs which permit customers to lock in the prices they pay for propane principally during the months of October through March, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. Certain other domestic business units and our International Propane operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. In addition, the Partnership enters into price swap agreements to provide market price risk support to a limited number of its wholesale customers. These agreements are not designated as hedges for accounting purposes. The volume of propane subject to these wholesale customer agreements at September 30, 2010 and 2009 were not material.

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At September 30, 2010 the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 19.5 million dekatherms and the maximum period over which Gas Utility is hedging natural gas market price risk is 12 months. At September 30, 2009, there were no unsettled NYMEX natural gas futures or option contracts outstanding. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets in accordance with FASB’s guidance in ASC 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 8).

Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At September 30, 2010, the fair values of Electric Utility’s forward purchase power agreements comprising a loss of $19.7 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying September 30, 2010 Consolidated Balance Sheet. In accordance with ASC 980 related to rate regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At September 30, 2010, the volumes of Electric Utility’s forward electricity purchase contracts was 990.7 million kilowatt hours and the maximum period over which these contracts extend is 43 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010 pursuant to the January 22, 2009 settlement of its DS filing with the PUC, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 8). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At September 30, 2010 and 2009, the volumes associated with Electric Utility FTRs totaled 546.8 million kilowatt hours and 1,009.0 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At September 30, 2010 and 2009, the volumes associated with Midstream & Marketing’s FTRs totaled 1,026.4 million kilowatt hours and 729.0 million kilowatt hours, respectively.

In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas and electricity futures contracts.

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

At September 30, 2010 and 2009, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:

LPG (millions of gallons)

Natural gas (millions of dekatherms)

Electricity (millions of kilowatt hours)

At September 30, 2010, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 24 months with a weighted average of 5 months; the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 36 months with a weighted average of 7 months; and the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity price risk (excluding Electric Utility) is 28 months with a weighted average of 10 months. At September 30, 2010, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 8 months with a weighted average of 4 months.

We account for commodity price risk contracts (other than our Gas Utility natural gas futures and option contracts, Electric Utility electricity forward contracts, gasoline futures and swap contracts, and FTRs) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales on the Consolidated Statements of Income. At September 30, 2010, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $46.1.

Interest Rate Risk

Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has effectively fixed the underlying euribor interest rate on its €380 variable-rate debt through its March 2011 maturity date through the use of pay-fixed, receive-variable interest rate swap agreements. Antargaz intends to refinance its €380 variable-rate term loan on a long-term basis by March 2011. In anticipation of such refinancing, during Fiscal 2010 Antargaz entered into forward-starting interest rate swap agreements to hedge the underlying euribor rate of interest relating to 4 1/2 years of quarterly interest payments on €300 notional amount of long-term debt commencing March 31, 2011. Flaga has also fixed the underlying euribor interest rate on a substantial portion of its two term loans through their scheduled maturity dates ending in 2014 through the use of pay-fixed, receive-variable interest rate swap agreements. As of September 30, 2010 and 2009, the total notional amounts of our existing and anticipated variable-rate debt subject to interest rate swap agreements were €703.2 and €410.6, respectively.

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). There were no unsettled IRPAs outstanding at September 30, 2010. At September 30, 2009, the total notional amount of unsettled IRPAs was $150.

We account for interest rate swaps and IRPAs as cash flow hedges. Changes in the fair values of interest rate swaps and IRPAs are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At September 30, 2010, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $1.7.

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 20% to 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At September 30, 2010 and 2009, we were hedging a total of $108.6 and $131.5 of U.S. dollar-denominated LPG purchases, respectively. At September 30, 2010, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 29 months with a weighted average of 12 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At September 30, 2010 and 2009, we were hedging a total of €10.0 and €30.8, respectively, of our euro-denominated net investments. As of September 30, 2010, such foreign currency contracts extend through March 2013.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At September 30, 2010, the amount of net losses associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $1.0. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise major energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. At September 30, 2010 and 2009, restricted cash in brokerage accounts totaled $34.8 and $7.0, respectively. Although we have concentrations of credit risk associated with derivative financial instruments, the maximum amount of loss, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at September 30, 2010. We generally do not have credit-risk-related contingent features in our derivative contracts.

The following table provides information regarding the balance sheet location and fair value of derivative assets and liabilities existing as of September 30, 2010 and 2009:

Derivatives Designated as Hedging Instruments:

Commodity contracts

Foreign currency contracts

Interest rate contracts

Total Derivatives Designated as Hedging Instruments

Derivatives Accounted for Under ASC 980:

Derivatives Not Designated as Hedging Instruments:

Total Derivatives

The following tables provide information on the effects of derivative instruments on the Consolidated Statement of Income and changes in AOCI and noncontrolling interest for Fiscal 2010 and 2009:

Cash Flow Hedges:

Foreign currency contracts

Net Investment Hedges:

The amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material for Fiscal 2010, Fiscal 2009 and Fiscal 2008. During the three months ended March 31, 2010, the Partnership’s management determined that it was likely that the Partnership would not issue $150 of long-term debt during the summer of 2010 due to the Partnership’s strong cash flow and anticipated extension of all or a portion of the 2009 AmeriGas Supplemental Credit Agreement. As a result, the Partnership discontinued cash flow hedge accounting treatment for IRPAs associated with this previously anticipated Fiscal 2010 $150 long-term debt issuance and recorded a $12.2 loss which is reflected in other income, net on the Fiscal 2010 Consolidated Statement of Income. During Fiscal 2009, the Partnership recorded a loss of $1.7 as a result of the discontinuance of cash flow hedge accounting associated with IRPAs which amount was also reflected in other income, net.

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

Note 18 — Energy Services Accounts Receivable Securitization Facility

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

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

During Fiscal 2010, Fiscal 2009 and Fiscal 2008, Energy Services sold trade receivables totaling $1,147.3, $1,247.1 and $1,496.2, respectively, to ESFC. During Fiscal 2010, Fiscal 2009 and Fiscal 2008, ESFC sold an aggregate $254.6, $596.9 and $251.5, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At September 30, 2010, the outstanding balance of ESFC trade receivables was $44.0 which is net of $12.1 that was sold to the commercial paper conduit and removed from the balance sheet. At September 30, 2009, the outstanding balance of ESFC trade receivables was $38.2 which is net of $31.3 that was sold to the commercial paper conduit and removed from the balance sheet. Losses on sales of receivables to the commercial paper conduit that occurred during Fiscal 2010, Fiscal 2009 and Fiscal 2008, which are included in “Other income, net,” were $1.5, $2.3 and $0.9, respectively.

Effective October 1, 2010, the Company adopted a new accounting standard that changes the accounting for the Receivables Facility. For information on the effects of the change, see Note 3.

Note 19 — Other Income, Net

Other income, net, comprises the following:

Interest and interest-related income

Antargaz Competition Authority Matter

Utility non-tariff service income

Gain on sale of Partnership LPG storage facility

Gain on sale of Atlantic Energy, LLC

Finance charges

Partnership interest rate protection agreement losses

Other, net

Total other income, net

Note 20 — Quarterly Data (unaudited)

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

Operating income (loss)

Net income (loss)

Net income (loss) attributable to UGI Corporation

Earnings (loss) per share attributable to UGI stockholders:

Includes a gain from the sale of the Partnership’s California storage facility which increased operating income by $39.9 and net income attributable to UGI Corporation by $10.4 or $0.10 per diluted share (see Note 4).

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

Includes a provision for the Antargaz Competition Authority Matter which decreased operating income by $10.0 and increased net loss attributable to UGI Corporation by $10.0 or $0.10 per share (see Note 15).

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

Note 21 — Segment Information

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

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

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

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

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

2010

Cost of sales

Operating income (loss)

Loss from equity investees

Interest expense

Income (loss) before income taxes

Net income (loss) attributable to UGI

Depreciation and amortization

Noncontrolling interests’ net income

Partnership EBITDA (a)

Capital expenditures

Investments in equity investees

Goodwill

2009

Net income attributable to UGI

Noncontrolling interests’ net income (loss)

2008

Operating income

Income before income taxes

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

Partnership EBITDA

Depreciation and amortization

Noncontrolling interests (ii)

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

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

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

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

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

UGI CORPORATION AND SUBSIDIARIES

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

BALANCE SHEETS
(Millions of dollars)

ASSETS

Current assets:

Accounts and notes receivable

Investments in subsidiaries

Deferred income taxes

LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY

Current liabilities:

Accounts and notes payable

Accrued liabilities

Commitments and contingencies (Note 1)

Common stockholders’ equity:

Common Stock, without par value (authorized - 300,000,000 shares; issued — 115,400,294 and 115,261,294 shares, respectively)

Retained earnings

Accumulated other comprehensive loss

Less treasury stock, at cost

Total common stockholders’ equity

Total liabilities and common stockholders’ equity

Note 1 — Commitments and Contingencies:

In addition to the guarantees of Flaga’s debt as described in Note 5 to Consolidated Financial Statements, at September 30, 2010, UGI Corporation had agreed to indemnify the issuers of $32.1 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to $385.0 of obligations to suppliers and customers of UGI Energy Services, Inc. and subsidiaries of which $346.5 of such obligations were outstanding as of September 30, 2010.

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

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

Costs and expenses:

Other income, net (1)

Operating (loss) income

Intercompany interest income

(Loss) income before income taxes

Income tax expense

Loss before equity in income of unconsolidated subsidiaries

Equity in income of unconsolidated subsidiaries

Earnings per common share:

Average common shares outstanding (thousands):

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

STATEMENTS OF CASH FLOWS
(Millions of dollars)

NET CASH PROVIDED BY OPERATING ACTIVITIES (a)

CASH FLOWS FROM INVESTING ACTIVITIES:

Net investments in unconsolidated subsidiaries

Net cash used by investing activities

CASH FLOWS FROM FINANCING ACTIVITIES:

Payment of dividends on Common Stock

Issuance of Common Stock

Net cash used by financing activities

Includes dividends received from unconsolidated subsidiaries of $172.8, $110.7, and $144.0 for the years ended September 30, 2010, 2009 and 2008, respectively.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

(Millions of dollars)

Year Ended September 30, 2010

Reserves deducted from assets in the consolidated balance sheet:

Allowance for doubtful accounts

Other reserves:

Property and casualty liability

Environmental, litigation and other

Deferred tax assets valuation allowance

Year Ended September 30, 2009

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

Year Ended September 30, 2008

Uncollectible accounts written off, net of recoveries.

Other adjustments.

Payments, net.

Acquisition.

At September 30, 2010, 2009 and 2008, the Company had insurance indemnification receivables associated with its property and casualty liabilities totaling $7.2, $1.0 and $18.5, respectively.

EXHIBIT INDEX

UGI Corporation Amended and Restated Directors’ Deferred Compensation Plan as of January 1, 2005

UGI Corporation 1997 Stock Option and Dividend Equivalent Plan Amended and Restated as of May 24, 2005

Amended and Restated UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Stock Option Grant Letter effective January 1, 2010

Amended and Restated UGI Corporation 2004 Omnibus Equity Compensation Plan Sub-Plan for French Employees and Corporate Officers Performance Unit Grant Letter effective January 1, 2010

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

Summary of Director Compensation as of October 1, 2010

Trademark License Agreement dated April 19, 1995 among UGI Corporation, AmeriGas, Inc., AmeriGas Propane, Inc., AmeriGas Partners, L.P. and AmeriGas Propane, L.P.

Consent of PricewaterhouseCoopers LLP

Certification by the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act

Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act

Certification by the Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act

Business description of UGI-CORP-PA from last 10-k form