8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): May 26, 2010

UGI Corporation
(Exact name of registrant as specified in its charter)

Pennsylvania	1-11071	23-2668356
(State or other Jurisdiction of Incorporation)	(Commission File Number)	(IRS Employer Identification No.)

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

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

(Former name or former address if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Events.

Effective October 1, 2009, we adopted new guidance issued by the Financial Accounting Standards Board (“FASB”) regarding the accounting for and presentation of noncontrolling interests (previously minority interests). Prior to the adoption of the new FASB guidance, we reported minority interests between liabilities and stockholders’ equity on our Consolidated Balance Sheets. The new guidance requires an entity to clearly identify and present ownership interests in subsidiaries held by parties other than the parent in the consolidated financial statements within the equity section but separate from the parent’s equity. The new guidance also requires that revenues, expenses, net income or loss, and other comprehensive income or loss be reported in the consolidated financial statements at the consolidated amounts, which includes amounts attributable to both owners of the parent and to noncontrolling interests. Net income or loss and other comprehensive income or loss is then attributed to the parent and to noncontrolling interests. Prior to the adoption of the new guidance, we recorded minority interest in net income (loss) of consolidated subsidiaries in the determination of net income (loss). These changes were reflected in the financial statements included in our Quarterly Reports on Form 10-Q for the first and second quarters of fiscal 2010, filed with the U.S. Securities and Exchange Commission (“SEC”) on February 5, 2010 and May 7, 2010, respectively. These changes did not affect our net income per basic or diluted common share.

We have recast certain prior financial statements to retrospectively reflect the adoption of the new accounting guidance regarding noncontrolling interests. We have also recast the related Management’s Discussion and Analysis of Financial Condition and Results of Operations and Selected Financial Information for the five years ended September 30, 2009. The Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Selected Financial Information included in this Current Report on Form 8-K supersede those included in our Annual Report on Form 10-K for the year ended September 30, 2009, filed with the SEC on November 20, 2009.

Copies of the Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Financial Statements and Supplementary Data are filed hereto as Exhibits 99.1, 99.2 and 99.3, respectively, and are incorporated herein by reference.

Item 9.01 Financial Statements and Exhibits.

The following exhibits are filed with this report:

Exhibit Number	Exhibit Description
99.1	Selected Financial Data
99.2	Management’s Discussion and Analysis of Financial Condition and Results of Operations
99.3	Financial Statements and Supplementary Data
99.4	Consent of PricewaterhouseCoopers LLP

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	UGI Corporation
May 26, 2010	By:	Peter Kelly
		Name: Peter Kelly
		Title: Vice President-Finance and Chief Financial Officer

EXHIBIT INDEX

EXHIBIT NO.	DESCRIPTION
99.1	Selected Financial Data
99.2	Management’s Discussion and Analysis of Financial Condition and Results of Operations
99.3	Financial Statements and Supplementary Data
99.4	Consent of PricewaterhouseCoopers LLP

EX-99.1

Exhibit 99.1

ITEM 6. SELECTED FINANCIAL DATA

	Year Ended September 30,
(Millions of dollars, except per share amounts)	2009			2008			2007			2006			2005
FOR THE PERIOD:
Income statement data:
Revenues	$	5,737.8		$	6,648.2		$	5,476.9		$	5,221.0		$	4,888.7
Net income	$	382.0		$	305.3		$	311.2		$	224.9		$	217.4
Less: net income attributable to noncontrolling interests, principally in AmeriGas Partners		(123.5	)		(89.8	)		(106.9	)		(48.7	)		(29.9	)
Net income attributable to UGI Corporation	$	258.5		$	215.5		$	204.3		$	176.2		$	187.5
Earnings per common share attributable to UGI stockholders:
Basic	$	2.38		$	2.01		$	1.92		$	1.67		$	1.81
Diluted	$	2.36		$	1.99		$	1.89		$	1.65		$	1.77
Cash dividends declared per common share	$	0.785		$	0.755		$	0.723		$	0.690		$	0.650
AT PERIOD END:
Balance sheet data:
Total assets	$	6,042.6		$	5,685.0		$	5,502.7		$	5,080.5		$	4,571.5
Capitalization:
Debt:
Bank loans — UGI Utilities	$	154.0		$	57.0		$	190.0		$	216.0		$	81.2
Bank loans — Antargaz		—			70.4			—			—			—
Bank loans — other		9.1			9.0			8.9			9.4			16.2
Long-term debt (including current maturities):
AmeriGas Propane		865.6			933.4			933.1			933.7			913.5
Antargaz		557.7			537.4			544.9			483.5			431.1
UGI Utilities		640.0			532.0			512.0			512.0			237.0
Other		69.8			66.3			63.5			67.7			62.9
Total debt		2,296.2			2,205.5			2,252.4			2,222.3			1,741.9
UGI Corporation stockholders’ equity		1,591.4			1,417.7			1,321.9			1,099.6			997.6
Noncontrolling interests, principally in AmeriGas Partners		225.4			159.2			192.2			139.5			206.3
Total capitalization	$	4,113.0		$	3,782.4		$	3,766.5		$	3,461.4		$	2,945.8
Ratio of capitalization:
Total debt		55.8	%		58.3	%		59.8	%		64.2	%		59.1	%
UGI Corporation stockholders’ equity		38.7	%		37.5	%		35.1	%		31.8	%		33.9	%
Noncontrolling interests, principally in AmeriGas Partners		5.5	%		4.2	%		5.1	%		4.0	%		7.0	%
		100.0	%		100.0	%		100.0	%		100.0	%		100.0	%

EX-99.2

Exhibit 99.2

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

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

Executive Overview

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

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

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

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

1

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

Results of Operations

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

Fiscal 2009 Compared with Fiscal 2008
Consolidated Results

Net Income Attributable to UGI Corporation by Business Unit:

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

N.M. — Variance is not meaningful.

Highlights — Fiscal 2009 versus Fiscal 2008

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

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

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

• AmeriGas Partners’ sale of its California LPG storage terminal generated net income attributable to UGI Corporation of $10.4 million.

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

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

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

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

Our consolidated results of operations for the years ended September 30, 2009, 2008 and 2007 include the effects of the Financial Accounting Standards Board’s accounting guidance for the presentation of noncontrolling interests in consolidated financial statements. For further discussion see Note 3 to consolidated financial statements.

2

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

(a)	Total margin represents total revenues less total cost of sales.
(b)	Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements).
(c)	Deviation from average heating degree-days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska. Fiscal 2008 data has been adjusted to correct a NOAA error.

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

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

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

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

3

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

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

(a)	Reflects the consolidation of ZLH subsequent to Flaga’s January 2009 acquisition of the 50% of ZLH it did not already own.
(b)	Total margin represents total revenues less total cost of sales.
(c)	Deviation from average heating degree days for the 30-year period 1971-2000 at 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.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. During Fiscal 2009, the average currency translation rate was $1.35 per euro compared to a rate of $1.51 per euro during Fiscal 2008. Although the stronger dollar resulted in lower translated International Propane operating results, the effects of the stronger dollar on reported International Propane net income 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 lower average selling prices partially offset by an increase in revenues from the consolidation of ZLH. The lower average selling prices reflect the previously mentioned year-over-year decrease in wholesale LPG product costs. In U.S. dollars, revenues declined $169.5 million or 15.1% reflecting the previously mentioned total lower euro-based revenues and the effects of the stronger U.S. dollar. International Propane’s total cost of sales decreased to €320.0 million in Fiscal 2009 from €434.9 million in Fiscal 2008, a 26.4% decline, principally reflecting the lower per-unit LPG commodity costs and, to a much lesser extent, the effects of gains on forward currency contracts used to hedge purchases of dollar-denominated LPG. On a U.S. dollar basis, cost of sales decreased $222.4 million or 34.1%.

4

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

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

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

(a)	Total margin represents total revenues less total cost of sales.
(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. In Fiscal 2009, Gas Utility began calculating normal degree days using the 15-year period 1990-2004. Previously, normal degree days were based upon recent 30-year periods. For comparison purposes, the Fiscal 2008 weather variance has been recalculated using the new 15-year period. Total distribution throughput increased 16.0 bcf in Fiscal 2009 principally reflecting the effects of the October 1, 2008 CPG Acquisition and increases in core-market volumes resulting from the colder Fiscal 2009 weather and year-over-year customer growth. Gas Utility’s core-market customers principally comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers. These increases in system throughput were partially offset by the effects on volumes sold and transported due to lower demand from commercial and industrial customers as a result of the deterioration in general economic activity and customer conservation.

5

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

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

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

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

(a) 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 the effects of the lower sales volumes.

6

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

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

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

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

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

Interest Expense and Income Taxes. Consolidated interest expense decreased slightly to $141.1 million in Fiscal 2009 from $142.5 million in Fiscal 2008 principally due to lower International Propane interest expense, attributable to lower effective interest rates and the stronger U.S. dollar, lower interest on UGI Utilities revolving credit agreement borrowings and lower interest expense on AmeriGas Propane long-term debt largely offset by incremental interest expense on CPG Acquisition debt. Our effective income tax rate was slightly lower in Fiscal 2009 reflecting the effects of a higher percentage of pretax income from noncontrolling interests, principally in AmeriGas Partners, not subject to income taxes.

Fiscal 2008 Compared with Fiscal 2007
Consolidated Results

Net Income Attributable to UGI Corporation by Business Units:

												Variance- Favorable
	Fiscal 2008					Fiscal 2007						(Unfavorable)
			% of						% of						%
(Millions of dollars)	Amount		Total			Amount			Total			Amount			Change
AmeriGas Propane	$	43.9		20.4	%	$	53.2			26.0	%	$	(9.3	)		(17.5	)%
International Propane		52.3		24.3	%		44.9			22.0	%		7.4			16.5	%
Gas Utility		60.3		28.0	%		59.0			28.9	%		1.3			2.2	%
Electric Utility		13.1		6.1	%		13.7			6.7	%		(0.6	)		(4.4	)%
Energy Services		45.3		21.0	%		34.5			16.9	%		10.8			31.3	%
Corporate & Other		0.6		0.2	%		(1.0	)		(0.5	)%		1.6			N.M.
Total Net Income Attributable to UGI Corporation	$	215.5		100.0	%	$	204.3			100.0	%	$	11.2			5.5	%

N.M. — Variance is not meaningful.

7

Highlights — Fiscal 2008 versus Fiscal 2007

• Energy Services Fiscal 2008 results benefited from greater income from peaking supply and storage management services and higher electric generation margin.

• Fiscal 2008 International Propane results improved driven by a return to more normal weather compared with the record-setting warm weather experienced in Fiscal 2007.

• Significant increases in LPG cost during most of Fiscal 2008 caused all propane businesses to experience increased conservation and certain of our International Propane business units to experience modest unit margin reductions.

• AmeriGas Propane total margin was higher in Fiscal 2008 despite the effects of price-induced customer conservation on volumes sold.

							Increase
AmeriGas Propane	2008			2007			(Decrease)
(Millions of dollars)
Revenues	$	2,815.2		$	2,277.4		$	537.8		23.6	%
Total margin (a)	$	906.9		$	840.2		$	66.7		7.9	%
Partnership EBITDA (b)	$	313.0		$	338.7		$	(25.7	)	(7.6	)%
Operating income	$	235.0		$	265.8		$	(30.8	)	(11.6	)%
Retail gallons sold (millions)		993.2			1,006.7			(13.5	)	(1.3	)%
Degree days — % (warmer) than normal (c)		(3.0	)%		(6.5	)%		—		—

(a)	Total margin represents total revenues less total cost of sales.
(b)	Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 21 to Consolidated Financial Statements).
(c)	Deviation from average heating degree-days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska. Fiscal 2008 data has been adjusted to correct a NOAA error.

Based upon heating degree-day data, average temperatures in AmeriGas Propane’s service territories were 3.0% warmer than normal in Fiscal 2008 compared with temperatures that were 6.5% warmer than normal in Fiscal 2007. Notwithstanding the slightly colder Fiscal 2008 weather and the full year benefits of acquisitions made in Fiscal 2007, retail gallons sold were slightly lower reflecting, among other things, customer conservation in response to increasing propane product costs and a weak economy. The average wholesale propane product cost at Mont Belvieu, Texas, increased nearly 50% during Fiscal 2008 over the average cost during Fiscal 2007.

Retail propane revenues increased $480.7 million in Fiscal 2008 reflecting a $507.0 million increase due to the higher average selling prices partially offset by a $26.3 million decrease as a result of the lower retail volumes sold. Wholesale propane revenues increased $47.8 million in Fiscal 2008 reflecting a $55.1 million increase from higher average wholesale selling prices partially offset by a $7.3 million decrease from lower wholesale volumes sold. Other revenues increased $9.3 million reflecting in large part higher fee income. Total cost of sales increased $471.1 million to $1,908.3 million in Fiscal 2008 reflecting higher propane product costs.

Total margin was $66.7 million greater in Fiscal 2008 principally reflecting higher average propane margin per retail gallon sold and, to a much lesser extent, higher fee income.

8

Partnership EBITDA in Fiscal 2008 was $313.0 million compared to EBITDA of $338.7 million in Fiscal 2007. Fiscal 2007 EBITDA includes $46.1 million resulting from the sale of the Partnership’s Arizona storage facility. Excluding the effects of this gain in Fiscal 2007, EBITDA in Fiscal 2008 increased $20.4 million over Fiscal 2007 principally reflecting the previously mentioned increase in total margin partially offset by a $47.9 million increase in operating and administrative expenses. The increased operating expenses reflect expenses associated with acquisitions, increased vehicle fuel and maintenance expenses, greater general insurance expense and, to a lesser extent, higher uncollectible accounts expenses largely attributable to the higher revenues.

AmeriGas Propane’s operating income decreased $30.8 million in Fiscal 2008 reflecting the lower EBITDA and higher depreciation and amortization expense resulting from the full-year effects of Fiscal 2007 propane business acquisitions and plant and equipment expenditures.

							Increase
International Propane	2008			2007			(Decrease)
(Millions of euros)
Revenues	€	749.8		€	602.4		€	147.4		24.5	%
Total margin (a)	€	314.9		€	309.8		€	5.1		1.6	%
Operating income	€	70.4		€	73.3		€	(2.9	)	(4.0	)%
Income before income taxes	€	48.8		€	51.4		€	(2.6	)	(5.1	)%
(Millions of dollars)
Revenues	$	1,124.8		$	800.4		$	324.4		40.5	%
Total margin (a)	$	472.9		$	411.8		$	61.1		14.8	%
Operating income	$	106.8		$	94.5		$	12.3		13.0	%
Income before income taxes	$	73.0		$	64.1		$	8.9		13.9	%
Antargaz retail gallons sold (millions)		292.6			269.1			23.5		8.7	%
Degree days — % (warmer) than normal (b)		(4.1	)%		(21.1	)%		—		—

(a)	Total margin represents total revenues less total cost of sales.
(b)	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 4.1% warmer than normal during Fiscal 2008 compared with temperatures that were approximately 21.1% warmer than normal during Fiscal 2007. Temperatures in Flaga’s service territory were also warmer than normal and significantly colder than the prior year. Principally as a result of the colder weather, Antargaz’ retail volumes sold increased to 292.6 million gallons in Fiscal 2008 from 269.1 million gallons in Fiscal 2007. Flaga also recorded higher retail gallons sold in Fiscal 2008. The beneficial volume effects on Antargaz resulting from the colder weather were partially offset by customer conservation in response to substantially higher LPG commodity costs, the loss of a low-margin industrial customer and a weaker economy. The average wholesale price for propane in northwest Europe during Fiscal 2008 was nearly 35% higher than such average price in Fiscal 2007.

During Fiscal 2008, the average currency translation rate was $1.51 per euro compared to a rate of $1.34 during Fiscal 2007. The effects of the weaker dollar on year-over-year International Propane net income attributable to UGI Corporation were substantially offset, however, by the impact of losses on forward currency contracts used to purchase dollar denominated LPG.

International propane euro-based revenues increased €147.4 million principally reflecting higher Antargaz and Flaga average selling prices during Fiscal 2008 and the higher Antargaz and Flaga retail volumes sold. International Propane’s total cost of sales increased to €434.9 million in Fiscal 2008 from € 292.6 million in Fiscal 2007, largely reflecting the higher per-unit LPG commodity costs, the greater volumes sold and, to a much lesser extent, higher losses on forward currency contracts.

International Propane total margin increased €5.1 million or 1.6% in Fiscal 2008 reflecting the effects of the greater retail sales of LPG substantially offset by a decline in average retail unit margin per gallon primarily due to the significantly higher LPG commodity costs and increased competition in certain customer segments at Antargaz. In U.S. dollars, total margin increased $61.1 million or 14.8% principally reflecting the effects of the weaker dollar on translated euro base-currency revenues and cost of sales.

9

International Propane euro-based operating income decreased €2.9 million principally reflecting the previously mentioned €5.1 million increase in total margin more than offset by higher operating and administrative expenses, due in large part to the effects of the increased sales activity and higher fuel costs, and greater depreciation from plant and equipment additions. On a U.S. dollar basis, operating income increased $12.3 million as the previously-mentioned $61.1 million increase in total margin was substantially offset by higher U.S. dollar denominated operating and administrative expenses and depreciation and amortization expense. Euro-based income before income taxes was €2.6 million lower than last year primarily reflecting the lower operating income. In U.S. dollars, income before income taxes was $8.9 million higher than the prior year reflecting the higher operating income slightly offset by greater U.S. dollar translated interest expense. Although Flaga’s results, including those of ZLH, improved in Fiscal 2008 due in large part to the colder weather, ZLH continued to experience the effects on sales volumes of customer conservation and competition from alternative fuels and other suppliers caused in large part by high and increasing LPG commodity costs.

Gas Utility	2008			2007			Increase
(Millions of dollars)
Revenues	$	1,138.3		$	1,044.9		$	93.4	8.9	%
Total margin (a)	$	307.2		$	303.4		$	3.8	1.3	%
Operating income	$	137.6		$	136.6		$	1.0	.7	%
Income before income taxes	$	100.5		$	96.7		$	3.8	3.9	%
System throughput — billions of cubic feet (“bcf”)		133.7			131.8			1.9	1.4	%
Degree days — % (warmer) than normal (b)		(2.7	)%		(2.4	)%		—	—

(a)	Total margin represents total revenues less total cost of sales.
(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 2.7% warmer than normal in Fiscal 2008 compared with temperatures that were 2.4% warmer than normal in Fiscal 2007. Total distribution system throughput increased 1.9 bcf in Fiscal 2008 principally reflecting greater interruptible delivery service volumes (principally volumes associated with low margin cogeneration customers) and an increase in the number of Gas Utility core market customers partially offset by lower average usage per customer due in large part to price-induced customer conservation and a weak economy.

Gas Utility revenues increased $93.4 million in Fiscal 2008 principally reflecting a $57.4 million increase in revenues from off-system sales and the effects of higher average PGC rates on retail core-market revenues. Gas Utility’s cost of sales was $831.1 million in Fiscal 2008 compared with $741.5 million in Fiscal 2007 principally reflecting the greater off-system sales and the increase in average retail core-market PGC rates.

Gas Utility total margin increased $3.8 million in Fiscal 2008 primarily reflecting modest increases in interruptible delivery service and core market total margin.

10

The increase in Gas Utility operating income principally reflects the previously mentioned $3.8 million increase in total margin and a $5.3 million increase in other income partially offset by modestly higher operating and administrative expenses. The higher other income reflects in large part greater storage contract fees and a $2.2 million postretirement benefit plan curtailment gain. The increase in operating and administrative expenses includes, among other things, higher environmental legal costs and greater uncollectible accounts expense. Gas Utility income before income taxes also reflects lower interest expense on bank loans.

					Increase
Electric Utility	2008		2007		(Decrease)
(Millions of dollars)
Revenues	$	139.2	$	121.9	$	17.3		14.2	%
Total margin (a)	$	47.0	$	47.3	$	(0.3	)	(0.6	)%
Operating income	$	24.4	$	26.0	$	(1.6	)	(6.2	)%
Income before income taxes	$	22.4	$	23.6	$	(1.2	)	(5.1	)%
Distribution sales — millions of kilowatt hours (“gwh”)		1,004.4		1,010.6		(6.2	)	(0.6	)%

(a) Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $7.9 million and $6.9 million during Fiscal 2008 and Fiscal 2007, 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 2008 were about equal to Fiscal 2007 on heating-season weather that was slightly warmer and cooling-season weather that was slightly cooler. Electric Utility revenues increased $17.3 million principally as a result of higher POLR rates. Electric Utility cost of sales increased to $84.3 million in Fiscal 2008 from $67.8 million in the prior year principally reflecting higher per-unit purchased power costs.

Electric Utility total margin in Fiscal 2008 was about equal to Fiscal 2007 reflecting the effects of the higher POLR rates offset principally by the higher per-unit purchased power costs and higher revenue-related taxes.

The decrease in Fiscal 2008 Electric Utility operating income reflects slightly higher operating and administrative costs including higher system maintenance and uncollectible accounts expense. Income before income taxes reflects the lower operating income partially offset by lower interest expense on bank loans.

Energy Services	2008		2007		Increase
(Millions of dollars)
Revenues	$	1,619.5	$	1,336.1	$	283.4	21.2	%
Total margin (a)	$	124.1	$	100.9	$	23.2	23.0	%
Operating income	$	77.3	$	57.4	$	19.9	34.7	%
Income before income taxes	$	77.3	$	57.4	$	19.9	34.7	%

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

Notwithstanding retail gas volumes in Fiscal 2008 that were approximately equal to the prior-year period, Energy Services revenues increased $283.4 million principally reflecting the effects of higher commodity costs for natural gas and propane, higher electricity spot-market and fixed contract prices, and higher revenues from peaking supply services.

Total margin from Energy Services was $23.2 million higher in Fiscal 2008 reflecting greater total margin from peaking supply and storage management services, due in part to the expansion of peaking facilities and higher peaking rates charged, and higher electric generation margin resulting in large part from higher spot-market and fixed contract prices for electricity in Fiscal 2008 compared with Fiscal 2007. The increase in Energy Service’s operating income and income before income taxes in Fiscal 2008 principally reflects the previously mentioned $23.2 million increase in total margin partially offset by slightly higher operating and administrative expenses.

Interest Expense and Income Taxes. Consolidated interest expense increased to $142.5 million in Fiscal 2008 from $139.6 million in Fiscal 2007 principally due to higher interest expense associated with greater Partnership short-term borrowings to fund increases in working capital principally as a result of higher commodity prices for propane during Fiscal 2008 and the effects of foreign exchange on International Propane interest expense. Our effective income tax rate in Fiscal 2008 was slightly higher than in Fiscal 2007 reflecting the effects of a lower percentage of pretax income from noncontrolling interests, principally in AmeriGas Partners, not subject to income taxes.

11

Financial Condition and Liquidity

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

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

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

AmeriGas Propane’s ability to pay dividends to UGI is dependent upon distributions it receives from AmeriGas Partners. At September 30, 2009, our 44% effective ownership interest in the Partnership consisted of approximately 24.7 million Common Units and combined 2% general partner interests. Approximately 45 days after the end of each fiscal quarter, the Partnership distributes all of its Available Cash (as defined in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, the “Partnership Agreement”) relating to such fiscal quarter. The ability of the Partnership to pay distributions depends upon a number of factors. These factors include (1) the level of Partnership earnings; (2) the cash needs of the Partnership’s operations (including cash needed for maintaining and increasing operating capacity); (3) changes in operating working capital; and (4) the ability of the Partnership to borrow under its Credit Agreement, to refinance maturing debt and to increase its long-term debt. Some of these factors are affected by conditions beyond the Partnership’s control including weather, competition in markets it serves, the cost of propane and capital market conditions.

During Fiscal 2009, Fiscal 2008 and Fiscal 2007, our principal business units paid cash dividends and made other cash payments to UGI and its subsidiaries as follows:

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

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

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

12

Long-term Debt and Credit Facilities

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

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

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

AmeriGas OLP’s Credit Agreement expires on October 15, 2011 and consists of (1) a $125 million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 million to finance the purchase of propane businesses or propane business assets or, to the extent it is not so used, for working capital and general purposes.

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

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

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

13

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

Antargaz. Antargaz has a five-year, floating rate Senior Facilities Agreement that expires on March 31, 2011. The Senior Facilities Agreement consists of (1) a €380 million variable-rate term loan and (2) a €50 million revolving credit facility. Antargaz executed interest rate swap agreements to fix the underlying euribor rate of interest on the term loan at approximately 3.25% for the duration of the loan. The effective interest rate on Antargaz’ term loan at September 30, 2009 was 3.94%. The Senior Facilities Agreement also includes a €50 million letter of credit facility. In order to minimize the interest margin it pays on Senior Facilities Agreement borrowings, in September 2008 Antargaz borrowed €50 million ($70.4 million), the total amount available under its revolving credit facility, which amount remained outstanding at September 30, 2008. This amount is included in bank loans on the September 30, 2008 Consolidated Balance Sheet. This borrowing was repaid by Antargaz on October 27, 2008. Excluding this borrowing in September 2008, no other amounts were borrowed under Antargaz’ revolving credit facility during Fiscal 2009 or Fiscal 2008.

The Senior Facilities Agreement restricts the ability of Antargaz to, among other things, incur additional indebtedness and make investments. For a more detailed discussion of Antargaz’ debt, see Note 5 to Consolidated Financial Statements.

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

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

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

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

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

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UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement. This agreement expires in August 2011. Amounts outstanding under the Revolving Credit Agreement are classified as bank loans on the Consolidated Balance Sheets. During Fiscal 2009 and Fiscal 2008, peak bank loan borrowings totaled $312 million and $267 million, respectively. Average daily bank loan borrowings were $180.0 million in Fiscal 2009 and $121.0 million in Fiscal 2008. Revolving Credit Agreement borrowings were greater in Fiscal 2009 due in large part to increases in margin deposits associated with natural gas futures contracts as a result of declines in wholesale natural gas prices. UGI Utilities’ Revolving Credit Agreement requires it to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

Based upon cash expected to be generated from Gas Utility and Electric Utility operations and borrowings available under its Revolving Credit Agreement, UGI Utilities’ management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2010. For a more detailed discussion of UGI Utilities’ long-term debt and Revolving Credit Agreement, see Note 5 to Consolidated Financial Statements.

Energy Services. Energy Services has a $200 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper expiring in April 2010, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility’s back-up purchasers. Management expects it will extend or replace the Receivables Facility prior to its termination date. Under the Receivables Facility, Energy services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. At September 30, 2009, the outstanding balance of ESFC trade receivables was $38.2 million which is net of $31.3 million that was sold to the commercial paper conduit and removed from the balance sheet. During Fiscal 2009 and Fiscal 2008, peak sales of receivables were $139.7 million and $71.0 million, respectively. The greater peak sales in Fiscal 2009 reflect greater cash needed to fund collateral deposits on natural gas NYMEX futures accounts due to the sharp decline in natural gas prices. Based upon cash expected to be generated from operations, borrowings available under its Receivables Facility and capital contributions from UGI for capital projects, management believes that Energy Services will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2010. For a more detailed discussion of the Receivables Facility, see Note 18 to Consolidated Financial Statements.

Cash Flows

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

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

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

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

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

Capital Expenditures

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

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

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

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Contractual Cash Obligations and Commitments

The Company has contractual cash obligations that extend beyond Fiscal 2009. Such obligations include scheduled repayments of long-term debt, interest on long-term fixed-rate debt, operating lease payments, unconditional purchase obligations for pipeline capacity, pipeline transportation and natural gas storage services and commitments to purchase natural gas, LPG and electricity, capital expenditures and derivative financial instruments. The following table presents contractual cash obligations under agreements existing as of September 30, 2009:

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

(a)	Based upon stated maturity dates.
(b)	Based upon stated interest rates adjusted for the effects of interest rate swaps.
(c)	Represents the sum of amounts due from us if derivative financial instrument liabilities were settled at the September 30, 2009 amounts reflected in the Consolidated Balance Sheet (but excluding amounts associated with interest rate swaps).
(d)	Includes material capital expenditure obligations.

Components of other noncurrent liabilities included in our Consolidated Balance Sheet at September 30, 2009 principally comprise refundable tank and cylinder deposits (as further described in Note 2 to Consolidated Financial Statements under the caption “Refundable Tank and Cylinder Deposits”); litigation, property and casualty liabilities and obligations under environmental remediation agreements (see Note 15); pension and other post-employment benefit liabilities recorded in accordance with accounting guidance relating to employee retirement plans (see Note 7); and liabilities associated with executive compensation plans (see Note 13). These liabilities are not included in the table of Contractual Cash Obligations and Commitments because they are estimates of future payments and not contractually fixed as to timing or amount. In addition, we have committed to invest over the next several years a total of up to $25 million in a limited partnership that will focus on investments in the alternative energy sector.

Significant Acquisitions and Dispositions

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

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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.

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

Antargaz Competition Authority Matter

In June 2005, officials from France’s General Division of Competition, Consumption and Fraud Punishment (“DGCCRF”) conducted an unannounced inspection of, and obtained documents from, Antargaz’ headquarters building. Antargaz did not have any further contact with the DGCCRF regarding this matter until February 2007, when it received a letter from the DGCCRF requesting documents and information relating to Antargaz’ pricing policies and practices. In March 2007, and again in August 2007, the DGCCRF requested additional information from Antargaz and three joint ventures in which it participates. In July 2008, France’s Autorité de la concurrence (“Competition Authority”) interviewed Mr. Varagne, as President of Antargaz and President of the industry association, Comité Français du Butane et du Propane, about competitive practices in the LPG cylinder market in France.

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

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

Pension Plans

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

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

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

GAAP guidance associated with pension and other postretirement plans generally requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and other postretirement benefit plans with current year changes recognized in shareholders’ equity unless such amounts are subject to regulatory recovery. In accordance with this guidance, through September 30, 2009 we have recorded cumulative after-tax charges to UGI Corporation stockholders’ equity of $81.5 million in order to reflect the funded status of these plans. For a more detailed discussion of the Pension Plans and other postretirement benefit plans, see Note 7 to Consolidated Financial Statements.

Related Party Transactions

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

Off-Balance Sheet Arrangements

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

We do not have any off-balance sheet arrangements that are expected to have a material effect on our financial condition, change in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Utility Regulatory Matters

Gas Utility

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

Electric Utility

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

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

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

Because Electric Utility will be assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010 Electric Utility will no longer be subject to the risk that actual costs for purchased power will exceed POLR revenues. However, beginning January 1, 2010, Electric Utility will forego the opportunity to recover revenues in excess of actual costs as currently permitted under the POLR Settlement. This will result in a reduction in Electric Utility’s Fiscal 2010 operating income.

Manufactured Gas Plants

UGI Utilities

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

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

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

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

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

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

AmeriGas OLP

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

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

Market Risk Disclosures

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

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Commodity Price Risk

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

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

Electric Utility purchases its electric power needs from electricity suppliers under fixed-price energy contracts and, to a much lesser extent, on the spot market. Wholesale prices for electricity can be volatile especially during periods of high demand or tight supply. Electric Utility’s fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 2009. With respect to its existing fixed-price power contracts, should any of the counterparties fail to provide electric power under the terms of such contracts, any increases in the cost of replacement power could negatively impact Electric Utility results. In order to reduce this nonperformance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. As previously mentioned, on January 22, 2009, the PUC approved a settlement of a rate filing that provides for Electric Utility to fully recover its default service costs beginning January 1, 2010. Because Electric Utility will be assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010, Electric Utility will no longer be subject to the risk that actual costs for purchased power will exceed POLR revenues.

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

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

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

22

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

Interest Rate Risk

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

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

Our long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. This debt may have an interest rate that is more or less than the refinanced debt. In order to reduce interest rate risk associated with near- to medium- term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements.

Foreign Currency Exchange Rate Risk

Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign-denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Realized gains or losses remain in accumulated other comprehensive income until such foreign operations are liquidated. At September 30, 2009, the fair value of unsettled net investment hedges was a loss of $5.7 million, which is included in foreign currency exchange rate risk in the table below. With respect to our net investments in Flaga and Antargaz, a 10% decline in the value of the euro versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value by approximately $61.9 million, which amount would be reflected in other comprehensive income.

Derivative Financial Instrument Credit Risk

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

23

The following table summarizes the fair values of unsettled market risk sensitive derivative instruments assets and (liabilities) held at September 30, 2009 and 2008. The table also includes the changes in fair value that would result if there were a 10% adverse change in (1) the market price of LPG and gasoline; (2) the market price of natural gas; (3) the market price of electricity and electricity transmission congestion changes; (4) the three-month LIBOR and the three- and nine-month Euribor and; (5) the value of the euro versus the U.S. dollar. The fair value of Gas Utility’s exchange-traded natural gas futures contracts comprising losses $23.3 million at September 30, 2008 are excluded from the table below because any associated net gains or losses are included in Gas Utility’s PGC recovery mechanism. There were no such contracts at September 30, 2009.

	Asset (Liability)
				Change in
	Fair Value			Fair Value
(Millions of dollars)
September 30, 2009:
LPG commodity price risk	$	12.2		$	(14.4	)
FTR price risk		2.9			(0.3	)
Natural gas commodity price risk		(0.4	)		(13.6	)
Gasoline price risk		0.1			(0.2	)
Electricity commodity price risk		(3.4	)		(1.7	)
Interest rate risk		(34.4	)		(6.0	)
Foreign currency exchange rate risk		(5.7	)		(18.2	)
September 30, 2008:
LPG commodity price risk	$	(53.7	)	$	(29.2	)
FTR price risk		5.7			(0.6	)
Natural gas commodity price risk		(29.1	)		(21.7	)
Electricity commodity price risk		(0.7	)		(0.2	)
Interest rate risk		9.1			(9.9	)
Foreign currency exchange rate risk		3.4			(19.5	)

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

Critical Accounting Policies and Estimates

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

24

Litigation Accruals and Environmental Remediation Liabilities. We are involved in litigation regarding pending claims and legal actions that arise in the normal course of our businesses. In addition, UGI Utilities and its former subsidiaries owned and operated a number of MGPs in Pennsylvania and elsewhere, and PNG Gas and CPG Gas owned and operated a number of MGP sites located in Pennsylvania, at which hazardous substances may be present. In accordance with accounting principles generally accepted in the United States of America, the Company establishes reserves for pending claims and legal actions or environmental remediation obligations when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. Reasonable estimates involve management judgments based on a broad range of information and prior experience. These judgments are reviewed quarterly as more information is received and the amounts reserved are updated as necessary. Such estimated reserves may differ materially from the actual liability and such reserves may change materially as more information becomes available and estimated reserves are adjusted.

Regulatory Assets and Liabilities. Gas Utility and Electric Utility are subject to regulation by the PUC. In accordance with accounting guidance associated with rate-regulated entities, we record the effects of rate regulation in our financial statements as regulatory assets or regulatory liabilities. We continually assess whether the regulatory assets are probable of future recovery by evaluating the regulatory environment, recent rate orders and public statements issued by the PUC, and the status of any pending deregulation legislation. If future recovery of regulatory assets ceases to be probable, the elimination of those regulatory assets would adversely impact our results of operations and cash flows. As of September 30, 2009, our regulatory assets totaled $141.5 million. See Notes 2 and 8 to the Consolidated Financial Statements.

Depreciation and Amortization of Long-lived Assets. We compute depreciation on UGI Utilities’ property, plant and equipment on a straight-line basis over the average remaining lives of its various classes of depreciable property and on our other property, plant and equipment on a straight-line basis over estimated useful lives generally ranging from 2 to 40 years. We also use amortization methods and determine asset values of intangible assets other than goodwill using reasonable assumptions and projections. Changes in the estimated useful lives of property, plant and equipment and changes in intangible asset amortization methods or values could have a material effect on our results of operations. As of September 30, 2009, our net property, plant and equipment totaled $2,903.6 million and we recorded depreciation expense of $180.2 million during Fiscal 2009. As of September 30, 2009, our net intangible assets other than goodwill totaled $165.5 million and we recorded intangible amortization expense of $18.4 million during Fiscal 2009.

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

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

25

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

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

Newly Adopted and Recently Issued Accounting Pronouncements

See Note 3 to Consolidated Financial Statements for a discussion of the effects of recently adopted accounting guidance as well as recently issued accounting guidance not yet adopted.

26

EX-99.3

Exhibit 99.3

UGI CORPORATION AND SUBSIDIARIES

FINANCIAL INFORMATION

F-1

UGI CORPORATION

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT
SCHEDULES

	Pages
Management’s Report on Internal Control over Financial Reporting		F-3
Financial Statements:
Report of Independent Registered Public Accounting Firm		F-4
Consolidated Balance Sheets as of September 30, 2009 and 2008		F-5
Consolidated Statements of Income for the years ended September 30, 2009, 2008 and 2007		F-6
Consolidated Statements of Cash Flows for the years ended September 30, 2009, 2008 and 2007		F-7
Consolidated Statements of Changes in Stockholders’ Equity for the years ended September 30, 2009, 2008 and 2007		F-8
Consolidated Statements of Comprehensive Income for the years ended September 30, 2009, 2008 and 2007		F-9
Notes to Consolidated Financial Statements		F-10 - F-52
Financial Statement Schedules:
For the years ended September 30, 2009, 2008 and 2007:
I — Condensed Financial Information of Registrant (Parent Company)		S-1 to S-3
II — Valuation and Qualifying Accounts		S-4 to S-5

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

F-2

Report of Management

Financial Statements

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

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

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

Management’s Report on Internal Control over Financial Reporting

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

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

Based on its assessment, management has concluded that the Company maintained effective internal control over financial reporting as of September 30, 2009, based on the COSO Framework.

/s/ Lon R. Greenberg Chief Executive Officer

/s/ Peter Kelly Chief Financial Officer

/s/ Davinder S. Athwal Chief Accounting Officer

F-3

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of UGI Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of UGI Corporation and its subsidiaries at September 30, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2009 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 exhibit 99.3 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, 2009 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, effective October 1, 2009, the Company adopted new accounting guidance regarding the accounting for and presentation of noncontrolling interests. Also, as discussed in Note 3 to the consolidated financial statements, the Company has adopted new accounting guidance for uncertain tax positions effective October 1, 2007.

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 LLP
Philadelphia, Pennsylvania
November 20, 2009 except with respect to our opinion on the consolidated financial statements
insofar as it relates to the effects of the change in accounting for the noncontrolling interests
discussed in Note 3, as to which the date is May 26, 2010.

F-4

UGI CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Millions of dollars)

	September 30,
	2009			2008
ASSETS
Current assets
Cash and cash equivalents	$	280.1		$	245.2
Restricted cash		7.0			70.3
Accounts receivable (less allowances for doubtful accounts of $38.3 and $40.8, respectively)		405.9			488.0
Accrued utility revenues		21.0			20.8
Inventories		363.2			400.8
Deferred income taxes		34.5			27.5
Utility regulatory assets		19.6			16.0
Derivative financial instruments		20.3			12.7
Prepaid expenses and other current assets		33.5			57.3
Total current assets		1,185.1			1,338.6
Property, plant and equipment
Utilities		2,056.9			1,669.0
Non-utility		2,635.5			2,295.6
		4,692.4			3,964.6
Accumulated depreciation and amortization		(1,788.8	)		(1,515.1	)
Net property, plant, and equipment		2,903.6			2,449.5
Goodwill		1,582.3			1,489.7
Intangible assets, net		165.5			155.0
Other assets		206.1			252.2
Total assets	$	6,042.6		$	5,685.0
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	94.5		$	81.8
Bank loans		163.1			136.4
Accounts payable		334.9			461.8
Employee compensation and benefits accrued		89.9			76.3
Deposits and advances		159.6			164.8
Derivative financial instruments		37.5			103.2
Other current liabilities		217.8			159.9
Total current liabilities		1,097.3			1,184.2
Debt and other liabilities
Long-term debt		2,038.6			1,987.3
Deferred income taxes		504.9			491.0
Deferred investment tax credits		5.7			6.0
Other noncurrent liabilities		579.3			439.6
Total liabilities		4,225.8			4,108.1
Commitments and contingencies (note 15)
Equity
UGI Corporation stockholders’ equity
UGI Common Stock, without par value (authorized — 300,000,000 shares; issued — 115,261,294 and 115,247,694 shares, respectively)		875.6			858.3
Retained earnings		804.3			630.9
Accumulated other comprehensive loss		(38.9	)		(15.2	)
Treasury stock, at cost		(49.6	)		(56.3	)
Total UGI Corporation stockholders’ equity		1,591.4			1,417.7
Noncontrolling interests, principally in AmeriGas Partners		225.4	(1)		159.2	(1)
Total equity		1,816.8	(1)		1,576.9	(1)
Total liabilities and equity	$	6,042.6		$	5,685.0

(1) 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.

F-5

UGI CORPORATION AND SUBSIDIARIES

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

	Year Ended September 30,
	2009			2008			2007
Revenues
Utilities	$	1,379.5		$	1,277.5		$	1,166.8
Non-utility and other		4,358.3			5,370.7			4,310.1
		5,737.8			6,648.2			5,476.9
Costs and Expenses
Cost of sales (excluding depreciation shown below):
Utilities		944.8			915.4			809.2
Non-utility and other		2,725.8			3,829.2			2,921.6
Operating and administrative expenses		1,220.0			1,157.3			1,055.8
Utility taxes other than income taxes		16.9			18.3			17.7
Depreciation		180.2			163.8			150.6
Amortization		20.7			20.6			18.6
Other income, net		(55.9	)		(41.6	)		(77.9	)
		5,052.5			6,063.0			4,895.6
Operating income		685.3			585.2			581.3
Loss from equity investees		(3.1	)		(2.9	)		(3.8	)
Interest expense		(141.1	)		(142.5	)		(139.6	)
Income before income taxes		541.1			439.8			437.9
Income taxes		(159.1	)		(134.5	)		(126.7	)
Net income		382.0	(1)		305.3	(1)		311.2	(1)
Less: net income attributable to noncontrolling interests, principally in AmeriGas Partners		(123.5)	(1)		(89.8)	(1)		(106.9)	(1)
Net income attributable to UGI Corporation	$	258.5	(1)	$	215.5	(1)	$	204.3	(1)
Earnings per common share attributable to UGI Corporation stockholders:
Basic	$	2.38		$	2.01		$	1.92
Diluted	$	2.36		$	1.99		$	1.89
Average common shares outstanding (millions):
Basic		108.523			107.396			106.451
Diluted		109.339			108.521			107.941

(1) 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.

F-6

UGI CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of dollars)

	Year Ended September 30,
	2009			2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	382.0	(1)	$	305.3	(1)	$	311.2	(1)
Reconcile to net cash provided by operating activities:
Depreciation and amortization		200.9			184.4			169.2
Gains on sales of Partnership storage facilities		(39.9	)		—			(46.1	)
Deferred income taxes, net		26.8			(0.9	)		27.1
Provision for uncollectible accounts		34.1			37.1			26.7
Stock-based compensation expense		11.4			11.8			9.1
Net change in settled accumulated other comprehensive income		(21.0	)		(3.8	)		21.5
Other, net		17.4			(8.6	)		(0.3	)
Net change in:
Accounts receivable and accrued utility revenues		79.5			(22.2	)		(80.5	)
Inventories		67.0			(42.3	)		(9.1	)
Utility deferred fuel costs, net of changes in unsettled derivatives		10.3			21.5			(25.7	)
Accounts payable		(146.1	)		(6.0	)		30.3
Other current assets		30.3			(28.5	)		4.6
Other current liabilities		12.3			16.6			18.2
Net cash provided by operating activities		665.0			464.4			456.2
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(301.7	)		(232.1	)		(223.1	)
Acquisitions of businesses, net of cash acquired		(322.6	)		(1.3	)		(78.8	)
Net (costs of) proceeds from disposals of assets		(0.1	)		11.9			3.2
Net proceeds from sales of Partnership LPG storage facilities		42.4			—			49.0
PG Energy acquisition working capital adjustment		—			—			23.7
Decrease (increase) in restricted cash		63.3			(57.5	)		1.4
Other, net		(1.2	)		(10.5	)		0.8
Net cash used by investing activities		(519.9	)		(289.5	)		(223.8	)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock		(85.1	)		(80.9	)		(76.8	)
Distributions on AmeriGas Partners publicly held Common Units		(90.4	)		(80.9	)		(85.0	)
Issuances of debt		118.0			34.0			20.0
Repayments of debt		(82.2	)		(15.7	)		(30.6	)
Increase (decrease) in bank loans		13.1			(60.9	)		(27.6	)
Issuances of UGI Common Stock		10.8			20.9			16.4
Other		1.2			3.4			5.1
Net cash used by financing activities		(114.6	)		(180.1	)		(178.5	)
EFFECT OF EXCHANGE RATE CHANGES ON CASH		4.4			(1.4	)		11.7
Cash and cash equivalents increase (decrease)	$	34.9		$	(6.6	)	$	65.6
Cash and cash equivalents:
End of year	$	280.1		$	245.2		$	251.8
Beginning of year		245.2			251.8			186.2
Increase (decrease)	$	34.9		$	(6.6	)	$	65.6
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for:
Interest	$	136.3		$	144.9		$	124.7
Income taxes	$	130.2		$	134.8		$	93.5

(1) 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.

F-7

UGI CORPORATION AND SUBSIDIARIES

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

	Year Ended September 30,
	2009			2008			2007
Common stock, without par value
Balance, beginning of year	$	858.3		$	831.6		$	807.5
Common stock issued:
Employee and director plans		2.9			11.2			10.2
Dividend reinvestment plan		1.6			1.7			1.6
Excess tax benefits realized on equity-based compensation		2.9			3.4			3.7
Stock-based compensation expense		9.9			10.4			8.6
Balance, end of year	$	875.6		$	858.3		$	831.6
Retained earnings
Balance, beginning of year	$	630.9		$	497.5		$	370.0
Net income attributable to UGI Corporation		258.5	(1)		215.5	(1)		204.3	(1)
Cumulative effect from initial adoption of new accounting for uncertain tax positions		—			(1.2	)		—
Cash dividends on Common Stock ($0.785, $0.755 and $0.723 per share, respectively)		(85.1	)		(80.9	)		(76.8	)
Balance, end of year	$	804.3		$	630.9		$	497.5
Accumulated other comprehensive (loss) income
Balance, beginning of year	$	(15.2	)	$	57.7		$	(3.8	)
Net loss on derivative instruments, net of tax		(127.3	)		(34.9	)		(11.1	)
Reclassification of net losses (gains) on derivative instruments, net of tax		116.2			(3.1	)		30.1
Benefit plans, principally actuarial losses, net of tax		(44.4	)		(28.5	)		—
Reclassification of benefit plans actuarial losses and prior service costs, net of tax		2.3			0.2			—
Foreign currency translation adjustments, net of tax		29.5			(6.6	)		53.7
Adjustments to initially apply new accounting for pensions and postretirement benefits, net of tax		—			—			(11.2	)
Balance, end of year	$	(38.9	)	$	(15.2	)	$	57.7
Treasury stock
Balance, beginning of year	$	(56.3	)	$	(64.9	)	$	(74.1	)
Common stock issued:
Employee and director plans		5.9			8.1			8.5
Dividend reinvestment plan		0.8			0.5			0.7
Balance, end of year	$	(49.6	)	$	(56.3	)	$	(64.9	)
Total UGI Corporation stockholders’ equity	$	1,591.4		$	1,417.7		$	1,321.9
Noncontrolling interests
Balance, beginning of year	$	159.2		$	192.2		$	139.5
Net income attributable to noncontrolling interests, principally in AmeriGas Partners		123.5			89.8			106.9
Net (loss) gain on derivative instruments		(76.8	)		(14.5	)		14.6
Reclassification of net losses (gains) on derivative instruments		108.8			(29.8	)		11.6
Dividends and distributions		(91.7	)		(80.9	)		(85.0	)
Transactions with owners		0.8			2.7			2.8
Other		1.6			(0.3	)		1.8
Balance, end of year	$	225.4		$	159.2		$	192.2
Total equity	$	1,816.8		$	1,576.9		$	1,514.1

(1) 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.

F-8

UGI CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of dollars)

	Year Ended September 30,
	2009			2008			2007
Net income	$	382.0	(1)	$	305.3	(1)	$	311.2	(1)
Net (loss) gain on derivative instruments (net of tax of $82.1, $21.6 and $7.6, respectively)		(204.1	)		(49.4	)		3.5
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(78.6), $2.1 and $(20.8), respectively)		225.0			(32.9	)		41.7
Foreign currency translation adjustments (net of tax of $(8.4), $1.2 and $(9.4), respectively)		29.5			(6.6	)		53.7
Benefit plans (net of tax of $31.1 and $20.3, respectively)		(44.4	)		(28.5	)		—
Reclassification of benefit plans actuarial losses and prior service costs (net of tax of $(1.6) and $(0.1), respectively)		2.3			0.2			—
Cumulative effect from initial adoption of new accounting for uncertain tax positions		—			(1.2	)		—
Adjustments to initially apply new accounting for pensions and postretirement benefits (net of tax of $7.7)		—			—			(11.2	)
Comprehensive income		390.3			186.9			398.9
Less: comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners		(155.5	)		(45.5	)		(133.1	)
Comprehensive income attributable to UGI Corporation	$	234.8		$	141.4		$	265.8

(1) 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.

F-9

UGI Corporation and Subsidiaries

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

Index to Notes

Note 1 — Nature of Operations

Note 2 — Significant Accounting Policies

Note 3 — Accounting Changes

Note 4 — Acquisitions and Dispositions

Note 5 — Debt

Note 6 — Income Taxes

Note 7 — Employee Retirement Plans

Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters

Note 9 — Inventories

Note 10 — Property, Plant and Equipment

Note 11 — Goodwill and Intangible Assets

Note 12 — Series Preferred Stock

Note 13 — Common Stock and Equity-Based Compensation

Note 14 — Partnership Distributions

Note 15 — Commitments and Contingencies

Note 16 — Fair Value Measurements

Note 17 — Disclosures About Derivative Instruments, Hedging Activities and Other Financial Instruments

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”), incorporated in Pennsylvania in 1991, 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) energy marketing and services businesses. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in France, central and eastern 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 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, 2009, the General Partner held a 1% general partner interest and 42.9% 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 56.1% interest in AmeriGas Partners comprises 32,355,179 Common Units held by the general public as limited partner interests.

Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries (1) conducts an LPG distribution business in France (“Antargaz”); (2) conducts an LPG distribution business in central and eastern Europe (“Flaga”); and (3) participates in an LPG joint-venture business in the Nantong region of China. We refer to our foreign operations collectively as “International Propane.” Through other subsidiaries, Enterprises also conducts an energy marketing and services business primarily in the Mid-Atlantic region of the United States (collectively, “Energy Services”). Energy Services’ wholly owned subsidiary, UGI Development Company (“UGID”), owns interests in electricity generation facilities located in Pennsylvania.

F-10

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

Our natural gas and electric distribution utility businesses are conducted through our wholly owned subsidiary UGI Utilities, Inc. (“UGI Utilities”) and its subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania. 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, revenue, 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. In addition, the consolidated financial statements have been adjusted in accordance with the Financial Accounting Standard Board’s (“FASB’s”) guidance regarding the presentation of noncontrolling interests in consolidated subsidiaries (see Note 3).

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, 2009. Investments in business entities that are not publicly traded and where we hold less than 20% of voting rights are accounted for using the cost method. Such investments are recorded in other assets and totaled $55.0 and $53.2 at September 30, 2009 and 2008, 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 on regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulator.

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

F-11

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

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally 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 contracts.

• 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 and financial transmission rights (“FTRs”).

• 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, 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 the 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.

Substantially all 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, are included in deferred fuel costs 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 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.

F-12

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

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

Foreign Currency Translation

Balance sheets of international subsidiaries and our investments in international LPG joint ventures 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. Where the local currency is not the functional currency, translation adjustments are recorded in net income.

Revenue Recognition

Revenues from the sale of LPG are recognized principally upon delivery. Energy Services 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’ 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 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 partnerships’ 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 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.

F-13

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

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

Earnings Per Common Share

Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2009, Fiscal 2008 and Fiscal 2007:

	2009		2008		2007
(Millions of shares)
Average common shares outstanding for basic computation		108.523		107.396		106.451
Incremental shares issuable for stock options and common stock awards		0.816		1.125		1.490
Average common shares outstanding for diluted computation		109.339		108.521		107.941

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 subsequent to the adoption of FASB guidance regarding employers’ accounting for defined benefit pension and postretirement plans effective September 30, 2007, and foreign currency translation adjustments. Fiscal 2007 other comprehensive income also includes an after-tax charge of $11.2 associated with the initial adoption of the new guidance for employers accounting for defined benefit pension and postretirement plans (see “Accounting Changes” below).

The components of AOCI at September 30, 2009 and 2008 follow:

							Foreign
				Derivative			Currency
	Postretirement			Instruments Net			Translation
	Benefit Plans			Losses			Adjustments		Total
Balance, September 30, 2009	$	(81.5	)	$	(53.6	)	$	96.2	$	(38.9	)
Balance, September 30, 2008	$	(39.4	)	$	(42.5	)	$	66.7	$	(15.2	)

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 brokerage accounts which are restricted from withdrawal.

Inventories

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

F-14

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

Property, Plant and Equipment and Related Depreciation

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

We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives generally ranging from 15 to 40 years for buildings and improvements; 7 to 40 years for storage and customer tanks and cylinders; 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 method 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 2.4% in Fiscal 2009 and Fiscal 2008, and 2.7% in Fiscal 2007. Depreciation expense as a percentage of the related average depreciable base for Electric Utility was 2.9% in Fiscal 2009, 2.6% in Fiscal 2008 and 2.7% in Fiscal 2007. 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 2009, Fiscal 2008 or Fiscal 2007.

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

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 2009, Fiscal 2008 or Fiscal 2007.

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 $230.3 and $223.4 at September 30, 2009 and 2008, respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms.

Environmental Matters

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

F-15

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

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

FASB Accounting Standards Codification. In June 2009, the FASB issued guidance identifying the sources of accounting principles and the framework for selecting principles used in the preparation of financial statements by nongovernmental entities in accordance with GAAP. The guidance has established the FASB Accounting Standards Codification (“Codification”) as the source of such authoritative accounting principles. The identification of the Codification as the source of authoritative accounting principles does not change existing GAAP. The Codification is effective for all financial statements issued after September 15, 2009.

F-16

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

Subsequent Events. On June 30, 2009, we adopted accounting guidance issued by the FASB in May 2009 on accounting and disclosure of subsequent events. The adoption of this guidance did not change our prior accounting practice other than to disclose the date through which subsequent events were evaluated and the basis for that date. Other than this new disclosure, adoption of this guidance did not have a significant impact on our consolidated financial statements.

Other-Than-Temporary Impairments. On June 30, 2009, we adopted accounting guidance issued by the FASB in April 2009 on the recognition and presentation of other-than temporary impairments. Under this guidance, to assess whether an other-than-temporary impairment exists for a debt security, an entity must (1) evaluate the likelihood of liquidating the debt security prior to recovering its cost basis and (2) determine if any impairment of the debt security is related to credit losses. In addition, the guidance requires enhanced disclosures of other-than-temporary impairments on debt and equity securities in the financial statements. Recognition and measurement guidance for other-than-temporary impairments of equity securities is not amended by this guidance. Adoption of this guidance did not have a material impact on our consolidated financial statements.

Disclosures about Derivative Instruments and Hedging Activities. Effective with our disclosures for the quarter ended March 31, 2009, we adopted accounting guidance issued by the FASB in March 2008 on enhanced disclosures about derivative instruments and hedging activities. The enhanced disclosures provide greater transparency by requiring entities to provide qualitative disclosures about their objectives and strategies for using derivative instruments and quantitative disclosures that detail the fair value amounts of, and gains and losses on, derivative instruments. Disclosures about credit risk-related contingent features of derivative instruments are also required. See Note 17 for disclosures required by the new guidance.

Fair Value Measurements. On October 1, 2008, we adopted new guidance issued by the FASB in September 2006 on fair value measurements. The new guidance defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. In February 2008, the FASB issued two amendments to this guidance to exclude leases from the new fair value guidance and to delay the effective date of the new fair value guidance until fiscal years beginning after November 15, 2008 (Fiscal 2010) for non-financial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a non-recurring basis. The adoption of the initial phase of the fair value guidance did not have a material effect on our financial statements and we do not anticipate that the adoption of the remainder of the fair value guidance will have a material effect on our consolidated financial statements. In October 2008, the FASB issued two additional amendments to the fair value guidance which clarify the application of the fair value measurement guidance to financial assets in a market that is not active and when the volume and level of activity for the asset or liability have significantly decreased. These further amendments did not have an impact on our results of operations or financial condition. See Notes 2 and 16 for further information on fair value measurements in accordance with the new guidance.

Offsetting of Amounts Related to Certain Contracts. On October 1, 2008, we adopted accounting guidance issued by the FASB in April 2007 which permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. In addition, upon the adoption, companies are permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements. The new guidance requires retrospective application for all periods presented. We have elected to continue our policy of reflecting derivative asset or liability positions, as well as cash collateral, on a gross basis in our Consolidated Balance Sheets. Accordingly, the adoption of the new guidance did not impact our financial statements.

Fair Value Option for Financial Assets and Liabilities. On October 1, 2008, we adopted accounting guidance issued by the FASB in February 2007 by which we may elect to report individual financial instruments and certain items at fair value with changes in fair value reported in earnings. Once made, this election is irrevocable for those items. The adoption of this guidance did not impact our financial statements.

Uncertainty in Income Taxes. Effective October 1, 2007, we adopted new interpretive guidance issued by the FASB on accounting for uncertainty related to income taxes. The new guidance provides a comprehensive model for the recognition, measurement and disclosure in financial statements of uncertain income tax positions that a company has taken or expects to take on a tax return. The cumulative effect from the adoption of the new guidance was recorded as a $1.2 decrease to the October 1, 2007 retained earnings balance.

F-17

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

Pension and Postretirement Plans. Effective September 30, 2007, we adopted new accounting guidance issued by the FASB relating to employers’ accounting for pension and postretirement benefit plans. The new guidance requires recognition of an asset or liability in the statement of financial position reflecting the funded status of pension and postretirement benefit plans, such as retiree health and life, with current year changes recognized in shareholders’ equity. The new guidance did not change the existing criteria for measurement of periodic benefit costs, plan assets or benefit obligations. The incremental effect of the initial adoption of the new guidance reduced UGI Corporation stockholders’ equity at September 30, 2007 by $11.2.

Noncontrolling Interests. In December 2007, the FASB issued guidance regarding the accounting for and presentation of noncontrolling interests in consolidated financial statements. The new guidance significantly changes the accounting and reporting relating to noncontrolling interests in a consolidated subsidiary. Upon adoption, noncontrolling interests are classified as a component of equity, a change from its previous classification between liabilities and stockholders’ equity, and earnings attributable to noncontrolling interests is included in net income, although such earnings are still deducted to measure net income attributable to UGI Corporation and earnings per share. 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 is measured at fair value.

The new guidance is effective for financial statements issued for fiscal years beginning after December 15, 2008 and must be applied prospectively except for the presentation and disclosure requirements which must be applied retrospectively for all periods presented. Accordingly, we adopted the new guidance on October 1, 2009. The adoption of the new guidance resulted in an increase in total equity of $225.4 on our opening Fiscal 2010 Consolidated Balance Sheet. All prior period financial information has been adjusted to conform to the new presentation guidance. In addition to the effects on the consolidated financial statements described above, the adoption of the new accounting guidance for noncontrolling interests also affects disclosure of amounts provided in Notes 6, 20 and 21 to these consolidated financial statements.

New Accounting Standards Not Yet Implemented

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). We are currently evaluating the provisions of the new guidance.

Enhanced Disclosures of Postretirement Plan Assets. In December 2008, the FASB issued new 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. The provisions of this guidance are effective for fiscal years ending after December 15, 2009 (Fiscal 2010). Because this new guidance relates to disclosure only, it will not impact the financial statements.

Intangible Asset Useful Lives. In April 2008, the FASB issued new 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 is effective for financial statements issued for fiscal years beginning after December 15, 2008 (Fiscal 2010) and must be applied prospectively to intangible assets acquired after the effective date. We do not believe the new guidance will have a significant impact on our financial statements.

Business Combinations. In December 2007, the FASB issued new guidance on the 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 the first annual reporting period beginning on or after December 15, 2008 (Fiscal 2010). Among the more significant changes in accounting for acquisitions are (1) transaction costs will generally be expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, will generally be 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 will be recognized in operations (rather than decreases in goodwill). Generally, the effects of the new guidance will depend on future acquisitions.

F-18

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

Note 4 — Acquisitions & Dispositions

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 for cash consideration of $32 plus estimated working capital of $1.6. 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 of 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 Sheet at September 30, 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. Also during Fiscal 2009, UGI Utilities and AmeriGas OLP reached an agreement on the working capital adjustment associated with UGI Utilities’ sale of the assets of CPP to AmeriGas OLP pursuant to which UGI Utilities reimbursed AmeriGas OLP $1.4.

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	$	22.7
Property, plant and equipment		236.1
Goodwill		36.8
Utility regulatory assets		22.5
Other assets		12.5
Noncurrent liabilities		(34.4	)
Total	$	296.2

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

The operating results of CPG and CPP are included in our consolidated results beginning October 1, 2008. 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:

	2008
	(pro forma)
Revenues	$	6,867.6
Net income attributable to UGI Corporation	$	224.4
Earnings per share:
Basic	$	2.09
Diluted	$	2.07

F-19

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

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 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.

In July 2007, AmeriGas OLP sold its 3.5 million barrel liquefied petroleum gas storage terminal located near Phoenix, Arizona to Plains LPG Services, L.P. The Partnership recorded a pre-tax gain of $46.1 which amount is included in “Other income, net” in the Fiscal 2007 Consolidated Statement of Income. The gain increased Fiscal 2007 net income attributable to UGI Corporation by $12.5 or $0.12 per diluted share.

During Fiscal 2009, in addition to the acquisition of the assets of CPP described above, AmeriGas OLP acquired several retail propane distribution businesses for total cash consideration of $17.9. During Fiscal 2008, AmeriGas OLP acquired several retail propane distribution businesses for total cash consideration of $2.5. During Fiscal 2007, AmeriGas OLP acquired several retail propane distribution businesses, including the retail distribution businesses of All Star Gas Corporation and Shell Gas (LPG) USA and several cylinder refurbishing businesses, for total cash consideration of $79.6 and the issuance of 166,205 Common Units to the General Partner having a fair value of $5.7. Also during Fiscal 2007, UGI Utilities received a $23.7 working capital adjustment payment associated with its Fiscal 2006 acquisition of Southern Union Company’s PG Energy Division, a natural gas distribution utility located in northeastern Pennsylvania (now PNG Gas).

F-20

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

Note 5 — Debt

Long-term debt comprises the following at September 30:

	2009			2008
AmeriGas Propane:
AmeriGas Partners Senior Notes:
8.875%, due May 2011	$	14.7		$	14.7
7.25%, due May 2015		415.0			415.0
7.125%, due May 2016		350.0			350.0
AmeriGas OLP First Mortgage Notes:
Series D, 7.11%, due March 2009		—			70.2
Series E, 8.50%, due July 2010		80.0			80.1
Other		5.9			3.4
Total AmeriGas Propane		865.6			933.4
International Propane:
Antargaz Senior Facilities term loan, due March 2011		556.1			534.9
Flaga term loan, due through September 2011		43.9			50.7
Flaga term loan, due through June 2014		10.2			—
Other		3.6			3.9
Total International Propane		613.8			589.5
UGI Utilities:
Senior Notes:
6.375% Notes, due September 2013		108.0			—
5.75% Notes, due October 2016		175.0			175.0
6.21% Notes, due October 2036		100.0			100.0
Medium-Term Notes:
5.53% Notes, due September 2012		40.0			40.0
5.37% Notes, due August 2013		25.0			25.0
5.16% Notes, due May 2015		20.0			20.0
7.37% Notes, due October 2015		22.0			22.0
5.64% Notes, due December 2015		50.0			50.0
6.17% Notes, due June 2017		20.0			20.0
7.25% Notes, due November 2017		20.0			20.0
5.67% Notes, due January 2018		20.0			20.0
6.50% Notes, due August 2033		20.0			20.0
6.13% Notes, due October 2034		20.0			20.0
Total UGI Utilities		640.0			532.0
Other		13.7			14.2
Total long-term debt		2,133.1			2,069.1
Less current maturities		(94.5	)		(81.8	)
Total long-term debt due after one year	$	2,038.6		$	1,987.3

Scheduled principal repayments of long-term debt due in fiscal years 2010 to 2014 follow:

	2010		2011		2012		2013		2014
AmeriGas Propane	$	82.2	$	15.8	$	1.0	$	0.9	$	0.5
UGI Utilities		—		—		40.0		133.0		—
International Propane and Other		12.3		594.7		3.0		2.7		2.6
Total	$	94.5	$	610.5	$	44.0	$	136.6	$	3.1

F-21

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

AmeriGas Propane

AmeriGas Partners Senior Notes. The 8.875% Senior Notes may be redeemed at our option. The 7.25% and 7.125% Senior Notes generally cannot be redeemed at our option prior to May 20, 2010 and 2011, respectively. 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 First Mortgage Notes. The General Partner is co-obligor of the Series E First Mortgage Notes. AmeriGas OLP may prepay the Series E First Mortgage Notes, in whole or in part. These prepayments include a make whole premium. AmeriGas OLP 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 the Series E First Mortgage Notes, in whole or in part.

AmeriGas OLP Credit Agreements. AmeriGas OLP has a credit agreement (“AmeriGas Credit Agreement”) consisting of (1) a Revolving Credit Facility and (2) an Acquisition Facility. The General Partner and Petrolane Incorporated, a wholly owned subsidiary of the General Partner, are guarantors of amounts outstanding under the AmeriGas 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 AmeriGas OLP First Mortgage Notes and 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. There were no borrowings outstanding under AmeriGas OLP’s Revolving Credit Facility at September 30, 2009 and 2008. Issued and outstanding letters of credit, which reduce available borrowings under the AmeriGas OLP Revolving Credit Facility, totaled $37.0 and $42.9 at September 30, 2009 and 2008, respectively. The 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 AmeriGas OLP First Mortgage Notes and the Senior Notes indentures. The Acquisition Facility operates as a revolving facility through October 15, 2011, at which time amounts then outstanding will be immediately due and payable. There were no amounts outstanding under the Acquisition Facility at September 30, 2009 and 2008.

The Revolving Credit Facility and the Acquisition Facility permit 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, 2009), 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.

In order to provide for increased liquidity, on April 17, 2009, AmeriGas OLP entered into a $75 unsecured revolving credit facility (“2009 AmeriGas Supplemental Credit Agreement”) with three major banks. The 2009 AmeriGas Supplemental Credit Agreement expires on July 1, 2010 and permits AmeriGas OLP to borrow up to $75 for working capital and general purposes subject to restrictive covenants in the AmeriGas OLP First Mortgage Notes and 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, 2009), or a libor market index rate (0.25% at September 30, 2009) plus 1%, or at a one-week, two-week or one-month Eurodollar rate, as defined in the AmeriGas Supplemental Credit Agreement, plus a margin. The margin on base rate loans is 2.25% and the margin on Eurodollar loans is 3.25%.

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, 2009, 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).

F-22

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

The AmeriGas OLP credit agreements and First Mortgage Notes 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 and First Mortgage Notes require that AmeriGas OLP maintain a maximum ratio of total indebtedness to EBITDA, as defined. In addition, the AmeriGas OLP credit agreements require that AmeriGas OLP maintain a minimum ratio of EBITDA to interest expense, as defined, and 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 five-year, floating rate Senior Facilities Agreement with a bank group comprising a €380 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 rate on Antargaz’ term loan at September 30, 2009 and 2008 was 3.94% and 4.40%, respectively. Antargaz’ revolving credit facility permits Antargaz to borrow up to €50 for working capital or general corporate purposes. Borrowings under its revolving credit facility are classified as bank loans on the Consolidated Balance Sheets. 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. There were no revolving credit facility borrowings outstanding at September 30, 2009. In order to minimize the interest margin it pays on its Senior Facilities Agreement borrowings, in September 2008 Antargaz borrowed €50 ($70.4), the total amount available under its revolving credit facility at a weighted average interest rate of 6.0%. This amount was repaid on October 27, 2008. The Senior Facilities Agreement debt is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivable.

Flaga has two euro-based variable-rate term loans. The principal outstanding on the first term loan was €30 ($43.9) and €36 ($50.7) at September 30, 2009 and 2008, 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%. Generally, semi-annual principal payments of €3 on this term loan are due on March 31 and September 30 each year through Fiscal 2010 with final payments totaling €3.0, €6.4 and €14.6 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, 2009 and 2008 were 4.28% and 4.80%, respectively. Flaga may prepay this term loan, in whole or in part, without incurring any penalty.

The second euro-based variable-rate term loan, executed in August 2009, had an outstanding principal balance of €7 ($10.2) on September 30, 2009. 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%. Semi-annual principal payments of €0.7 on this term loan 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, 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 2010 that provides for borrowings and issuances of guarantees totaling €16 of which €2.1 ($3.0) was outstanding at September 30, 2009. Flaga also has an €8 euro-denominated working capital facility currently scheduled to expire in June 2010 of which €4.1 ($6.1) was outstanding at September 30, 2009. Issued and outstanding guarantees, which reduce available borrowings under the working capital facilities, totaled €2.7 ($3.9) at September 30, 2009 and €0.7 ($1.0) at September 30, 2008. 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 4.94% at September 30, 2009 and 4.52% at September 30, 2008.

F-23

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

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.

UGI Utilities

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 Utilities Revolving Credit Agreement, which we classify as bank loans, totaling $154 at September 30, 2009 and $57 at September 30, 2008. The weighted-average interest rates on UGI Utilities’ Revolving Credit Agreement borrowings at September 30, 2009 and 2008 were 0.59% and 5.0%, respectively. In conjunction with the October 1, 2008, CPG Acquisition, UGI made a $120 cash contribution to UGI Utilities on September 30, 2008. This cash contribution was used by UGI Utilities to reduce borrowings under the UGI Utilities Revolving Credit Agreement. On October 1, 2008, UGI Utilities borrowed under the UGI Utilities Revolving Credit Agreement to fund a portion of the CPG Acquisition.

Restrictive Covenants. UGI Utilities Revolving Credit Agreement requires UGI Utilities to maintain a maximum ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

Restricted Net Assets

At September 30, 2009, 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 $1,200.

Note 6 — Income Taxes

Income before income taxes comprises the following:

	2009		2008		2007
Domestic	$	431.7	$	380.5	$	385.3
Foreign		109.4		59.3		52.6
Total income before income taxes	$	541.1	$	439.8	$	437.9

The provisions for income taxes consist of the following:

	2009			2008			2007
Current expense:
Federal	$	69.6		$	92.4		$	65.6
State		21.6			26.1			17.4
Foreign		41.1			16.9			16.6
Total current expense		132.3			135.4			99.6
Deferred (benefit) expense:
Federal		27.6			(1.6	)		24.8
State		(1.1	)		(3.0	)		1.9
Foreign		0.7			4.1			0.8
Investment tax credit amortization		(0.4	)		(0.4	)		(0.4	)
Total deferred expense (benefit)		26.8			(0.9	)		27.1
Total income tax expense	$	159.1		$	134.5		$	126.7

Federal income taxes for Fiscal 2009, Fiscal 2008 and Fiscal 2007 are net of foreign tax credits of $34.9, $4.3 and $14.1, respectively.

F-24

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

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

	2009			2008			2007
Statutory federal tax rate		35.0	%		35.0	%		35.0	%
Difference in tax rate due to:
Noncontrolling interests, not subject to tax		(8.0	)		(7.1	)		(8.5	)
State income taxes, net of federal benefit		2.5			3.4			2.9
Effects of international operations		(0.3	)		(1.1	)		(1.0	)
Other, net		0.2			0.4			0.5
Effective tax rate		29.4	%		30.6	%		28.9	%

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

	2009			2008
Excess book basis over tax basis of property, plant and equipment	$	366.2		$	313.0
Investment in AmeriGas Partners		172.5			172.6
Intangible assets and goodwill		51.0			49.1
Utility regulatory assets		51.6			34.0
Foreign currency translation adjustment		21.4			13.0
Other		9.5			14.7
Gross deferred tax liabilities		672.2			596.4
Pension plan liabilities		(60.4	)		(21.7	)
Employee-related benefits		(37.6	)		(31.7	)
Operating loss carryforwards		(25.5	)		(22.1	)
Foreign tax credit carryforwards		(69.6	)		(43.6	)
Utility regulatory liabilities		(16.6	)		(3.7	)
Derivative financial instruments		(30.9	)		(33.6	)
Other		(49.0	)		(33.0	)
Gross deferred tax assets		(289.6	)		(189.4	)
Deferred tax assets valuation allowance		87.8			56.5
Net deferred tax liabilities	$	470.4		$	463.5

At September 30, 2009, foreign net operating loss carryforwards principally relating to Flaga and certain operations of Antargaz totaled $36.8 and $7.6, respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to four non-operating subsidiaries which approximate $119.8 and expire through 2029. We also have operating loss carryforwards of $6.5 for certain operations of AmeriGas Propane that expire through 2029. At September 30, 2009, deferred tax assets relating to operating loss carryforwards include $8.2 for Flaga, $2.6 for Antargaz, $1.0 for UGI International (BV), $2.3 for AmeriGas Propane and $11.4 for certain other subsidiaries. A valuation allowance of $14.6 has been provided for all 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 $3.6 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.

F-25

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

We have foreign tax credit carryforwards of approximately $69.6 expiring through 2020 resulting from the actual and planned repatriation of Antargaz’ accumulated earnings since acquisition includable in U.S. taxable income. Because we expect that these credits will expire unused, a valuation allowance has been provided for the entire foreign tax credit carryforward amount. The valuation allowance for all deferred tax assets increased by $31.3 in Fiscal 2009, due primarily to an increase in the foreign tax credit carryforward of $26.0.

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 2006 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 2001 to 2006. UGI Corporation’s federal income tax return for Fiscal 2007 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 audit of our Fiscal 2007 U.S. federal income tax return will likely be completed during Fiscal 2010. 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. The state impact of any amended U.S. federal income tax return remains subject to examination by various states for a period of up to one year after formal notification to the states of such U.S. federal tax return amendments.

As of September 30, 2009, we have unrecognized income tax benefits totaling $2.3 including related accrued interest of $0.2. If these unrecognized tax benefits were subsequently recognized, $2.2 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 $0.9.

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

Balance at October 1, 2007	$	4.3
Additions for tax positions of the current year		0.7
Additions for tax positions of prior years		0.7
Settlements with tax authorities		(0.8	)
Balance at September 30, 2008		4.9
Additions for tax positions of the current year		0.5
Additions for tax positions of prior years		0.3
Reductions as a result of tax positions taken in prior years		(1.2	)
Settlements with tax authorities		(2.2	)
Balance at September 30, 2009	$	2.3

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 postretirement life insurance benefits to nearly all domestic active and retired employees. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related to the Antargaz plans, such amounts are not material.

Effective December 31, 2008, we merged two of our domestic defined benefit pension plans. As a result of the merger, we were required under GAAP to remeasure the combined plan’s assets and benefit obligations as of December 31, 2008 and we recorded an after-tax charge to AOCI of $38.7 to reflect the underfunded position of the merged plan at December 31, 2008. As a result of the remeasurement, Fiscal 2009 pension expense increased approximately $4.2 in the period subsequent to the measurement principally as a result of the amortization of actuarial losses.

F-26

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

The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the 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, 2009 and 2008. ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation.

	Pension						Other Postretirement
	Benefits						Benefits
	2009			2008			2009			2008
Change in benefit obligations:
Benefit obligations — beginning of year	$	310.9		$	310.4		$	15.6		$	20.1
Service cost		7.1			6.1			0.3			0.5
Interest cost		23.3			19.6			1.2			1.2
Actuarial loss (gain)		67.0			(10.0	)		2.2			(2.5	)
Acquisitions		44.5			—			3.4			—
Plan amendments		0.1			—			—			(0.4	)
Plan settlement or curtailment		(5.7	)		—			—			(2.2	)
Foreign currency		0.1			(0.1	)		0.1			—
Benefits paid		(18.4	)		(15.1	)		(1.4	)		(1.1	)
Benefit obligations — end of year	$	428.9		$	310.9		$	21.4		$	15.6
Change in plan assets:
Fair value of plan assets — beginning of year	$	244.7		$	294.0		$	10.0		$	12.2
Actual gain (loss) on plan assets		15.0			(34.7	)		—			(1.8	)
Acquisitions		38.4			—			—			—
Foreign currency		0.1			—			—			—
Employer contributions		5.7			0.5			1.1			0.7
Settlement payments		(5.7	)		—			—			—
Benefits paid		(18.4	)		(15.1	)		(1.4	)		(1.1	)
Fair value of plan assets — end of year	$	279.8		$	244.7		$	9.7		$	10.0
Funded status of the plans — end of year	$	(149.1	)	$	(66.2	)	$	(11.7	)	$	(5.6	)
Assets (liabilities) recorded in the balance sheet:
Prepaid assets (included in Other assets)	$	—		$	1.1		$	—		$	0.7
Unfunded liabilities (included in Other noncurrent liabilities)		(149.1	)		(67.3	)		(11.7	)		(6.3	)
Net amount recognized	$	(149.1	)	$	(66.2	)	$	(11.7	)	$	(5.6	)
Amounts recorded in UGI Corporation stockholders’ equity:
Net actuarial loss (gain)	$	133.2		$	64.6		$	(0.6	)	$	(1.2	)
Prior service (credit) cost		(0.2	)		(0.2	)		0.1			—
Total	$	133.0		$	64.4		$	(0.5	)	$	(1.2	)

In Fiscal 2010, we estimate that we will amortize $5.8 of net actuarial losses from UGI Corporation stockholders’ equity 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.

	Pension Plans												Other Postretirement Benefits
	2009			2008			2007			2006			2009			2008			2007			2006
Weighted-average assumptions:
Discount rate		5.5	%		6.8	%		6.4	%		6.0	%		5.5	%		6.8	%		6.4	%		6.0	%
Expected return on plan assets		8.5	%		8.5	%		8.5	%		8.5	%		5.5	%		5.5	%		5.5	%		5.6	%
Rate of increase in salary levels		3.8	%		3.8	%		3.8	%		3.8	%		3.8	%		3.8	%		3.8	%		3.8	%

F-27

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

The ABO for the Pension Plans was $377.7 and $272.4 as of September 30, 2009 and 2008, respectively.

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

	Pension Benefits									Postretirement Benefits
	2009			2008			2007			2009			2008			2007
Service cost	$	7.1		$	6.1		$	6.5		$	0.3		$	0.5		$	0.5
Interest cost		23.3			19.6			18.8			1.2			1.2			1.2
Expected return on assets		(25.7	)		(24.5	)		(23.5	)		(0.6	)		(0.7	)		(0.6	)
Curtailment gain		—			—			—			—			(2.2	)		—
Settlement loss		1.8			—			—			—			—			—
Amortization of:
Transition obligation		—			—			—			0.2			0.2			0.2
Prior service cost (benefit)		—			—			0.2			(0.4	)		(0.4	)		(0.3	)
Actuarial loss (gain)		3.8			0.1			1.1			(0.1	)		(0.1	)		—
Net benefit cost (income)		10.3			1.3			3.1			0.6			(1.5	)		1.0
Change in associated regulatory liabilities		—			—			—			3.3			3.4			3.1
Net benefit cost after change in regulatory liabilities	$	10.3		$	1.3		$	3.1		$	3.9		$	1.9		$	4.1

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. We did not make any contributions to the Pension Plans in Fiscal 2009, Fiscal 2008 or Fiscal 2007. In conjunction with the settlement of obligations under a subsidiary retirement benefit plan, Antargaz made a settlement payment of approximately €4.1 ($5.7) during Fiscal 2009. We believe that we will be required to make contributions to the Pension Plans in Fiscal 2010 but such amounts are not expected to be material.

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 2010 are not expected to be material.

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

			Other
	Pension		Postretirement
	Benefits		Benefits
Fiscal 2010	$	19.2	$	2.0
Fiscal 2011		19.5		2.0
Fiscal 2012		20.8		2.0
Fiscal 2013		21.7		1.9
Fiscal 2014		23.1		1.9
Fiscal 2015 — 2019		137.0		9.5

F-28

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

In accordance with our investment strategy to obtain long-term growth, our target asset allocations are to maintain a mix of 65% equities and the remainder in fixed income funds or cash equivalents in the Pension Plans. The targets and actual allocations for the Pension Plans’ and VEBA trust assets at September 30 are as follows:

	Target						Pension Plan						VEBA
	Pension Plan			VEBA			2009			2008			2009			2008
Equities		65	%		65	%		68	%		63	%		64	%		57	%
Fixed income funds		35	%		35	%		32	%		37	%		30	%		34	%
Cash equivalents		N/A			0	%		N/A			N/A			6	%		9	%

UGI Common Stock comprised approximately 8% and 9% of Pension Plans’ assets at September 30, 2009 and 2008, respectively.

The assumed domestic health care cost trend rates are 8.0% for Fiscal 2010, 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 2009 postretirement benefit cost and obligation as follows:

	1% Increase		1% Decrease
Service and interest costs in Fiscal 2009	$	0.1	$	(0.1	)
ABO at September 30, 2009	$	1.0	$	(0.8	)

We also sponsor unfunded and non-qualified supplemental executive retirement plans. At September 30, 2009 and 2008, the PBOs of these plans were $20.7 and $17.5, respectively. We recorded net costs for these plans of $3.1 in Fiscal 2009, $3.0 in Fiscal 2008 and $2.4 in Fiscal 2007. These costs are not included in the tables above. Amounts recorded in UGI Corporation stockholders’ equity for these plans include after-tax losses of $4.2 and $2.6 at September 30, 2009 and 2008, respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $0.4 million of pre-tax actuarial losses in Fiscal 2010.

Defined Contribution Plans. We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for employer matching contributions at various rates. The cost of benefits under the savings plans totaled $10.1 in Fiscal 2009, $9.4 in Fiscal 2008 and $9.2 in Fiscal 2007.

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:

	2009		2008
Regulatory assets:
Income taxes recoverable	$	79.5	$	73.7
Postretirement benefits		2.5		4.3
CPG Gas pension and postretirement plans		8.5		—
Environmental costs		26.9		9.0
Deferred fuel costs		19.6		16.0
Other		4.5		4.4
Total regulatory assets	$	141.5	$	107.4
Regulatory liabilities:
Postretirement benefits	$	9.3	$	8.9
Environmental overcollections		8.7		—
Deferred fuel refunds		30.8		—
Total regulatory liabilities	$	48.8	$	8.9

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.

F-29

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

Postretirement benefits. The PUC has authorized UGI Utilities to recover certain early retirement benefit costs as well as other postretirement benefit costs incurred prior to such amounts being reflected in tariff rates. These costs are reflected as regulatory assets in the table above. At September 30, 2009, UGI Utilities expects to recover these costs over periods ranging from 1 to approximately 10 years.

Gas Utility and Electric Utility are also 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. In addition, in accordance with GAAP relating to pension and postretirement plans, UGI Utilities’ postretirement regulatory liability is adjusted annually to reflect changes in the funded status of UGI Gas’ and Electric Utility’s postretirement benefit plan.

CPG Gas pension and postretirement plans. This regulatory asset represents the portion of prior service cost and net actuarial losses associated with CPG Gas pension and postretirement plans that will be 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 life expectancy of the plan participants. These regulatory assets are reflected net of associated deferred income taxes.

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 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 such prudently incurred remediation costs. PNG Gas and CPG Gas are currently recovering and expect to continue to recover these costs in base rate revenues. At September 30, 2009, the period over which PNG Gas and CPG Gas expect to recover these costs will depend upon future remediation activity.

Deferred fuel costs and refunds. Gas Utility’s tariffs contain clauses which permit recovery of certain purchased gas costs through the application of purchased gas cost (“PGC”) rates. The clauses provide for periodic adjustments to PGC rates for the difference between the total amount of purchased gas costs collected from customers and the recoverable costs incurred. In accordance with GAAP relating to rate-regulated entities, we defer the difference between amounts recognized in revenues and the applicable gas costs incurred until they are subsequently billed or refunded to customers. Net undercollected gas 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 refunds or costs. Unrealized losses on such contracts at September 30, 2008 were $23.3. There were no such gains or losses at September 30, 2009. UGI Utilities expects to recover or refund deferred fuel costs generally over a period of 1 to 2 years.

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.

Other. Other regulatory assets comprise a number of items including, among others, deferred asset retirement costs, deferred rate case expenses, customer choice implementation costs and deferred software development costs. At September 30, 2009, UGI Utilities expects to recover these costs over periods of approximately 1 to 5 years.

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

F-30

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

Other Regulatory Matters

PNG and CPG Base Rate Filings. On January 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 provider of last resort (“POLR”) for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006.

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

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

Note 9 — Inventories

Inventories comprise the following at September 30:

	2009		2008
Non-utility LPG and natural gas	$	118.0	$	199.8
Gas Utility natural gas		189.7		155.9
Materials, supplies and other		55.5		45.1
Total inventories	$	363.2	$	400.8

At September 30, 2009 and 2008, UGI Utilities was a party to one-year storage contract administrative agreements (“SCAAs”) expiring on October 31, 2009 and 2008, respectively. Pursuant to the 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 term of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represent 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, 2009 and 2008 comprising 1.3 billion cubic feet (“bcf”) and 1.4 bcf of natural gas was $10.5 and $10.3, respectively. Effective November 1, 2009, UGI Utilities entered into three new SCAAs with terms ranging from one to three years.

F-31

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

Note 10 — Property, Plant and Equipment

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

	2009		2008
Utilities:
Distribution	$	1,813.2	$	1,520.3
Transmission		76.8		28.5
General and other		166.9		120.2
Total Utilities		2,056.9		1,669.0
Non-utility:
Land		96.0		81.8
Buildings and improvements		192.0		160.6
Transportation equipment		110.6		94.5
Equipment, primarily cylinders and tanks		1,970.6		1,762.7
Electric generation		119.8		84.9
Other		146.5		111.1
Total non-utility		2,635.5		2,295.6
Total property, plant and equipment	$	4,692.4	$	3,964.6

Note 11 — Goodwill and Intangible Assets

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

	2009			2008
Goodwill (not subject to amortization)	$	1,582.3		$	1,489.7
Other intangible assets:
Customer relationships, noncompete agreements and other	$	219.1		$	197.3
Trademark (not subject to amortization)		49.7			47.8
Gross carrying amount		268.8			245.1
Accumulated amortization		(103.3	)		(90.1	)
Net carrying amount	$	165.5		$	155.0

The increase in goodwill and other intangibles during Fiscal 2009 principally reflects the effects of foreign currency translation and acquisitions. 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 $18.4 in Fiscal 2009, $18.8 in Fiscal 2008 and $16.9 in Fiscal 2007. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2010 — $17.2; Fiscal 2011 — $16.8; Fiscal 2012 — $16.7; Fiscal 2013 — $16.1; Fiscal 2014 — $14.2.

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, 2009 or 2008.

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, 2009 and 2008, there were no shares of UGI Utilities Series Preferred Stock outstanding.

F-32

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

Note 13 — Common Stock and Equity-Based Compensation

UGI Common Stock share activity for Fiscal 2007, Fiscal 2008 and Fiscal 2009 follows:

	Issued		Treasury			Outstanding
Balance September 30, 2006		115,152,994		(9,698,632	)		105,454,362
Issued:
Employee and director plans		—		1,104,824			1,104,824
Dividend reinvestment plan		—		87,700			87,700
Balance September 30, 2007		115,152,994		(8,506,108	)		106,646,886
Issued:
Employee and director plans		94,700		1,028,843			1,123,543
Dividend reinvestment plan		—		90,533			90,533
Balance September 30, 2008		115,247,694		(7,386,732	)		107,860,962
Issued:
Employee and director plans		13,600		776,074			789,674
Dividend reinvestment plan		—		96,071			96,071
Balance September 30, 2009		115,261,294		(6,514,587	)		108,746,707

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 equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $17.6 ($11.4 after-tax), $11.8 ($7.7 after-tax) and $12.4 ($8.5 after-tax) in Fiscal 2009, Fiscal 2008 and Fiscal 2007, 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 paid in additional Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of Common Stock and cash. Beginning with Fiscal 2006 grants, 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 2010.

F-33

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

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 2007, Fiscal 2008 and Fiscal 2009 follow:

								Weighted
				Weighted		Total		Average
				Average		Intrinsic		Contract Term
	Shares			Option Price		Value		(Years)
Shares under option — September 30, 2006		5,843,852		$	17.06
Granted		1,326,800		$	27.12
Exercised		(812,573	)	$	13.20	$	11.8
Shares under option — September 30, 2007		6,358,079		$	19.65
Granted		1,423,800		$	27.25
Cancelled		(147,300	)	$	27.03
Exercised		(982,334	)	$	15.64	$	11.2
Shares under option — September 30, 2008		6,652,245		$	21.71	$	30.9		6.6
Granted		1,411,200		$	24.65
Forfeited		(87,334	)	$	25.81
Exercised		(474,618	)	$	13.30	$	6.0
Shares under option — September 30, 2009		7,501,493		$	22.74	$	23.2		6.4
Options exercisable — September 30, 2007		3,568,746		$	16.75
Options exercisable — September 30, 2008		3,960,778		$	18.93
Options exercisable — September 30, 2009		4,744,054		$	21.00	$	21.9		5.3
Non-vested options — September 30, 2009		2,757,439		$	25.74	$	1.3		8.3

Cash received from stock option exercises and associated tax benefits was $6.3 and $2.2, $15.4 and $3.7, and $10.7 and $4.0 in Fiscal 2009, Fiscal 2008 and Fiscal 2007, respectively. As of September 30, 2009, there was $3.8 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, 2009:

	Range of exercise prices
	$6.88 -		$16.25 -		$22.38 -
	$15.65		$21.73		$28.02
Options outstanding at September 30, 2009:
Number of options		529,325		2,653,102		4,319,066
Weighted average remaining contractual life (in years)		2.8		4.7		7.8
Weighted average exercise price	$	11.82	$	19.52	$	26.07
Options exercisable at September 30, 2009
Number of options		529,325		2,533,102		1,681,627
Weighted average exercise price	$	11.82	$	19.47	$	26.19

F-34

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

UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $4.13 in Fiscal 2009, $5.06 in Fiscal 2008, and $5.71 in Fiscal 2007. 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 2009, Fiscal 2008 and Fiscal 2007 are as follows:

	2009		2008		2007
Expected life of option	5.75 years		5.75 – 6.75 years		6 – 6.75 years
Weighted average volatility		23.7%		20.9%		21.5%
Weighted average dividend yield		3.0%		2.8%		2.9%
Expected volatility		20.3% – 23.7%		20.3% – 20.9%		20.8% – 21.5%
Expected dividend yield		2.9% – 3.2%		2.8% – 2.9%		2.8% – 2.9%
Risk free rate		1.7% – 3.0%		3.4% – 3.6%		4.3% – 4.7%

UGI Unit Awards. UGI Stock 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-year periods) 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 receive an award. 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:

	Grants Awarded in Fiscal
	2009		2008		2007
Risk-free rate		1.0%		2.7%		4.7%
Expected life	3 years		3 years		3 years
Expected volatility		27.1%		20.5%		19.6%
Dividend yield		3.2%		3.1%		2.6%

F-35

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

The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $27.91 for Units granted in Fiscal 2009, $29.70 for Units granted in Fiscal 2008, and $26.84 for Units granted in Fiscal 2007.

The following table summarizes UGI Unit award activity for Fiscal 2009:

	Total					Vested					Non-Vested
				Weighted					Weighted					Weighted
				Average					Average					Average
	Number of			Grant Date		Number of			Grant Date		Number of			Grant Date
	UGI			Fair Value		UGI			Fair Value		UGI			Fair Value
	Units			(per Unit)		Units			(per Unit)		Units			(per Unit)
September 30, 2008		881,675		$	21.82		527,061		$	18.32		354,614		$	27.01
UGI Performance Units:
Granted		216,250		$	27.91		—		$	—		216,250		$	27.91
Forfeited		(25,666	)	$	28.67		—		$	—		(25,666	)	$	28.67
Vested		—		$	—		192,753		$	25.92		(192,753	)	$	25.92
Unit awards paid		(158,150	)	$	21.01		(158,150	)	$	21.01		—		$	—
Performance criteria not met		—		$	—		—		$	—		—		$	—
UGI Stock Units:
Granted (a)		52,767		$	24.60		—		$	—		52,767		$	24.60
Vested		—		$	—		62,367		$	24.85		(62,367	)	$	24.85
Unit awards paid		(88,449	)	$	17.30		(88,449	)	$	17.30		—		$	—
September 30, 2009		878,427		$	23.89		535,582		$	21.20		342,845		$	28.09

(a) Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2008 and Fiscal 2007 were 37,732 and 44,729, respectively.

During Fiscal 2009, Fiscal 2008 and Fiscal 2007, the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows:

	2009		2008		2007
UGI Performance Unit awards:
Number of original awards granted		163,450		185,300		193,600
Fiscal year granted		2006		2005		2004
Payment of awards:
Shares of UGI Common Stock issued		117,847		0		117,987
Cash paid	$	3.1	$	0	$	2.8
UGI Stock Unit awards:
Number of original awards granted		88,449		40,000		86,000
Payment of awards:
Shares of UGI Common Stock issued		58,376		20,000		51,400
Cash paid	$	0.8	$	0.6	$	1.1

F-36

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

During Fiscal 2009, Fiscal 2008 and Fiscal 2007, we granted UGI Unit awards representing 269,017, 253,325, and 242,371 shares, respectively, having weighted-average grant date fair values per Unit of $27.26, $29.34, and $26.78, respectively.

As of September 30, 2009, there was a total of approximately $6.7 of unrecognized compensation cost associated with 878,427 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 2009, Fiscal 2008, and Fiscal 2007 were $7.6, $7.1 and $6.9, respectively. As of September 30, 2009 and 2008, total liabilities of $8.9 and $6.3, respectively, associated with UGI Unit awards are reflected in “Other current liabilities” and “Other noncurrent liabilities” in the Consolidated Balance Sheets.

At September 30, 2009, 5,572,930 shares of Common Stock were available for future grants under the OECP, of which up to 1,855,956 may be issued pursuant to grants other than stock options or SARs.

AmeriGas Partners Equity-Based Compensation Plans and Awards. Under the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan (“2000 Propane Plan”), the General Partner may award to key employees the right to receive a total of 500,000 AmeriGas Partners Common Units (“AmeriGas 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. AmeriGas Performance Unit grant recipients 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 the performance of AmeriGas Partners Common Units as compared with a peer group. Percentile rankings and payout percentages are generally the same as those used for the UGI Performance Unit awards. Any distribution equivalents earned are paid in cash. 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 AmeriGas Units, is accounted for as equity and the fair value of all 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 AmeriGas Partners Common Units over a three-year period. The risk-free interest rate is based on the rates on U.S. Treasury bonds at the time of grant. Volatility for all limited partnerships in the peer group is based on historical volatility.

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

	Grants Awarded in Fiscal
	2009		2008		2007
Risk-free rate		1.0%		3.1%		4.7%
Expected life	3 years		3 years		3 years
Expected volatility		32.0%		17.7%		17.6%
Dividend yield		9.1%		6.8%		7.1%

We also have a nonexecutive AmeriGas Partners Common Unit plan under which the General Partner may grant awards of up to a total of 200,000 Common Units (comprising “AmeriGas Units”) to key employees who do not participate in the 2000 Propane Plan. Generally, awards under the nonexecutive plan vest at the end of a three-year period and are paid in Common Units and cash. The General Partner made awards under the 2000 Propane Plan and the nonexecutive plan representing 60,200, 40,050 and 49,650 Common Units in Fiscal 2009, Fiscal 2008 and Fiscal 2007, respectively, having weighted-average grant date fair values per Common Unit of $31.94, $37.91 and $33.63, respectively. At September 30, 2009 and 2008, awards representing 147,600 and 126,100 Common Units, respectively, were outstanding. At September 30, 2009, 227,986 and 135,700 Common Units were available for future grants under the 2000 Propane Plan and the nonexecutive plan, respectively.

F-37

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

The following table summarizes AmeriGas Unit and AmeriGas Performance Unit award activity for Fiscal 2009:

	Total					Vested					Non-Vested
	Number of			Weighted		Number of			Weighted		Number of			Weighted
	AmeriGas			Average		AmeriGas			Average		AmeriGas			Average
	Partners			Grant Date		Partners			Grant Date		Partners			Grant Date
	Common			Fair Value		Common			Fair Value		Common			Fair Value
	Units			(per Unit)		Units			(per Unit)		Units			(per Unit)
September 30, 2008		126,100		$	33.44		39,966		$	32.03		86,134		$	34.10
Granted		60,200		$	31.94		—		$	—		60,200		$	31.94
Forfeited		(1,500	)	$	30.70		—		$	—		(1,500	)	$	30.70
Vested		—		$	—		48,818		$	31.70		(48,818	)	$	31.70
Unit awards paid		(37,200	)	$	29.56		(37,200	)	$	29.56		—		$	—
September 30, 2009		147,600		$	33.83		51,584		$	33.49		96,016		$	34.02

During Fiscal 2009, Fiscal 2008 and Fiscal 2007, the Partnership paid AmeriGas Performance Unit and AmeriGas Unit awards (collectively, “Awards”) in Common Units and cash as follows:

	2009		2008		2007
Number of original Awards granted		38,350		39,767		52,200
Fiscal year granted		2006		2005		2004
Payment of Awards:
AmeriGas Partners Common Units issued		36,437		21,249		25,392
Cash paid	$	0.9	$	0.8	$	0.6

As of September 30, 2009, there was a total of approximately $2.0 of unrecognized compensation cost associated with 147,600 AmeriGas Common Unit awards that is expected to be recognized over a weighted average period of 1.8 years. The total fair values of Common Units that vested during Fiscal 2009, Fiscal 2008, and Fiscal 2007 were $1.6, $2.1, and $1.2, respectively. As of September 30, 2009 and 2008, total liabilities of $1.4 and $1.0 associated with Common Unit 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:

1.	all cash on hand at the end of such quarter,
2.	plus all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter,
3.	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.

F-38

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

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. Because the Partnership made quarterly distributions to Common Unitholders in excess of $0.605 per limited partner unit 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 general partner ownership percentage interest alone totaled $7.8 in Fiscal 2009, $3.6 in Fiscal 2008 and $6.8 in Fiscal 2007. The amount of the distributions received by the General Partner during Fiscal 2009, Fiscal 2008 and Fiscal 2007 in excess of its ownership percentage totaled $4.5, $0.7 and $3.7, 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.

On July 30, 2007, the General Partner’s Board of Directors approved a distribution of $0.86 per Common Unit payable on August 18, 2007 to unitholders of record on August 10, 2007. This distribution included the regular quarterly distribution of $0.61 per Common Unit and $0.25 per Common Unit reflecting a distribution of a portion of the proceeds from the Partnership’s July 2007 sale of its Arizona storage facility.

Note 15 — Commitments and Contingencies

Commitments

We lease various buildings and other facilities and transportation, 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 $70.1 in Fiscal 2009, $71.2 in Fiscal 2008 and $68.1 in Fiscal 2007.

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

											After
	2010		2011		2012		2013		2014		2014
AmeriGas Propane	$	46.2	$	37.6	$	30.8	$	24.8	$	17.7	$	28.4
UGI Utilities		5.0		4.2		3.5		3.0		2.1		4.7
International Propane and other		10.3		6.8		3.1		1.6		0.6		0.1
Total	$	61.5	$	48.6	$	37.4	$	29.4	$	20.4	$	33.2

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 2029. 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 energy needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2014. Energy Services enters into fixed-price contracts with suppliers to purchase natural gas to meet its sales commitments. Generally, these contracts have terms of less than two years. The Partnership enters into fixed-price and, from time to time, 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.

F-39

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

The following table presents contractual obligations under Gas Utility, Electric Utility, Energy Services, AmeriGas Propane and International Propane supply, storage and service contracts existing at September 30, 2009:

											After
	2010		2011		2012		2013		2014		2014
Gas Utility and Electric Utility supply, storage and transportation contracts	$	218.9	$	99.8	$	82.9	$	56.7	$	44.3	$	55.4
Energy Services supply contracts		436.4		102.2		6.6		—		—		—
AmeriGas Propane supply contracts		50.5		—		—		—		—		—
International Propane supply contracts		238.9		—		—		—		—		—
Total	$	944.7	$	202.0	$	89.5	$	56.7	$	44.3	$	55.4

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 over the next several years a total of up to $25 in a limited partnership that will focus 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, 2009, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $25.0. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets totaling $25.0.

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

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

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

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

F-40

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

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 for summary judgment with respect to Frontier’s claims.

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. In a second phase of the trial scheduled for early 2010, the court will determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies estimate that remediation costs at Waterbury North could total $25.

F-41

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

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

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.

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 and we are vigorously defending the lawsuits.

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 members 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. Class counsel has indicated that the class is seeking compensatory damages in excess of $12 plus punitive damages, civil penalties and attorneys’ fees.

F-42

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

In 2005, the Swigers 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 both actions.

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. In June 2005, officials from France’s General Division of Competition, Consumption and Fraud Punishment (“DGCCRF”) conducted an unannounced inspection of, and obtained documents from, Antargaz’ headquarters building. Antargaz did not have any further contact with the DGCCRF regarding this matter until February 2007, when it received a letter from the DGCCRF requesting documents and information relating to Antargaz’ pricing policies and practices. In March 2007, and again in August 2007, the DGCCRF requested additional information from Antargaz and three joint ventures in which it participates. In July 2008, France’s Autorité de la concurrence (“Competition Authority”) interviewed Mr. Varagne, as President of Antargaz and President of the industry association, Comité Français du Butane et du Propane, about competitive practices in the LPG cylinder market in France.

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

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

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.

F-43

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

Note 16 — Fair Value Measurements

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, 2009:

	Level 1			Level 2			Level 3		Total
Derivative financial instruments:
Assets	$	2.0		$	18.8		$	—	$	20.8
Liabilities	$	(5.8	)	$	(43.7	)	$	—	$	(49.5	)

Note 17 — Disclosures About Derivative Instruments, Hedging Activities and Other Financial Instruments

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, 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.

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 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, 2009, there were no unsettled NYMEX natural gas futures contracts outstanding. Although we did not have any unsettled NYMEX natural gas futures contracts outstanding at September 30, 2009, we typically hedge anticipated purchases of natural gas over periods of approximately 12 to 18 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. Energy Services 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.

F-44

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

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. The volumes of gasoline under these contracts, the associated fair values and the effect on net income were not material for all periods presented. At September 30, 2009, the maximum period over which we are hedging gasoline is 12 months.

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

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

Commodity	Volumes
LPG (millions of gallons)		152.8
Natural gas (millions of dekatherms)		21.8
Electricity (millions of kilowatt-hours)		372.0

At September 30, 2009, the maximum period over which we are hedging our exposure to the variability in cash flows associated with commodity price risk is 19 months. The volume of electricity congestion that is subject to FTRs at September 30, 2009 totaled 1,738.0 million kilowatt-hours and the maximum period over which we are economically hedging electricity congestion with FTRs is 20 months.

We account for commodity price risk contracts (other than our Gas Utility natural gas futures contracts, FTRs and gasoline futures contracts) 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 interest, 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, 2009, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $32.7. With respect to natural gas futures contracts associated with our Gas Utility, gains and losses on unsettled natural gas futures contracts are recorded in deferred fuel costs on the Consolidated Balance Sheet in accordance with the FASB guidance related to rate-regulated entities and reflected in cost of sales through the PGC mechanism. Because Electric Utility is entitled to fully recover its default service costs commencing January 1, 2010 pursuant to a January 22, 2009 settlement of its default service rate filing with the PUC (see Note 8), changes in the fair value of Electric Utility FTRs associated with periods beginning January 1, 2010 will not affect net income. Electric Utility FTRs associated with periods prior to January 2010 are recorded at fair value with changes in fair value reflected in cost of sales. Energy Services’ FTRs are recorded at fair value with changes in fair value reflected in cost of sales.

Interest Rate Risk

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”). As of September 30, 2009, the total notional amount of our unsettled IRPAs was $150. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of debt forecasted to occur in June 2010.

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 variable-rate debt through March 2011 and Flaga has fixed the underlying euribor interest rate on a substantial portion of its two term loans through their scheduled maturity dates in 2011 and 2014 through the use of pay-fixed, receive-variable interest rate swap agreements. As of September 30, 2009, the total notional amount of our interest rate swaps was €410.6.

We account for IRPAs and interest rate swaps as cash flow hedges. Changes in the fair values of IRPAs and interest rate swaps are recorded in AOCI and, with respect to the Partnership, noncontrolling interest, 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, 2009, 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 based upon current fair values is $2.1.

F-45

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

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 20% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At September 30, 2009, we were hedging a total of $131.5 of U.S. dollar denominated LPG purchases. 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 investment. At September 30, 2009, we were hedging a total of €30.8 of our euro-denominated net investments. As of September 30, 2009, our foreign currency contracts extend through December 2011.

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, 2009, 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 $1.3. 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, 2009 and 2008, restricted cash in brokerage accounts totaled $7.0 and $70.3, respectively. Although we attempt to reduce our overall credit risk with derivative financial instrument counterparties, we have concentrations of credit risk associated with derivative financial instruments held by certain counterparties who comprise a significant portion of the value of derivative financial instrument assets at September 30, 2009. The maximum amount of loss due to credit risk that, based upon the gross fair values of the derivative financial instrument, we would incur if these counterparties that make up the concentration failed to perform according to the terms of their contracts was not material at September 30, 2009. We generally do not have credit-risk-related contingent features in our derivative contracts.

F-46

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

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

	Derivative Assets			Derivative (Liabilities)
	Balance Sheet	Fair		Balance Sheet	Fair
As of September 30, 2009	Location	Value		Location	Value
Derivatives Designated as Hedging Instruments:
Commodity contracts:
LPG	Derivative financial instruments and Other assets	$	13.6	Derivative financial instruments	$	(1.4	)
Natural gas	Derivative financial instruments		2.0	Derivative financial instruments and Other noncurrent liabilities		(2.4	)
Electricity				Derivative financial instruments and Other noncurrent liabilities		(3.4	)
Foreign currrency contracts	Derivative financial instruments and Other assets		—	Other noncurrent liabilities		(5.7	)
Interest rate contracts	Derivative financial instruments		2.2	Derivative financial instruments and Other noncurrent liabilities		(36.6	)
Total Derivatives Designated as Hedging Instruments		$	17.8		$	(49.5	)
Derivatives Not Designated as Hedging Instruments:
FTRs	Derivative financial instruments	$	2.9
Gasoline contracts	Derivative financial instruments		0.1
Total Derivatives Not Designated as Hedging instruments		$	3.0
Total Derivatives		$	20.8		$	(49.5	)

F-47

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

The 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 2009:

							Location of
	Gain or (Loss)			Gain or (Loss)			Gain or (Loss)
	Recognized in			Reclassified from			Reclassified from
	AOCI and			AOCI and Noncontrolling			AOCI and Noncontrolling
Fiscal 2009:	Noncontrolling Interest			Interest into Income			Interest into Income
Cash Flow Hedges:
Commodity contracts:
LPG	$	(135.0	)	$	(199.3	)	Cost of sales
Natural gas		(103.4	)		(100.3	)	Cost of sales
Electricity		(2.7	)		(6.2	)	Cost of sales
Foreign currency contracts		(2.1	)		5.0		Cost of sales
Interest rate contracts		(46.7	)		(7.0	)	Interest expense /other income
Total	$	(289.9	)	$	(307.8	)
Net Investment Hedges:
Foreign currency contracts	$	(2.0	)
	Gain or (Loss)						Location of Gain or (Loss)
	Recognized in						Recognized in
	Income						Income
Derivatives Not Designated as Hedging Instruments:
FTRs	$	(0.6	)				Cost of sales
Gasoline contracts		0.7					Operating expenses/ other income
Total	$	0.1

The amounts of derivative gains or losses representing ineffectiveness and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing were not material for Fiscal 2009, Fiscal 2008 and Fiscal 2007. We reclassified losses of $1.7 into other income, net, during Fiscal 2009 as a result of the discontinuance of cash flow hedges.

We are also a party to a number of 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 purchase and normal sale 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 businesses and the price based on the contract underlying is directly associated with the price or value of a service.

F-48

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

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 amounts and estimated fair values of our remaining financial instruments assets and (liabilities) at September 30 (including unsettled derivative instruments) are as follows:

	Asset (Liability)
	Carrying			Estimated
	Amount			Fair Value
2009:
Derivative financial instruments	$	(28.7	)	$	(28.7	)
Long-term debt		(2,133.1	)		(2,170.3	)
2008:
Derivative financial instruments	$	(88.6	)	$	(88.6	)
Long-term debt		(2,069.1	)		(1,943.2	)

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. Fair values of derivative financial instruments are determined in accordance with the FASB’s guidance regarding fair value measurements.

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 and securities guaranteed by the U.S. Government or its agencies. 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 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 2010, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility’s back-up purchasers.

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 2009, Fiscal 2008 and Fiscal 2007, Energy Services sold trade receivables totaling $1,247.1, $1,496.2 and $1,241.0, respectively, to ESFC. During Fiscal 2009, Fiscal 2008 and Fiscal 2007, ESFC sold an aggregate $596.9, $251.5 and $495.5, respectively, of undivided interests in its trade receivables to the commercial paper conduit. 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. At September 30, 2008, the outstanding balance of ESFC trade receivables was $28.7 which is net of $71 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 2009, Fiscal 2008 and Fiscal 2007, which are included in “Other income, net,” were $2.3, $0.9, and $1.5, respectively.

F-49

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

Note 19 — Other Income, Net

Other income, net, comprises the following:

	2009			2008		2007
Interest and interest-related income	$	5.0		$	11.6	$	11.5
Antargaz Competition Authority Matter		(10.0	)		—		—
Utility non-tariff service income		3.2			6.2		5.1
Gains on Partnership sales of storage facilities		39.9			—		46.1
Finance charges		11.7			11.8		10.2
Other, net		6.1			12.0		5.0
Total other income, net	$	55.9		$	41.6	$	77.9

Note 20 — Quarterly Data (unaudited)

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

	December 31,						March 31,						June 30,						September 30,
	2008 (a)			2007			2009			2008			2009 (b)			2008			2009			2008
Revenues	$	1,778.5		$	1,764.7		$	2,137.8		$	2,361.5		$	962.2		$	1,332.8		$	859.3		$	1,189.2
Operating income (loss)	$	289.4		$	196.2		$	374.8		$	317.4		$	28.8		$	58.2		$	(7.7	)	$	13.4
Loss from equity investees	$	(0.2	)	$	(0.7	)	$	(0.6	)	$	(0.7	)	$	—		$	(0.7	)	$	(2.3	)	$	(0.8	)
Net income (loss)	$	183.9		$	110.9		$	241.8		$	201.5		$	(12.2	)	$	10.8		$	(31.5	)	$	(17.9	)
Net income (loss) attributable to UGI Corporation	$	114.9		$	80.0		$	158.2		$	126.1		$	(3.6	)	$	15.7		$	(11.0	)	$	(6.3	)
Earnings (loss) per share attributable to UGI stockholders:
Basic	$	1.06		$	0.75		$	1.46		$	1.18		$	(0.03	)	$	0.15		$	(0.10	)	$	(0.06	)
Diluted	$	1.05		$	0.74		$	1.45		$	1.17		$	(0.03	)	$	0.14		$	(0.10	)	$	(0.06	)

(a)	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 $12.5 or $0.10 per diluted share (see Note 4).
(b)	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).

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 international propane equity investments (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Energy Services. 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, central and eastern Europe including Austria. 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. Energy Services 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.

F-50

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

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 Energy Services segments principally based upon their income before income taxes.

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

F-51

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

							Reportable Segments
				Elim-			AmeriGas			Gas			Electric			Energy		International Propane						Corporate
	Total			inations			Propane			Utility			Utility			Services		Antargaz			Other (b)			& Other (c)
2009
Revenues	$	5,737.8		$	(172.5	)(d)	$	2,260.1		$	1,241.0		$	138.5		$	1,224.7	$	837.7		$	117.6		$	90.7
Cost of sales	$	3,670.6		$	(167.7	)(d)	$	1,316.5		$	853.2		$	91.6		$	1,098.5	$	362.4		$	67.1		$	49.0
Operating income (loss)	$	685.3		$	—		$	300.5		$	153.5		$	15.4		$	64.8	$	142.8		$	8.6		$	(0.3	)
Loss from equity investees		(3.1	)		—			—			—			—			—		(2.9	)		(0.2	)		—
Interest expense		(141.1	)		—			(70.3	)		(42.2	)		(1.7	)		—		(24.0	)		(2.6	)		(0.3	)
Income (loss) before income taxes	$	541.1		$	—		$	230.2		$	111.3		$	13.7		$	64.8	$	115.9		$	5.8		$	(0.6	)
Depreciation and amortization	$	200.9		$	—		$	83.9		$	47.2		$	3.9		$	8.5	$	47.7		$	8.8		$	0.9
Noncontrolling interests’ net income (loss)	$	123.5		$	0.2		$	123.6		$	—		$	—		$	—	$	(0.4	)	$	0.1		$	—
Partnership EBITDA (a)							$	381.4
Total assets	$	6,042.6		$	(115.5	)	$	1,647.7		$	1,917.1		$	113.2		$	344.1	$	1,705.6		$	260.1		$	170.3
Bank loans	$	163.1		$	—		$	—		$	145.9		$	8.1		$	—	$	—		$	9.1		$	—
Capital expenditures	$	301.7		$	—		$	78.7		$	73.8		$	5.3		$	66.2	$	70.5		$	5.8		$	1.4
Investments in equity investees	$	3.0		$	—		$	—		$	—		$	—		$	—	$	—		$	3.0		$	—
Goodwill	$	1,582.3		$	(4.0	)	$	670.1		$	180.1		$	—		$	—	$	646.9		$	70.4		$	18.8
2008
Revenues	$	6,648.2		$	(283.7	)(d)	$	2,815.2		$	1,138.3		$	139.2		$	1,619.5	$	1,062.6		$	62.2		$	94.9
Cost of sales	$	4,744.6		$	(277.1	)(d)	$	1,908.3		$	831.1		$	84.3		$	1,495.4	$	615.9		$	36.0		$	50.7
Operating income	$	585.2		$	—		$	235.0		$	137.6		$	24.4		$	77.3	$	102.2		$	4.6		$	4.1
Loss from equity investees		(2.9	)		—			—			—			—			—		(1.3	)		(1.6	)		—
Interest expense		(142.5	)		—			(72.9	)		(37.1	)		(2.0	)		—		(27.4	)		(2.3	)		(0.8	)
Income before income taxes	$	439.8		$	—		$	162.1		$	100.5		$	22.4		$	77.3	$	73.5		$	0.7		$	3.3
Depreciation and amortization	$	184.4		$	—		$	80.4		$	37.7		$	3.6		$	7.0	$	50.5		$	4.2		$	1.0
Noncontrolling interests’ net income	$	89.8		$	0.2		$	88.4		$	—		$	—		$	—	$	1.2		$	—		$	—
Partnership EBITDA (a)							$	313.0
Total assets	$	5,685.0		$	(86.3	)	$	1,722.8		$	1,582.5		$	112.1		$	312.3	$	1,673.2		$	196.8		$	171.6
Bank loans	$	136.4		$	—		$	—		$	54.0		$	3.0		$	—	$	70.4		$	9.0		$	—
Capital expenditures	$	234.2		$	—		$	62.8		$	58.3		$	6.0		$	30.7	$	70.7		$	4.3		$	1.4
Investments in equity investees	$	63.1		$	—		$	—		$	—		$	—		$	—	$	—		$	63.1		$	—
Goodwill	$	1,489.7		$	(4.0	)	$	645.2		$	161.7		$	—		$	11.8	$	622.2		$	45.7		$	7.1
2007
Revenues	$	5,476.9		$	(197.3	)(d)	$	2,277.4		$	1,044.9		$	121.9		$	1,336.1	$	759.2		$	41.2		$	93.5
Cost of sales	$	3,730.8		$	(193.8	)(d)	$	1,437.2		$	741.5		$	67.8		$	1,235.2	$	366.7		$	21.9		$	54.3
Operating income	$	581.3		$	—		$	265.8		$	136.6		$	26.0		$	57.4	$	94.5		$	—		$	1.0
Loss from equity investees		(3.8	)		—			—			—			—			—		(1.8	)		(2.0	)		—
Interest expense		(139.6	)		—			(71.5	)		(39.9	)		(2.4	)		—		(23.1	)		(2.1	)		(0.6	)
Income (loss) before income taxes	$	437.9		$	—		$	194.3		$	96.7		$	23.6		$	57.4	$	69.6		$	(4.1	)	$	0.4
Depreciation and amortization	$	169.2		$	—		$	75.7		$	37.4		$	3.5		$	6.9	$	41.5		$	3.4		$	0.8
Noncontrolling interests’ net income	$	106.9		$	0.2		$	105.3		$	—		$	—		$	—	$	1.4		$	—		$	—
Partnership EBITDA (a)							$	338.7
Total assets	$	5,502.7		$	(94.5	)	$	1,708.4		$	1,531.2		$	102.9		$	254.9	$	1,648.9		$	196.8		$	154.1
Bank loans	$	198.9		$	—		$	—		$	176.7		$	13.3		$	—	$	—		$	8.9		$	—
Capital expenditures	$	223.1		$	—		$	73.8		$	66.2		$	7.2		$	10.7	$	61.8		$	2.5		$	0.9
Investments in equity investees	$	63.9		$	—		$	—		$	—		$	—		$	—	$	—		$	63.9		$	—
Goodwill	$	1,498.8		$	(4.0	)	$	645.1		$	162.3		$	—		$	11.8	$	630.3		$	46.3		$	7.0

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

Year ended September 30,	2009			2008			2007
Partnership EBITDA	$	381.4	(i)	$	313.0		$	338.7	(ii)
Depreciation and amortization		(83.9	)		(80.4	)		(75.7	)
Noncontrolling interests (iii)		3.0			2.4			2.8
Operating income	$	300.5		$	235.0		$	265.8

(i)	Includes $39.9 gain on the sale of California storage facility. See Note 4 to consolidated financial statements.
(i)	Includes $46.1 gain on the sale of Arizona storage facility. See Note 4 to consolidated financial statements.
(iii)	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(b)	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 joint-venture business in China.
(c)	Corporate & Other results principally comprise UGI Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC/R”), net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate and Other assets principally comprise cash, short-term investments, assets of HVAC/R and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
(d)	Principally represents the elimination of intersegment transactions among Energy Services, Gas Utility and AmeriGas Propane.

F-52

UGI CORPORATION AND SUBSIDIARIES

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

BALANCE SHEETS
(Millions of dollars)

	September 30,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	1.4		$	1.4
Accounts and notes receivable		3.9			5.3
Deferred income taxes		0.3			0.3
Prepaid expenses and other current assets		0.5			0.4
Total current assets		6.1			7.4
Investments in subsidiaries		1,608.8			1,429.4
Derivative financial instruments		—			1.8
Deferred income taxes		18.7			15.0
Total assets	$	1,633.6		$	1,453.6
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts and notes payable	$	11.3		$	10.6
Derivative financial instruments		0.2			—
Accrued liabilities		6.1			5.9
Total current liabilities		17.6			16.5
Noncurrent liabilities		24.6			19.4
Commitments and contingencies (Note 1)
Common stockholders’ equity:
Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,261,294 and 115,247,694 shares, respectively)		875.6			858.3
Retained earnings		804.3			630.9
Accumulated other comprehensive loss		(38.9	)		(15.2	)
		1,641.0			1,474.0
Less treasury stock, at cost		(49.6	)		(56.3	)
Total common stockholders’ equity		1,591.4			1,417.7
Total liabilities and common stockholders’ equity	$	1,633.6		$	1,453.6

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, 2009, UGI Corporation had agreed to indemnify the issuers of $35.6 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 $342.4 of such obligations were outstanding as of September 30, 2009.

S-1

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

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

	Year Ended
	September 30,
	2009			2008			2007
Revenues	$	—		$	—		$	—
Costs and expenses:
Operating and administrative expenses		33.7			29.3			27.2
Other income, net (1)		(33.7	)		(29.6	)		(27.1	)
		—			(0.3	)		0.1
Operating income (loss)		—			0.3			(0.1	)
Intercompany interest income		0.1			0.1			0.2
Income before income taxes		0.1			0.4			0.1
Income tax expense		0.8			1.3			0.8
Loss before equity in income of unconsolidated subsidiaries		(0.7	)		(0.9	)		(0.7	)
Equity in income of unconsolidated subsidiaries		259.2			216.4			205.0
Net income	$	258.5		$	215.5		$	204.3
Earnings per common share:
Basic	$	2.38		$	2.01		$	1.92
Diluted	$	2.36		$	1.99		$	1.89
Average common shares outstanding (millions):
Basic		108.523			107.396			106.451
Diluted		109.339			108.521			107.941

(1) UGI provides certain financial and administrative services to certain of its subsidiaries. UGI bills these subsidiaries monthly for all direct expenses incurred by UGI on behalf of its subsidiaries as well as allocated shares of indirect corporate expense incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to certain of its subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed and considers the relative percentage of 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.

S-2

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

STATEMENTS OF CASH FLOWS
(Millions of dollars)

	Year Ended
	September 30,
	2009			2008			2007
NET CASH PROVIDED BY OPERATING ACTIVITIES (a)	$	124.7		$	155.1		$	105.1
CASH FLOWS FROM INVESTING ACTIVITIES:
Net investments in unconsolidated subsidiaries		(50.4	)		(94.4	)		(44.0	)
Net cash used by investing activities		(50.4	)		(94.4	)		(44.0	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of dividends on Common Stock		(85.1	)		(80.9	)		(76.8	)
Issuance of Common Stock		10.8			20.9			16.4
Net cash used by financing activities		(74.3	)		(60.0	)		(60.4	)
Cash and cash equivalents increase	$	—		$	0.7		$	0.7
Cash and cash equivalents:
End of year	$	1.4		$	1.4		$	0.7
Beginning of year		1.4			0.7			—
Increase	$	—		$	0.7		$	0.7

(a) Includes dividends received from unconsolidated subsidiaries of $110.7, $144.0, and $100.0 for the years ended September 30, 2009, 2008 and 2007, respectively.

S-3

UGI CORPORATION AND SUBSIDIARIES

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

			Charged
	Balance at		(credited)					Balance at
	beginning		to costs and					end of
	of year		expenses		Other			year
Year Ended September 30, 2009
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	40.8	$	34.1	$	(42.3	)(1)	$	38.3
						5.7	(4)
Other reserves:
Property and casualty liability	$	77.4	$	22.7	$	(32.6	)(3)	$	72.3	(5)
						4.6	(4)
						0.2	(2)
Environmental, litigation and other	$	31.4	$	20.5	$	(5.5	)(3)	$	66.3
						13.9	(4)
						6.0	(2)
Deferred tax assets valuation allowance	$	56.5	$	31.3	$	—		$	87.8
Year Ended September 30, 2008
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	37.7	$	37.1	$	(34.0	)(1)	$	40.8
Other reserves:
Property and casualty liability	$	65.0	$	34.4	$	(22.3	)(3)	$	77.4	(5)
						0.3	(2)
Environmental, litigation and other	$	37.1	$	5.7	$	(13.0	)(3)	$	31.4
						1.6	(2)
Deferred tax assets valuation allowance	$	62.2	$	0.8	$	(6.5	)(2)	$	56.5

S-4

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

			Charged
	Balance at		(credited)					Balance at
	beginning		to costs and					end of
	of year		expenses		Other			year
Year Ended September 30, 2007
Reserves deducted from assets in the consolidated balance sheet:
Allowance for doubtful accounts	$	38.0	$	26.7	$	(28.3	)(1)	$	37.7
						1.3	(4)
Other reserves:
Property and casualty liability	$	62.9	$	16.1	$	(15.3	)(3)	$	65.0	(5)
						1.3	(2)
Environmental, litigation and other	$	26.5	$	2.0	$	(0.9	)(3)	$	37.1
						1.2	(2)
						8.3	(4)
Deferred tax assets valuation allowance	$	39.3	$	22.9	$	—		$	62.2

(1)	Uncollectible accounts written off, net of recoveries
(2)	Other adjustments
(3)	Payments, net
(4)	Acquisition
(5)	At September 30, 2009, 2008 and 2007, the Company had insurance indemnification receivables associated with its property and casualty liabilities totaling $1.0, $18.5 and $1.0, respectively.

S-5

EX-99.4

Exhibit 99.4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-144781) and Form S-8 (Nos. 33-61722, 333-22305, 333-49080, 333-104938, 333-118147 and 333-142010) of UGI Corporation of our report dated November 20, 2009, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of the change in accounting for the noncontrolling interests discussed in Note 3, which is as of May 26, 2010, relating to the financial statements, financial statement schedules and the effectiveness of internal control over financial reporting, which appears in this Current Report on Form 8-K of UGI Corporation dated May 26, 2010.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

May 26, 2010