10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2010

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number 1-11071

UGI CORPORATION

(Exact name of registrant as specified in its charter)

Pennsylvania
(State or other jurisdiction of
incorporation or organization) 23-2668356
(I.R.S. Employer
Identification No.)

UGI CORPORATION
460 North Gulph Road, King of Prussia, PA
(Address of principal executive offices)
19406
(Zip Code)

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

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

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

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

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

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

At July 30, 2010, there were 109,943,804 shares of UGI Corporation Common Stock, without par value, outstanding.

UGI CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

	PAGES
Part I Financial Information
Item 1. Financial Statements (unaudited)
Condensed Consolidated Balance Sheets as of June 30, 2010, September 30, 2009 and June 30, 2009		1
Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2010 and 2009		2
Condensed Consolidated Statements of Cash Flows for the three and nine months ended June 30, 2010 and 2009		3
Notes to Condensed Consolidated Financial Statements		4-30
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		31-49
Item 3. Quantitative and Qualitative Disclosures About Market Risk		50-53
Item 4. Controls and Procedures		53
Part II Other Information
Item 1. Legal Proceedings		54-56
Item 1A. Risk Factors		56
Item 6. Exhibits		57
Signatures		58
Exhibit 10.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Millions of dollars)

	June 30,			September 30,			June 30,
	2010			2009			2009
ASSETS
Current assets:
Cash and cash equivalents	$	241.8		$	280.1		$	240.1
Restricted cash		22.9			7.0			64.8
Accounts receivable (less allowances for doubtful accounts of $44.5, $38.3 and $58.2, respectively)		503.4			405.9			454.5
Accrued utility revenues		9.7			21.0			21.2
Inventories		249.2			363.2			269.1
Deferred income taxes		26.7			34.5			49.3
Utility regulatory assets		6.3			19.6			28.8
Derivative financial instruments		17.5			20.3			12.4
Prepaid expenses and other current assets		34.1			33.5			21.0
Total current assets		1,111.6			1,185.1			1,161.2
Property, plant and equipment (less accumulated depreciation and amortization of $1,866.2, $1,788.8 and $1,750.5 respectively)		2,875.5			2,903.6			2,823.3
Goodwill		1,475.9			1,582.3			1,545.5
Intangible assets, net		138.1			165.5			161.6
Other assets		230.5			206.1			209.7
Total assets	$	5,831.6		$	6,042.6		$	5,901.3
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	572.9		$	94.5		$	11.6
Bank loans		35.2			163.1			125.5
Accounts payable		297.9			334.9			276.4
Derivative financial instruments		48.0			37.5			95.1
Other current liabilities		379.5			467.3			437.7
Total current liabilities		1,333.5			1,097.3			946.3
Long-term debt		1,456.8			2,038.6			2,087.9
Deferred income taxes		510.9			504.9			464.7
Deferred investment tax credits		5.4			5.7			5.8
Other noncurrent liabilities		531.0			579.3			554.5
Total liabilities		3,837.6			4,225.8			4,059.2
Commitments and contingencies (note 9)
Equity:
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,375,794, 115,261,294 and 115,261,294 shares, respectively)		896.1			875.6			870.4
Retained earnings		992.1			804.3			837.0
Accumulated other comprehensive loss		(115.8	)		(38.9	)		(71.7	)
Treasury stock, at cost		(42.4	)		(49.6	)		(52.4	)
Total UGI Corporation stockholders’ equity		1,730.0			1,591.4			1,583.3
Noncontrolling interests		264.0			225.4	(1)		258.8	(1)
Total equity		1,994.0			1,816.8	(1)		1,842.1	(1)
Total liabilities and equity	$	5,831.6		$	6,042.6		$	5,901.3

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

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Millions of dollars, except per share amounts)

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues	$	961.9		$	962.2		$	4,701.0		$	4,878.5
Costs and expenses:
Cost of sales (excluding depreciation shown below)		615.5			591.6			3,009.2			3,142.8
Operating and administrative expenses		267.6			281.0			892.7			929.6
Utility taxes other than income taxes		4.2			4.2			13.6			13.8
Depreciation		46.1			46.0			140.4			133.6
Amortization		5.6			5.3			16.9			15.2
Other (income) expense, net		(8.3	)		5.3			(12.2	)		(49.5	)
		930.7			933.4			4,060.6			4,185.5
Operating income		31.2			28.8			640.4			693.0
Loss from equity investees		(1.9	)		—			(1.9	)		(0.8	)
Interest expense		(33.6	)		(34.6	)		(101.9	)		(106.7	)
(Loss) income before income taxes		(4.3	)		(5.8	)		536.6			585.5
Income taxes		0.1			(6.4	)		(162.5	)		(172.0	)
Net (loss) income		(4.2	)		(12.2	)(1)		374.1			413.5	(1)
Less: net loss (income) attributable to noncontrolling interests, principally AmeriGas Partners		7.6			8.6	(1)		(115.2	)		(144.0	)(1)
Net income (loss) attributable to UGI Corporation	$	3.4		$	(3.6	)(1)	$	258.9		$	269.5	(1)
Earnings (loss) per common share attributable to UGI stockholders:
Basic	$	0.03		$	(0.03	)	$	2.37		$	2.49
Diluted	$	0.03		$	(0.03	)	$	2.35		$	2.47
Average common shares outstanding (thousands):
Basic		109,683			108,592			109,331			108,407
Diluted		110,699			108,592			110,188			109,207
Dividends declared per common share	$	0.25		$	0.20		$	0.65		$	0.585

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

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Millions of dollars)

	Nine Months Ended
	June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	374.1		$	413.5	(1)
Reconcile to net cash from operating activities:
Depreciation and amortization		157.3			148.8
Gain on sale of Partnership California storage facility		—			(39.9	)
Deferred income taxes, net		46.9			(8.3	)
Provision for uncollectible accounts		26.2			35.8
Net change in settled accumulated other comprehensive income (loss)		31.4			(33.2	)
Other, net		20.7			10.4
Net change in:
Accounts receivable and accrued utility revenues		(147.3	)		68.3
Inventories		106.9			159.0
Utility deferred fuel costs		(1.0	)		40.2
Accounts payable		(10.0	)		(238.7	)
Other current assets		(6.2	)		42.0
Other current liabilities		(82.3	)		(4.6	)
Net cash provided by operating activities		516.7			593.3
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(228.8	)		(213.4	)
Acquisitions of businesses, net of cash acquired		(25.4	)		(319.5	)
Net proceeds from sale of Partnership California storage facility		—			42.4
(Increase) decrease in restricted cash		(15.9	)		5.5
Other, net		(14.7	)		1.2
Net cash used by investing activities		(284.8	)		(483.8	)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock		(71.1	)		(63.3	)
Distributions on AmeriGas Partners publicly held Common Units		(66.2	)		(63.2	)
Issuance of debt		—			108.1
Repayments of debt		(9.5	)		(76.5	)
Decrease in bank loans		(123.3	)		(24.0	)
Other		18.3			5.3
Net cash used by financing activities		(251.8	)		(113.6	)
EFFECT OF EXCHANGE RATE CHANGES ON CASH		(18.4	)		(1.0	)
Cash and cash equivalents decrease	$	(38.3	)	$	(5.1	)
Cash and cash equivalents:
End of period	$	241.8		$	240.1
Beginning of period		280.1			245.2
Decrease	$	(38.3	)	$	(5.1	)

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

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

1. Nature of Operations

UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes and markets energy products and related services. In the United States, we own and operate (1) a retail propane marketing and distribution business; (2) natural gas and electric distribution utilities; (3) electricity generation facilities; and (4) 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 June 30, 2010, the General Partner held a 1% general partner interest and 42.8% limited partner interest in AmeriGas Partners, and an effective 44.4% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners Common Units (“Common Units”). The remaining 56.2% interest in AmeriGas Partners comprises 32,397,300 Common Units held by the general public as limited partner interests.

Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries (1) conducts an LPG distribution business in France (“Antargaz”); (2) conducts an LPG distribution business in central and eastern Europe (“Flaga”); and (3) conducts an LPG 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.

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 principally located 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.”

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

2. Significant Accounting Policies

Our condensed consolidated financial statements include the accounts of UGI and its controlled subsidiary companies, which, except for the Partnership, are majority owned. We eliminate all significant intercompany accounts and transactions when we consolidate. We report the public’s limited partner interests in the Partnership and the outside ownership interests in certain subsidiaries of Antargaz and Flaga as noncontrolling interests. Entities in which we own 50 percent or less and in which we exercise significant influence over operating and financial policies are accounted for by the equity method.

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments which we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2009 condensed consolidated balance sheet data were derived from audited financial statements but do not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”). These financial statements should be read in conjunction with the financial statements and related notes included in our Current Report on Form 8-K dated May 26, 2010 (“Company’s 2009 Annual Financial Statements and Notes”) which supersede the financial statements and related notes included in our Form 10-K for the year ended September 30, 2009 in order to retrospectively reflect the adoption of the new guidance relating to noncontrolling interests discussed in Note 3. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

As discussed below, certain prior-period amounts have been adjusted to comply with recently adopted Financial Accounting Standards Board (“FASB”) accounting guidance for the presentation of noncontrolling interests in consolidated financial statements.

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

Earnings Per Common Share. Basic earnings per share reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Shares used in computing basic and diluted earnings per share are as follows:

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Denominator (thousands of shares):
Average common shares outstanding for basic computation		109,683		108,592		109,331		108,407
Incremental shares issuable for stock options and awards		1,016		—		857		800
Average common shares outstanding for diluted computation		110,699		108,592		110,188		109,207

Comprehensive Income (Loss). The following table presents the components of comprehensive income (loss) for the three and nine months ended June 30, 2010 and 2009:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2010			2009 (1)			2010			2009 (1)
Net (loss) income	$	(4.2	)	$	(12.2	)	$	374.1		$	413.5
Other comprehensive (loss) income		(58.2	)		98.1			(84.4	)		(38.0	)
Comprehensive (loss) income (including noncontrolling interests)		(62.4	)		85.9			289.7			375.5
Less: comprehensive income (loss) attributable to noncontrolling interests		21.4			(31.1	)		(107.7	)		(162.5	)
Comprehensive (loss) income attributable to UGI Corporation	$	(41.0	)	$	54.8		$	182.0		$	213.0

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

Other comprehensive (loss) income principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, principally commodity instruments, interest rate protection agreements, interest rate swaps and foreign currency derivatives, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation adjustments.

On December 31, 2008, we merged two of our domestic defined benefit pension plans. As a result of the merger, at December 31, 2008, the Company was required under GAAP to remeasure the combined plan’s assets and obligations and record the funded status in our Condensed Consolidated Balance Sheet. The associated after-tax charge to other comprehensive loss of $38.7 is included in the table above for the nine months ended June 30, 2009.

Reclassifications. In addition to the previously mentioned prior-period adjustments resulting from the adoption of accounting guidance relating to the presentation of noncontrolling interests, we have reclassified certain other prior-period balances to conform to the current-period presentation.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Use of Estimates. We make estimates and assumptions when preparing financial statements in conformity with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

Income Taxes. As a result of settlements with tax authorities during the three months ended December 31, 2009 and 2008, the Company adjusted its unrecognized tax benefits which reduced income tax expense and increased net income by $0.9 and $2.0 for the nine months ended June 30, 2010 and 2009, respectively.

The Company received Internal Revenue Service (“IRS”) consent to change its tax method of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. The filing of the Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax benefits totaling approximately $30.2 which has been, or will be, used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 stand alone Pennsylvania income tax return also produced an approximate $43.4 state net operating loss (“NOL”) carryforward, resulting in a net deferred tax benefit of approximately $2.8.

Under current Pennsylvania state income tax law, the NOL stated above can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. Because the Company believes that it is more likely than not that it will fully utilize this state NOL prior to its expiration, no valuation allowance has been recorded.

The Company’s determination of what constitutes a capital cost versus ordinary expense as it relates to the new tax method will likely be reviewed upon audit by the IRS and may be subject to subsequent adjustment. Accordingly, the status of this tax return position is uncertain at this time. In accordance with accounting guidance regarding uncertain tax positions, the Company has added $3.9 to its liability for unrecognized tax benefits related to this tax method. However, because this tax matter relates only to the timing of tax deductibility, we have recorded an offsetting deferred tax asset of an equal amount.

The previously discussed change in tax method did not affect the Company’s net income (loss) for any periods presented. For further information regarding the regulatory impact of this change, see Note 7.

3.	Accounting Changes
	Adoption of New Accounting Standards

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Business Combinations. Effective October 1, 2009, we adopted new guidance on accounting for business combinations. The new guidance applies to all transactions or other events in which an entity obtains control of one or more businesses. The new guidance establishes, among other things, principles and requirements for how the acquirer (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in a business combination or gain from a bargain purchase; and (3) determines what information with respect to a business combination should be disclosed. The new guidance applies prospectively to business combinations for which the acquisition date is on or after October 1, 2009. Among the more significant changes in accounting for acquisitions are (1) transaction costs are generally expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, are generally recorded at fair value with subsequent adjustments recognized in operations (rather than as adjustments to the purchase price); and (3) decreases in valuation allowances on acquired deferred tax assets are recognized in operations (rather than as decreases in goodwill). The new guidance did not have a material impact on our financial statements for the three and nine months ended June 30, 2010.

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

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

New Accounting Standards Not Yet Adopted

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 annual disclosure guidance are effective for fiscal years ending after December 15, 2009 (Fiscal 2010). Because this new guidance relates to disclosures only, it will not impact the financial statements.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Transfers of Financial Assets. In June 2009, the FASB issued new guidance regarding accounting for transfers of financial assets. Among other things, the new guidance eliminates the concept of Qualified Special Purpose Entities (“QSPEs”). It also amends previous derecognition guidance. The new guidance is effective for financial asset transfers occurring after the beginning of an entity’s fiscal year that begins after November 15, 2009 (Fiscal 2011). The adoption of the new accounting guidance will change the accounting for transfers of accounts receivable to a commercial paper conduit of a major bank under the Energy Services Receivables Facility (see Note 6). Beginning October 1, 2010, trade receivables transferred to the commercial paper conduit will remain on the Company’s balance sheet and the Company will reflect a liability equal to the amount advanced by the commercial paper conduit. Under current accounting guidance, trade accounts receivable sold to the commercial paper conduit are removed from the balance sheet. Additionally, the Company will record interest expense on amounts owed to the commercial paper conduit. Currently, losses on sales of accounts receivable are reflected in other income, net.

4. Intangible Assets

The Company’s intangible assets comprise the following:

	June 30,			September 30,			June 30,
	2010			2009			2009
Goodwill (not subject to amortization)	$	1,475.9		$	1,582.3		$	1,545.5
Other intangible assets:
Customer relationships, noncompete agreements and other	$	202.9		$	219.1		$	217.7
Trademark (not subject to amortization)		41.5			49.7			47.7
Gross carrying amount		244.4			268.8			265.4
Accumulated amortization		(106.3	)		(103.3	)		(103.8	)
Net carrying amount	$	138.1		$	165.5		$	161.6

The decrease in goodwill and other intangible assets during the nine months ended June 30, 2010 principally reflects the effects of currency translation partially offset by the effects of acquisitions. Amortization expense of intangible assets was $4.9 and $14.8 for the three and nine months ended June 30, 2010, respectively, and $4.7 and $13.6 for the three and nine months ended June 30, 2009, respectively. No amortization is included in cost of sales in the Condensed Consolidated Statements of Income. Our expected aggregate amortization expense of intangible assets for the next five fiscal years is as follows: Fiscal 2010 — $17.8; Fiscal 2011 — $16.8; Fiscal 2012 — $16.7; Fiscal 2013 — $16.0; Fiscal 2014 — $14.0.

5. Segment Information

We have organized our business units into six reportable segments generally based upon products sold, geographic location (domestic or international) or 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 retail propane business in China (“Other”); (4) Gas Utility; (5) Electric Utility; and (6) Energy Services. We refer to both international segments collectively as “International Propane.”

The accounting policies of our reportable segments are the same as those described in Note 2, “Significant Accounting Policies” in the Company’s 2009 Annual Financial Statements and Notes. 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 GAAP. 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.

- 9 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

5. Segment Information (continued)

Three Months Ended June 30, 2010:

							Reportable Segments
							AmeriGas			Gas			Electric			Energy		International Propane						Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other (a)			& Other (b)
Revenues	$	961.9		$	(22.2	)	$	396.6		$	149.1		$	25.3		$	198.6	$	150.8		$	41.0		$	22.7
Cost of sales	$	615.5		$	(20.7	)	$	235.8		$	83.0		$	15.8		$	177.3	$	81.9		$	30.0		$	12.4
Segment profit:
Operating income (loss)	$	31.2		$	(0.4	)	$	5.3		$	13.8		$	2.6		$	6.9	$	4.3		$	(1.4	)	$	0.1
Loss from equity investees		(1.9	)		—			—			—			—			—		(1.9	)		—			—
Interest expense		(33.6	)		—			(17.0	)		(10.0	)		(0.4	)		—		(5.3	)		(0.7	)		(0.2	)
(Loss) income before income taxes	$	(4.3	)	$	(0.4	)	$	(11.7	)	$	3.8		$	2.2		$	6.9	$	(2.9	)	$	(2.1	)	$	(0.1	)
Partnership EBITDA (d)							$	27.2
Noncontrolling interests’ net (loss) income	$	(7.6	)	$	0.1		$	(7.5	)	$	—		$	—		$	—	$	(0.2	)	$	—		$	—
Depreciation and amortization	$	51.7		$	—		$	21.8		$	12.5		$	1.0		$	2.0	$	11.5		$	2.6		$	0.3
Capital expenditures	$	83.1		$	—		$	14.4		$	16.1		$	2.3		$	34.3	$	12.8		$	2.0		$	1.2
Total assets (at period end)	$	5,831.6		$	(69.3	)	$	1,658.4		$	1,829.4		$	120.4		$	463.3	$	1,446.4		$	231.2		$	151.8
Bank loans (at period end)	$	35.2		$	—		$	15.0		$	—		$	—		$	—	$	—		$	20.2		$	—
Goodwill (at period end)	$	1,475.9		$	(3.9	)	$	674.8		$	180.1		$	—		$	11.8	$	540.6		$	65.6		$	6.9

Three Months Ended June 30, 2009:

							Reportable Segments
							AmeriGas			Gas			Electric			Energy		International Propane						Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other (a)			& Other (b)
Revenues	$	962.2		$	(28.6	)	$	372.7		$	176.9		$	30.8		$	223.4	$	133.5		$	31.4		$	22.1
Cost of sales	$	591.6		$	(27.4	)	$	210.3		$	109.8		$	19.7		$	200.4	$	49.3		$	18.1		$	11.4
Segment profit:
Operating income (loss)	$	28.8		$	0.1		$	4.4		$	12.9		$	3.3		$	8.6	$	(0.5	)(c)	$	0.8		$	(0.8	)
Income (loss) from equity investees		—			—			—			—			—			—		—			—			—
Interest expense		(34.6	)		—			(17.2	)		(10.3	)		(0.5	)		—		(5.8	)		(0.7	)		(0.1	)
(Loss) income before income taxes	$	(5.8	)	$	0.1		$	(12.8	)	$	2.6		$	2.8		$	8.6	$	(6.3	)(c)	$	0.1		$	(0.9	)
Partnership EBITDA (d)							$	25.4
Noncontrolling interests’ net (loss) income	$	(8.6	)	$	0.1		$	(8.3	)	$	—		$	—		$	—	$	(0.4	)	$	—		$	—
Depreciation and amortization	$	51.3		$	(0.1	)	$	21.1		$	11.8		$	1.1		$	2.2	$	12.4		$	2.5		$	0.3
Capital expenditures	$	74.6		$	—		$	19.5		$	18.2		$	1.1		$	18.1	$	15.5		$	2.0		$	0.2
Total assets (at period end)	$	5,901.3		$	(119.7	)	$	1,619.3		$	1,902.6		$	116.2		$	328.2	$	1,640.3		$	247.7		$	166.7
Bank loans (at period end)	$	125.5		$	—		$	—		$	103.1		$	6.9		$	—	$	—		$	15.5		$	—
Goodwill (at period end)	$	1,545.5		$	(3.9	)	$	666.1		$	176.9		$	—		$	11.8	$	620.2		$	67.5		$	6.9

(a)	International Propane — Other principally comprises Flaga and, to a much lesser extent, our retail propane business in China.
(b)	Corporate & Other results principally comprise UGI Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting business (“HVAC/R”), net expenses of UGI’s captive general liability insurance company, UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & 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 information.
(c)	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:

Three months ended June 30,	2010			2009
Partnership EBITDA	$	27.2		$	25.4
Depreciation and amortization		(21.8	)		(21.1	)
Noncontrolling interests (i)		(0.1	)		0.1
Operating income	$	5.3		$	4.4

(i)	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(d)	Includes $(10.0) provision for Antargaz Competition Authority Matter.

- 10 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

5. Segment Information (continued)

Nine Months Ended June 30, 2010:

							Reportable Segments
							AmeriGas			Gas			Electric			Energy		International Propane						Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other (a)			& Other (b)
Revenues	$	4,701.0		$	(146.9	)	$	1,939.3		$	922.3		$	90.9		$	949.5	$	755.3		$	129.8		$	60.8
Cost of sales	$	3,009.2		$	(142.3	)	$	1,165.1		$	584.2		$	58.0		$	830.9	$	394.4		$	86.8		$	32.1
Segment profit:
Operating income (loss)	$	640.4		$	(0.7	)	$	261.2		$	168.6		$	11.1		$	75.4	$	123.4		$	4.2		$	(2.8	)
Loss from equity investees		(1.9	)		—			—			—			—			—		(1.8	)		(0.1	)		—
Interest expense		(101.9	)		—			(50.2	)		(30.5	)		(1.3	)		—		(17.1	)		(2.3	)		(0.5	)
Income (loss) before income taxes	$	536.6		$	(0.7	)	$	211.0		$	138.1		$	9.8		$	75.4	$	104.5		$	1.8		$	(3.3	)
Partnership EBITDA (c)							$	323.7
Noncontrolling interests’ net income	$	115.2		$	0.1		$	114.5		$	—		$	—		$	—	$	0.6		$	—		$	—
Depreciation and amortization	$	157.3		$	(0.1	)	$	65.0		$	37.0		$	3.0		$	6.0	$	37.2		$	8.2		$	1.0
Capital expenditures	$	229.4		$	—		$	59.8		$	40.6		$	3.9		$	84.7	$	32.1		$	5.7		$	2.6
Total assets (at period end)	$	5,831.6		$	(69.3	)	$	1,658.4		$	1,829.4		$	120.4		$	463.3	$	1,446.4		$	231.2		$	151.8
Bank loans (at period end)	$	35.2		$	—		$	15.0		$	—		$	—		$	—	$	—		$	20.2		$	—
Goodwill (at period end)	$	1,475.9		$	(3.9	)	$	674.8		$	180.1		$	—		$	11.8	$	540.6		$	65.6		$	6.9

Nine Months Ended June 30, 2009:

							Reportable Segments
							AmeriGas			Gas			Electric			Energy		International Propane						Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other (a)			& Other (b)
Revenues	$	4,878.5		$	(135.4	)	$	1,923.1		$	1,130.1		$	104.8		$	1,007.1	$	699.3		$	81.3		$	68.2
Cost of sales	$	3,142.8		$	(131.7	)	$	1,129.8		$	795.7		$	67.1		$	902.3	$	297.4		$	44.9		$	37.3
Segment profit:
Operating income (loss)	$	693.0		$	0.2		$	317.2		$	149.8		$	13.8		$	60.0	$	147.5	(d)	$	6.6		$	(2.1	)
Loss from equity investees		(0.8	)		—			—			—			—			—		(0.7	)		(0.1	)		—
Interest expense		(106.7	)		—			(53.7	)		(31.7	)		(1.3	)		—		(17.9	)		(1.8	)		(0.3	)
Income (loss) before income taxes	$	585.5		$	0.2		$	263.5		$	118.1		$	12.5		$	60.0	$	128.9	(d)	$	4.7		$	(2.4	)
Partnership EBITDA (c)							$	376.7
Noncontrolling interests’ net income (loss)	$	144.0		$	0.1		$	144.0		$	—		$	—		$	—	$	(0.1	)	$	—		$	—
Depreciation and amortization	$	148.8		$	(0.3	)	$	62.8		$	34.9		$	3.0		$	6.1	$	35.3		$	6.0		$	1.0
Capital expenditures	$	213.4		$	—		$	57.4		$	52.6		$	3.5		$	44.9	$	49.7		$	4.2		$	1.1
Total assets (at period end)	$	5,901.3		$	(119.7	)	$	1,619.3		$	1,902.6		$	116.2		$	328.2	$	1,640.3		$	247.7		$	166.7
Bank loans (at period end)	$	125.5		$	—		$	—		$	103.1		$	6.9		$	—	$	—		$	15.5		$	—
Goodwill (at period end)	$	1,545.5		$	(3.9	)	$	666.1		$	176.9		$	—		$	11.8	$	620.2		$	67.5		$	6.9

(a)	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, to a much lesser extent, our retail propane business in China.
(b)	Corporate & Other results principally comprise UGI Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting business (“HVAC/R”), net expenses of UGI’s captive general liability insurance company, UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & 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.
(c)	The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:

Nine months ended June 30,	2010			2009
Partnership EBITDA	$	323.7	(ii)	$	376.7	(iii)
Depreciation and amortization		(65.0	)		(62.8	)
Noncontrolling interests (i)		2.5			3.3
Operating income	$	261.2		$	317.2

(i)	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(ii)	Includes $12.2 loss associated with the discontinuance of Partnership interest rate protection agreements.
(iii)	Includes $39.9 gain on sale of Partnership California storage facility.
(d)	Includes $(10.0) million provision for Antargaz Competition Authority Matter.

- 11 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

6. Energy Services Accounts Receivable Securitization Facility

Energy Services has a $200 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in April 2011, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility 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 some or all of the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables following the FASB’s guidance for accounting for transfers and servicing 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 the nine months ended June 30, 2010 and 2009, Energy Services sold trade receivables totaling $933.3 and $1,029.5, respectively, to ESFC. During the nine months ended June 30, 2010 and 2009, ESFC sold an aggregate $233.6 and $508.9, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At June 30, 2010, the outstanding balance of ESFC trade receivables was $61.8 and there was no amount sold to the commercial paper conduit and removed from the balance sheet. At June 30, 2009, the outstanding balance of ESFC trade receivables was $24.1 which is net of $44.4 that was sold to the commercial paper conduit.

- 12 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

7. Utility Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 to the Company’s 2009 Annual Financial Statements and Notes. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:

	June 30,		September 30,		June 30,
	2010		2009		2009
Regulatory assets:
Income taxes recoverable	$	95.3	$	79.5	$	76.6
Postretirement benefits		1.7		2.5		3.0
CPG Gas pension and postretirement plans		8.6		8.5		5.6
Environmental costs		24.3		26.9		20.6
Deferred fuel and power costs		6.3		19.6		28.8
Other		5.5		4.5		6.9
Total regulatory assets	$	141.7	$	141.5	$	141.5
Regulatory liabilities:
Postretirement benefits	$	10.3	$	9.3	$	10.0
Environmental overcollections		8.3		8.7		9.7
Deferred fuel refunds		16.6		30.8		13.5
State tax benefits — distribution system repairs		11.0		—		—
Total regulatory liabilities	$	46.2	$	48.8	$	33.2

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

Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Unrealized losses on such contracts at June 30, 2010 and June 30, 2009 were $(0.6) and $(42.5), respectively. There were no such unrealized gains or losses at September 30, 2009.

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

- 13 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

State Income Tax Benefits – Distribution System Repairs. As previously mentioned in Note 2 to condensed consolidated financial statements, the Company received IRS consent to change its tax method of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. This regulatory liability represents Pennsylvania state income tax benefits, net of federal income tax expense, resulting from the deduction for income tax purposes of these repairs and maintenance expenses which expenses are capitalized for regulatory and GAAP reporting. The state tax benefits associated with these repairs and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets.

8. Defined Benefit Pension and Other Postretirement Plans

We sponsor defined benefit pension plans for employees hired prior to January 1, 2009 of UGI, UGI Utilities, CPG, PNG and certain of UGI’s other wholly owned domestic subsidiaries (“Pension Plans”). We also provide postretirement health care benefits to certain retirees and a limited number of active employees, and postretirement life insurance benefits to nearly all domestic active and retired employees. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans.

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

							Other
	Pension Benefits						Postretirement Benefits
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Service cost	$	2.2		$	1.9		$	0.1		$	0.1
Interest cost		5.8			5.8			0.3			0.2
Expected return on assets		(6.5	)		(6.3	)		(0.1	)		(0.1	)
Amortization of:
Prior service benefit		—			—			(0.1	)		(0.1	)
Actuarial loss		1.5			1.2			0.1			—
Net benefit cost		3.0			2.6			0.3			0.1
Change in associated regulatory liabilities		—			—			0.7			0.8
Net expense	$	3.0		$	2.6		$	1.0		$	0.9

							Other
	Pension Benefits						Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Service cost	$	6.5		$	5.3		$	0.3		$	0.2
Interest cost		17.6			17.6			0.9			0.7
Expected return on assets		(19.4	)		(19.3	)		(0.3	)		(0.4	)
Amortization of:
Transition obligation		—			—			—			0.1
Prior service benefit		—			—			(0.3	)		(0.2	)
Actuarial loss		4.4			2.7			0.2			—
Net benefit cost		9.1			6.3			0.8			0.4
Change in associated regulatory liabilities		—			—			2.2			2.4
Net expense	$	9.1		$	6.3		$	3.0		$	2.8

- 14 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Pension Plans’ assets are held in trust and consist principally of equity and fixed income mutual funds. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $9.5 to the Pension Plans during the next twelve months. Pursuant to orders previously issued by the PUC, UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to fund and pay UGI Gas and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP relating to postretirement benefits other than pensions. The difference between the annual amount calculated and the amount included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the nine months ended June 30, 2010, nor are they expected to be material for all of Fiscal 2010.

We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans. We recorded pre-tax expense associated with these plans of $0.6 and $1.8 for the three and nine months ended June 30, 2010, respectively. We recorded pre-tax expense for these plans of $0.6 and $2.2 for the three and nine months ended June 30, 2009, respectively.

9. Commitments and Contingencies

Environmental Matters

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

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

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.

- 15 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

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.

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

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

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.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

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

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Other Matters

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

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

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

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

In 2005, the Swigers 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 Business Tax. French tax authorities levy various taxes on legal entities and individuals regularly operating a business in France which are commonly referred to collectively as “business tax.” The amount of business tax charged annually is generally dependent upon the value of the entity’s tangible fixed assets. Antargaz has recorded liabilities for business taxes related to various classes of equipment. Changes in the French government’s interpretation of the tax laws or in the tax laws themselves could have either an adverse or a favorable effect on our results of operations.

Antargaz Competition Authority Matter. On July 21, 2009, Antargaz received a Statement of Objections from France’s Autorité de la concurrence (“Competition Authority”) with respect to the investigation of Antargaz by the General Division of Competition, Consumption and Fraud Punishment (“DGCCRF”). A Statement of Objections (“Statement”) is part of French competition proceedings and generally follows an investigation under French competition laws. The Statement sets forth the Competition Authority’s findings; it is not a judgment or final decision. The Statement alleges that Antargaz engaged in certain anti-competitive practices in violation of French 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.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

We filed our written response to the Statement of Objections with the Competition Authority on October 21, 2009. The Competition Authority completed its review of Antargaz’ response and issued its report on April 26, 2010. Antargaz filed its response to this report on June 28, 2010. A hearing date has not yet been scheduled by the Competition Authority. Based on our assessment of the information contained in the report, we believe that we have good defenses to the objections and that the reserve established by management for this matter is adequate. However, the final resolution could result in payment of an amount significantly different from the amount we have recorded. We 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.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

10. Equity

The following table sets forth changes in UGI’s equity and the equity of the noncontrolling interests for the nine months ended June 30, 2010 and 2009:

				UGI Shareholders
									Accumulated
									Other
	Non-								Comprehensive
	controlling			Common		Retained			Income			Treasury			Total
	Interests			Stock		Earnings			(Loss)			Stock			Equity
Nine Months Ended June 30, 2010:
Balance September 30, 2009	$	225.4		$	875.6	$	804.3		$	(38.9	)	$	(49.6	)	$	1,816.8	(1)
Net income		115.2					258.9									374.1
Net gains (losses) on derivative instruments		6.9								(11.0	)					(4.1	)
Reclassifications of net (gains) losses on derivative instruments		(14.4	)							30.9						16.5
Benefit plans										2.3						2.3
Foreign currency translation adjustments										(99.1	)					(99.1	)
Comprehensive income		107.7					258.9			(76.9	)					289.7
Dividends and distributions		(66.2	)				(71.1	)								(137.3	)
Transactions with owners		0.7			20.5								7.2			28.4
Other		(3.6	)													(3.6	)
Balance June 30, 2010	$	264.0		$	896.1	$	992.1		$	(115.8	)	$	(42.4	)	$	1,994.0
Nine Months Ended June 30, 2009:
Balance September 30, 2008	$	159.2	(1)	$	858.3	$	630.9		$	(15.2	)	$	(56.3	)	$	1,576.9	(1)
Net income		144.0	(1)				269.5									413.5	(1)
Net losses on derivative instruments		(84.0	)(1)							(121.2	)					(205.2	)(1)
Reclassifications of net losses on derivative instruments		102.5	(1)							99.0						201.5	(1)
Benefit plans										(38.8	)					(38.8	)(1)
Foreign currency translation adjustments										4.5						4.5	(1)
Comprehensive income		162.5	(1)				269.5			(56.5	)					375.5	(1)
Dividends and distributions		(63.2	)(1)				(63.4	)								(126.6	)(1)
Transactions with owners		0.5	(1)		12.1								3.9			16.5	(1)
Other		(0.2	)(1)													(0.2	)(1)
Balance June 30, 2009	$	258.8	(1)	$	870.4	$	837.0		$	(71.7	)	$	(52.4	)	$	1,842.1	(1)

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

11. Fair Value Measurement

Derivative Financial Instruments

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

	Asset (Liability)
	Quoted Prices
	in Active			Significant
	Markets for			Other
	Identical Assets			Observable			Unobservable
	and Liabilities			Inputs			Inputs
	(Level 1)			(Level 2)			(Level 3)		Total
June 30, 2010:
Derivative financial instruments:
Commodity contracts	$	(25.1	)	$	(14.8	)	$	—	$	(39.9	)
Foreign currency contracts	$	—		$	16.9		$	—	$	16.9
Interest rate contracts	$	—		$	(16.4	)	$	—	$	(16.4	)
September 30, 2009:
Derivative financial instruments:
Commodity contracts	$	(3.8	)	$	15.1		$	—	$	11.3
Foreign currency contracts	$	—		$	(5.7	)	$	—	$	(5.7	)
Interest rate contracts	$	—		$	(34.3	)	$	—	$	(34.3	)
June 30, 2009:
Derivative financial instruments:
Commodity contracts	$	(59.8	)	$	(7.2	)	$	—	$	(67.0	)
Foreign currency contracts	$	—		$	1.2		$	—	$	1.2
Interest rate contracts	$	—		$	(27.9	)	$	—	$	(27.9	)

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

Other Financial Instruments

The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt at June 30, 2010 were $2,029.7 and $2,122.7, respectively. The carrying amount and estimated fair value of our long-term debt at June 30, 2009 were $2,099.5 and $2,063.1, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

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.

12. Disclosures About Derivative Instruments, Hedging Activities and Financial Instruments

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

Commodity Price Risk

In order to manage market price risk associated with the Partnership’s fixed-price programs which permit customers to lock in the prices they pay for propane principally during the months of October through March, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. Certain other domestic business units and our International Propane operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases.

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At June 30, 2010 and 2009, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.3 million dekatherms and 8.2 million dekatherms, respectively. Gains and losses on natural gas futures contracts and gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with FASB’s guidance in Accounting Standards Codification (“ASC”) 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 7).

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

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. 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 filing with the PUC, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 7). Gains and losses associated with periods prior to January 2010 were reflected in cost of sales. At June 30, 2010 and 2009, the volumes of Electric Utility electric transmission congestion subject to FTRs totaled 739.3 million kilowatt hours and 1,277.0 million kilowatt hours, respectively. Energy Services’ FTRs are recorded at fair value with changes in fair value reflected in cost of sales.

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

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

	Volumes
Commodity	2010		2009
LPG (millions of gallons)		150.5		163.1
Natural gas (millions of dekatherms)		33.3		25.1
Electricity (millions of kilowatt-hours)		928.0		378.2

The maximum period over which we are currently hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 21 months with a weighted average of 7 months. The maximum period over which we are currently hedging our exposure to the variability in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 31 months with a weighted average of 8 months. The maximum period over which we are currently hedging our exposure to the variability in cash flows associated with electricity price risk is 30 months with a weighted average of 9 months. The volume of electric transmission congestion that is subject to FTRs (excluding Electric Utility) at June 30, 2010 and 2009 totaled 1,415.0 million kilowatt hours and 1,005.0 million kilowatt hours, respectively. The maximum period over which we are economically hedging such electricity congestion with FTRs is 11 months with a weighted average of 6 months.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

We account for commodity price risk contracts (other than our Gas Utility natural gas futures and option contracts, gasoline futures and swap contracts, and Electric Utility FTRs) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in accumulated other comprehensive income (“AOCI”) and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales on the Consolidated Statements of Income. At June 30, 2010, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $45.7.

Interest Rate Risk

Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has effectively fixed the underlying euribor interest rate on its €380 variable-rate debt through its March 2011 maturity date through the use of pay-fixed, receive-variable interest rate swap agreements. Antargaz intends to refinance its €380 variable-rate term loan, subject to market conditions, on a long-term basis by March 2011. In anticipation of such refinancing, Antargaz has entered into forward-starting interest rate swap agreements to hedge the underlying euribor rate of interest relating to 4 1/2 years of quarterly interest payments on €300 notional amount of long-term debt commencing March 31, 2011. Flaga has also fixed the underlying euribor interest rate on a substantial portion of its two term loans through their scheduled maturity dates ending in 2014 through the use of pay-fixed, receive-variable interest rate swap agreements. As of June 30, 2010 and 2009, the total notional amounts of our existing and anticipated variable rate debt subject to interest rate swap agreements were €706.2 and €406.6, respectively.

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

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 20% — 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At June 30, 2010 and 2009, we were hedging a total of $72.8 and $121.4 of U.S. dollar-denominated LPG purchases, respectively. The maximum period over which we are currently hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 18 months with a weighted average of 7 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At June 30, 2010 and 2009, we were hedging a total of €48.3 and €30.8, respectively, of our euro-denominated net investments. As of June 30, 2010, such 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 June 30, 2010, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $5.1. 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 June 30, 2010 and 2009, restricted cash in brokerage accounts totaled $22.9 and $64.8, respectively. Although we have concentrations of credit risk associated with derivative financial instruments, the maximum amount of loss, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at June 30, 2010. We generally do not have credit-risk-related contingent features in our derivative contracts.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

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

	Derivative Assets					Derivative (Liabilities)
		Fair Value					Fair Value
	Balance Sheet	June 30,				Balance Sheet	June 30,
	Location	2010		2009		Location	2010			2009
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments					Derivative financial instruments
	and Other assets	$	0.3	$	2.9	and Other noncurrent liabilities	$	(42.8	)	$	(74.3	)
Foreign currency contracts	Derivative financial instruments
	and Other assets		16.9		3.1	Other noncurrent liabilities		—			(2.0	)
						Derivative financial instruments
Interest rate contracts	Derivative financial instruments		—		3.7	and Other noncurrent liabilities		(16.4	)		(31.6	)
Total Derivatives Designated as Hedging Instruments		$	17.2	$	9.7			(59.2	)		(107.9	)
Derivatives Accounted for under ASC 980:
Commodity contracts	Derivative financial instruments	$	0.6	$	—	Derivative financial instruments	$	(0.8	)	$	—
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments
	and Other assets	$	2.8	$	4.5
Total Derivatives		$	20.6	$	14.2		$	(60.0	)	$	(107.9	)

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

The following tables provide information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest for the three and nine months ended June 30, 2010 and 2009:

Three Months Ended June 30:

	Gain or (Loss)						Gain or (Loss)						Location of
	Recognized in						Reclassified from						Gain or (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2010			2009			2010			2009			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(14.6	)	$	17.9		$	(7.7	)	$	(64.6	)	Cost of sales
Foreign currency contracts		5.3			(6.1	)		0.1			0.2		Cost of sales
Interest rate contracts		(6.3	)		10.4			(3.9	)		(2.9	)	Interest expense /other income
Total	$	(15.6	)	$	22.2		$	(11.5	)	$	(67.3	)
Net Investment Hedges:
Foreign currency contracts	$	6.1		$	(2.3	)

	Gain or (Loss)
	Recognized in Income					Location of Gain or (Loss)
	2010			2009		Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	(0.1	)	$	1.0	Cost of sales
Commodity contracts		1.0			0.2	Operating expenses / other income
Total	$	0.9		$	1.2

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

Nine Months Ended June 30:

	Gain or (Loss)						Gain or (Loss)						Location of
	Recognized in						Reclassified from						Gain or (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2010			2009			2010			2009			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(30.1	)	$	(249.7	)	$	(14.1	)	$	(269.1	)	Cost of sales
Foreign currency contracts		12.2			3.0			0.7			5.0		Cost of sales
Interest rate contracts		(7.2	)		(37.2	)		(24.4	)		(3.9	)	Interest expense/other income
Total	$	(25.1	)	$	(283.9	)	$	(37.8	)	$	(268.0	)
Net Investment Hedges:
Foreign currency contracts	$	11.2		$	(0.2	)

	Gain or (Loss)
	Recognized in Income					Location of Gain or (Loss)
	2010		2009			Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	0.1	$	0.9		Cost of sales
Commodity contracts		1.4		(0.6	)	Operating expenses / other income
Total	$	1.5	$	0.3

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 the three and nine months ended June 30, 2010 and 2009. During the three months ended March 31, 2010, the Partnership’s management determined that it was likely that the Partnership would not issue $150 of long-term debt during the summer of 2010 due to the Partnership’s strong cash flow and anticipated extension of all or a portion of AmeriGas OLP’s $75 unsecured revolving credit agreement (“2009 AmeriGas Supplemental Credit Agreement”). As a result, the Partnership discontinued cash flow hedge accounting treatment for IRPAs associated with this previously anticipated Fiscal 2010 $150 long-term debt issuance and recorded a $12.2 loss which is reflected in other (income) expense, net on the Condensed Consolidated Statement of Income for nine months ended June 30, 2010. In March 2009, the Partnership recorded losses of $1.7 as a result of the discontinuance of cash flow hedge accounting associated with IRPAs.

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 business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Millions of dollars and euros, except per share amounts)

13. Inventories

Inventories comprise the following:

	June 30,		September 30,		June 30,
	2010		2009		2009
Non-utility LPG and natural gas	$	138.2	$	118.0	$	112.0
Gas Utility natural gas		60.3		189.7		99.0
Materials, supplies and other		50.7		55.5		58.1
Total inventories	$	249.2	$	363.2	$	269.1

At June 30, 2010, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”). 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 SCAAs with non-affiliates at June 30, 2010, September 30, 2009 and June 30, 2009 comprising 4.2 billion cubic feet (“bcf”), 1.3 bcf and 0.8 bcf of natural gas was $23.2, $10.5 and $6.7, respectively.

14. Subsequent Event — Sale of Atlantic Energy

On July 30, 2010, Energy Services sold all of its interest in its second-tier, wholly owned subsidiary Atlantic Energy, Inc. (“Atlantic Energy”) to DCP Midstream Partners, L.P. for $49.0 cash plus an amount for inventory and other working capital. Atlantic Energy owns and operates a 20 million gallon marine import and transshipment facility located in the port of Chesapeake, Virginia. The Company expects to record an after-tax gain of approximately $16.0 which will be reflected in results for the quarter ending September 30, 2010.

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UGI CORPORATION AND SUBSIDIARIES

ITEM 2: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATION

Forward-Looking Statements

Information contained in this Management’s Discussion and Analysis of Financial Condition and Results of Operations may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other LPG, oil, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) large customer, counter-party or supplier defaults; (12) liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and LPG; (13) political, regulatory and economic conditions in the United States and in foreign countries, including foreign currency exchange rate fluctuations, particularly the euro; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (15) changes in commodity market prices resulting in significantly higher cash collateral requirements; (16) reduced distributions from subsidiaries; and (17) the timing and success of our acquisitions and investments to grow our businesses.

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

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UGI CORPORATION AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended June 30, 2010 (“2010 three-month period”) with the three months ended June 30, 2009 (“2009 three-month period”) and the nine months ended June 30, 2010 (“2010 nine-month period”) with the nine months ended June 30, 2009 (“2009 nine-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 5 to the condensed consolidated financial statements.

Executive Overview

Because most of our businesses sell energy products used in large part for heating purposes, our results are significantly influenced by temperatures in our service territories, particularly during the peak-heating season months of October through March. As a result, our earnings are generally higher in our first and second fiscal quarters.

We recorded net income attributable to UGI Corporation of $3.4 million for the 2010 three-month period compared to a net loss attributable to UGI Corporation of $3.6 million in the prior-year three-month period which included a $10.0 million after-tax charge related to the Antargaz Competition Authority Matter. Excluding the effects of the $10.0 million after-tax charge in the prior-year period, 2010 three-month period results were lower than the prior year principally reflecting lower International Propane results partially offset by higher Gas Utility results. Our 2010 three-month period results reflect spring temperatures that were significantly warmer than normal and, except for our International Propane segment, were significantly warmer than the prior-year three-month period. International Propane unit margins were lower in the 2010 three-month period compared to the higher than normal margins experienced in the prior year which resulted from a precipitous decline in LPG commodity costs that occurred as Antargaz entered the Fiscal 2009 winter heating season. International Propane retail volumes sold were higher in the 2010 three-month period principally as a result of colder spring weather. Our improved Gas Utility results in the 2010 three-month period, notwithstanding the significantly warmer spring weather, resulted in large part from the August 2009 PNG Gas and CPG Gas base rate increases and lower operating expenses.

We recorded net income attributable to UGI Corporation of $258.9 million for the 2010 nine-month period compared to net income attributable to UGI Corporation of $269.5 million in the prior-year nine-month period. Net income attributable to UGI in the 2010 nine-month period includes a $3.3 million after-tax loss associated with the discontinuance of Partnership interest rate hedges. Net income attributable to UGI Corporation in the 2009 nine-month period includes (1) an after-tax gain of $10.4 million from the Partnership’s November 2008 sale of its California LPG storage facility and (2) the previously mentioned $10.0 million after-tax charge for the Antargaz Competition Authority Matter. International Propane’s contribution to net income attributable to UGI Corporation in the 2010 nine-month period was significantly lower as the prior-year’s results benefited from unit margins at Antargaz that were significantly higher than normal following a precipitous decline in LPG commodity costs that occurred as Antargaz entered the Fiscal 2009 winter heating season. The decline in 2010 nine-month period International Propane results was substantially offset by higher Gas Utility net income, resulting in large part from lower operating expenses and the effects of the PNG Gas and CPG Gas August 2009 base rate increase, and greater net income from Energy Services due in large part to higher total natural gas and retail power margins.

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UGI CORPORATION AND SUBSIDIARIES

The U.S. dollar was slightly stronger versus the euro in the 2010 three-month period and slightly weaker versus the euro in the 2010 nine-month period as compared with the associated three and nine-month periods in the prior year. The effects on net income from these differences in currency exchange rates were not material for all periods presented due in part to the effects of gains and losses on forward currency contracts used to hedge purchases of dollar-denominated LPG.

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

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
Net income (loss) attributable to UGI Corporation by business unit:	2010			2009			2010			2009
	(Millions of dollars)						(Millions of dollars)
Net income (loss) attributable to UGI Corporation:
AmeriGas Propane	$	(2.9	)	$	(2.9	)	$	56.5	(a)	$	71.6	(b)
International Propane		(3.5	)		(8.0	)		70.5			86.7
Gas Utility		2.4			1.3			83.5			71.4
Electric Utility		1.2			1.7			5.7			7.3
Energy Services		5.5			5.1			46.1			35.4
Corporate & Other		0.7			(0.8	)		(3.4	)		(2.9	)
Net income (loss) attributable to UGI Corporation	$	3.4		$	(3.6	)	$	258.9		$	269.5

(a)	Includes net loss of $3.3 million associated with discontinuance of Partnership interest rate hedges.
(b)	Includes net income of $10.4 million from sale of the Partnership’s California LPG storage facility.

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UGI CORPORATION AND SUBSIDIARIES

2010 three-month period compared to the 2009 three-month period

AmeriGas Propane:							Increase
For the three months ended June 30,	2010			2009			(Decrease)
(Millions of dollars)
Revenues	$	396.6		$	372.7		$	23.9		6.4	%
Total margin (a)	$	160.8		$	162.4		$	(1.6	)	(1.0	)%
Partnership EBITDA (b)	$	27.2		$	25.4		$	1.8		7.1	%
Operating income	$	5.3		$	4.4		$	0.9		20.5	%
Retail gallons sold (millions)		150.1			160.0			(9.9	)	(6.2	)%
Degree days — % (warmer) than normal (c)		(17.0	)%		(2.8	)%		—		—

(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 5 to condensed 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. Prior-year data has been adjusted to correct a NOAA error.

Based upon heating degree-day data, average temperatures in the Partnership’s service territories were 17.0% warmer than normal during the 2010 three-month period compared with temperatures in the prior-year period that were 2.8% warmer than normal. Retail propane gallons sold were lower than in the prior-year period due principally to the warmer weather, the lingering effects of the economic recession and customer conservation.

Retail propane revenues increased $18.7 million during the 2010 three-month period reflecting a $38.4 million increase due to higher average retail selling prices partially offset by a $19.7 million decrease as a result of the lower retail volumes sold. Wholesale propane revenues increased $4.9 million principally reflecting higher year-over-year wholesale selling prices. Average wholesale propane commodity prices at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 54% higher in the 2010 three-month period compared to such prices in the 2009 three-month period. The lower average wholesale prices in the prior-year period followed a precipitous decline in such prices principally during the first quarter of Fiscal 2009. Total cost of sales increased $25.5 million, to $235.8 million, principally reflecting the effects of the previously mentioned higher 2010 three-month period propane product costs.

Total margin declined $1.6 million in the 2010 three-month period primarily due to the lower retail volumes sold offset in large part by the effects of slightly higher average retail unit margins.

Notwithstanding the $1.6 million decline in total margin, Partnership EBITDA increased $1.8 million reflecting lower operating and administrative expenses during the 2010 three-month period and higher other income. The lower operating and administrative expenses principally reflects lower compensation and benefits and self-insured liability and casualty expenses partially offset by higher uncollectible accounts and vehicle fuel expense. Operating income in the 2010 three-month period increased $0.9 million reflecting the $1.8 million increase in EBITDA partially offset by slightly higher depreciation and amortization expense associated with acquisitions and plant and equipment expenditures made since the 2009 three-month period.

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International Propane:							Increase
For the three months ended June 30,	2010			2009			(Decrease)
(Millions of euros) (a)
Revenues	€	144.5		€	121.0		€	23.5		19.4	%
Total margin (b)	€	61.5		€	71.6		€	(10.1	)	(14.1	)%
Operating income	€	1.3		€	1.2		€	0.1		8.3	%
Loss before income taxes	€	(4.9	)	€	(3.3	)	€	1.6		48.5	%
(Millions of dollars)
Revenues	$	191.8		$	164.9		$	26.9		16.3	%
Total margin (b)	$	79.9		$	97.5		$	(17.6	)	(18.1	)%
Operating income	$	2.9		$	0.3		$	2.6		866.7	%
Loss before income taxes	$	(5.0	)	$	(6.2	)	€	(1.2	)	(19.4	)%
Antargaz retail gallons sold		49.3			48.1			1.2		2.5	%
Degree days — % (warmer) than normal (c)		(9.6	)%		(29.3	)%		—		—

(a)	Euro amounts exclude amounts associated with the Company’s propane operation in China which amounts are not material.
(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 9.6% warmer than normal during the 2010 three-month period compared with temperatures that were approximately 29.3% warmer than normal during the prior-year period. Temperatures in Flaga’s service territory were also warmer than normal but colder than the prior year. Average LPG wholesale product prices were more than 65% higher in the 2010 three-month period compared with such prices in the prior-year period. The lower average wholesale prices in the prior-year period followed a precipitous decline in such prices principally during the first quarter of Fiscal 2009. Antargaz’ retail volumes were higher than the prior-year period due principally to the colder 2010 three-month period spring weather.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. During the 2010 three-month period, the average currency translation rate was $1.28 per euro compared to a rate of $1.37 per euro during the prior-year three-month period. The effects of the stronger dollar did not have a material impact on International Propane net income.

International Propane euro-based revenues increased €23.5 million or 19.4% principally reflecting higher Antargaz average selling prices and higher retail gallons sold. The higher average selling prices reflect the effects of the previously mentioned year-over-year increase in wholesale LPG product costs. In U.S. dollars, revenues increased $26.9 million or 16.3% principally reflecting the higher base currency revenues partially offset by the effects of the stronger U.S. dollar. International Propane’s euro-based total cost of sales increased to €83.0 million in the 2010 three-month period from €49.4 million in the prior year, an increase of 68.0%, principally reflecting the higher per-unit LPG commodity costs. On a U.S. dollar basis, cost of sales increased to $111.9 million from $67.4 million in the prior-year period, an increase of 66.0%, principally reflecting the higher euro base-currency per unit commodity costs partially offset by the effects of the stronger U.S. dollar.

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UGI CORPORATION AND SUBSIDIARIES

International Propane euro-denominated total margin decreased €10.1 million or 14.1% in the 2010 three-month period principally reflecting lower average Antargaz retail unit margins. Flaga’s total margin was lower than the prior year also reflecting lower average unit margins. Euro-denominated retail unit margins were lower in the 2010 three-month period as prior-year unit margins were higher than normal due to the previously mentioned rapid and sharp decline in LPG commodity costs that occurred entering the Fiscal 2009 winter heating season. In U.S. dollars, total margin decreased $17.6 million or 18.1% principally reflecting the lower euro-denominated total margin.

Notwithstanding the €10.1 million decrease in total margin, International Propane euro base-currency operating income increased €0.1 million. The prior-year three month period includes a €7.1 million charge associated with the Antargaz Competition Authority Matter while the 2010 three-month period reflects lower operating and administrative costs at Antargaz and Flaga. On a U.S. dollar basis, operating income increased $2.6 million, notwithstanding the $17.6 million decline in U.S. dollar denominated total margin, reflecting the absence of the $10.0 million charge for the Antargaz Competition Authority Matter recorded in the prior year and lower U.S. dollar-denominated operating and administrative expenses. Euro base-currency loss before income taxes was €1.6 million higher than in the prior-year period reflecting a €1.6 million loss from equity investees principally resulting from additional accruals in the 2010 three-month period relating to the shut down of an underground storage facility. In U.S. dollars, loss before income taxes decreased $1.2 million principally reflecting the previously mentioned higher U.S. dollar-denominated operating income partially offset by the storage facility shut-down accrual.

Gas Utility:							Increase
For the three months ended June 30,	2010			2009			(Decrease)
(Millions of dollars)
Revenues	$	149.1		$	176.9		$	(27.8	)	(15.7	)%
Total margin (a)	$	66.1		$	67.1		$	(1.0	)	(1.5	)%
Operating income	$	13.8		$	12.9		$	0.9		7.0	%
Income before income taxes	$	3.8		$	2.6		$	1.2		46.2	%
System throughput — billions of cubic feet (“bcf”)		28.0			25.8			2.2		8.5	%
Degree days — % (warmer) than normal (b)		(26.4	)%		(6.5	)%		—		—

(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 26.4% warmer than normal in the 2010 three-month period compared with temperatures that were 6.5% warmer than normal in the prior-year period. Total distribution system throughput increased 2.2 bcf in the 2010 three-month period principally due to greater delivery service volumes including certain low margin interruptible delivery service volumes. The increase in delivery service volumes was partially offset by a decline in volumes sold and transported to Gas Utility’s core-market customers resulting in large part from the warmer spring weather. Gas Utility’s core-market customers 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.

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Gas Utility revenues decreased $27.8 million during the 2010 three-month period principally reflecting a decline in revenues from retail core-market customers partially offset by a $6.1 million increase in low-margin off-system sales. The decrease in retail core-market revenues principally resulted from lower retail core-market volumes sold and lower average purchased gas cost (“PGC”) rates partially offset by the effects of the PNG Gas and CPG Gas base operating revenue increases that became effective August 28, 2009. Under Gas Utility’s PGC recovery mechanisms, 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 $83.0 million in the 2010 three-month period compared with $109.8 million in the prior-year period principally reflecting the lower average PGC rates and, to a much lesser extent, the lower retail core-market sales.

Notwithstanding the PNG Gas and CPG Gas base rate increases, Gas Utility total margin decreased $1.0 million in the 2010 three-month period. The decrease reflects the impact of the previously mentioned decline in retail core-market volumes.

Gas Utility operating income during the 2010 three-month period increased $0.9 million principally reflecting lower operating and administrative costs partially offset by the previously mentioned decrease in total margin. The 2010 three-month period operating and administrative costs include, among other things, lower customer accounts-related expenses and lower costs associated with environmental matters. The $1.2 million increase in income before income taxes reflects the previously mentioned higher operating income and slightly lower interest expense on lower bank loan borrowings.

Electric Utility:					Increase
For the three months ended June 30,	2010		2009		(Decrease)
(Millions of dollars)
Revenues	$	25.3	$	30.8	$	(5.5	)	(17.9	)%
Total margin (a)	$	8.1	$	9.4	$	(1.3	)	(13.8	)%
Operating income	$	2.6	$	3.3	$	(0.7	)	(21.2	)%
Income before income taxes	$	2.2	$	2.8	$	(0.6	)	(21.4	)%
Distribution sales — millions of kilowatt hours (“gwh”)		218.6		209.8		8.8		4.2	%

(a) Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $1.4 million and $1.7 million during the three-month periods ended June 30, 2010 and 2009, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Condensed Consolidated Statements of Income.

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UGI CORPORATION AND SUBSIDIARIES

Electric Utility’s kilowatt-hour sales in the 2010 three-month period were 4.2% higher than in the prior year. The increase in sales reflects the effects of warmer late spring and early summer 2010 three-month period weather on air-conditioning-related sales volumes. Electric Utility revenues decreased $5.5 million principally as a result of lower default service (“DS”) rates which became effective January 1, 2010. Electric Utility decreased its DS rates effective January 1, 2010 pursuant to a January 22, 2009 settlement of its DS rate filing with the PUC. This reduced average costs to a residential general and residential heating customer by nearly 10% and 4%, respectively, over such costs in Fiscal 2009 and also reduced rates to commercial and industrial customers. Under DS rates, Electric Utility is no longer subject to electricity price and congestion cost risk as it is permitted to pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in excess of actual costs of electricity as was possible under previous Provider of Last Resort (“POLR”) rates in effect prior to January 1, 2010. Electric Utility cost of sales declined to $15.8 million in the 2010 three-month period compared to $19.7 million in the 2009 three-month period principally reflecting lower purchased power costs.

Electric Utility total margin declined $1.3 million in the 2010 three-month period reflecting the reduction in margin resulting from implementation of lower DS rates effective January 1, 2010.

Electric Utility operating income and income before income taxes in the 2010 three-month period were $0.7 million and $0.6 million lower, respectively, reflecting the previously mentioned lower total margin partially offset by slightly lower operating and administrative costs.

Energy Services:
For the three months ended June 30,	2010		2009		Decrease
(Millions of dollars)
Revenues	$	198.6	$	223.4	$	(24.8	)	(11.1	)%
Total margin (a)	$	21.3	$	23.0	$	(1.7	)	(7.4	)%
Operating income	$	6.9	$	8.6	$	(1.7	)	(19.8	)%
Income before income taxes	$	6.9	$	8.6	$	(1.7	)	(19.8	)%

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

Energy Services total revenues decreased $24.8 million in the 2010 three-month period principally reflecting lower revenues from natural gas marketing and electric generation due to lower 2010 three-month period average unit sales prices and volumes sold partially offset by the effects of higher retail power sales.

Total margin from Energy Services decreased $1.7 million principally reflecting lower electric generation and natural gas marketing total margin. The decrease in electric generation total margin principally reflects lower volumes sold due to electric generation plant outages and lower spot and fixed prices for electricity. These decreases were partially offset by higher total retail power margin, and to a lesser extent, higher margin from asset management activities. The decreases in Energy Services’ operating income and income before income taxes principally reflect the previously mentioned decrease in total margin.

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UGI CORPORATION AND SUBSIDIARIES

Consolidated Effective Tax Rate

During the 2010 three-month period, the Company’s Fiscal 2010 estimated annual effective tax rate was slightly reduced primarily to reflect the benefit of tax credits related to a recently completed solar energy project. Because pre-tax income is relatively low in the third fiscal quarter, and because the effects of the change in the estimated annual income tax rate on prior quarters’ pre-tax income is reflected in the 2010 three-month period, the 2010 three-month period effective income tax rate is not meaningful.

2010 nine-month period compared to the 2009 nine-month period

AmeriGas Propane:							Increase
For the nine months ended June 30,	2010			2009			(Decrease)
(Millions of dollars)
Revenues	$	1,939.3		$	1,923.1		$	16.2		0.8	%
Total margin (a)	$	774.2		$	793.3		$	(19.1	)	(2.4	)%
Partnership EBITDA (b)	$	323.7		$	376.7		$	(53.0	)	(14.1	)%
Operating income	$	261.2		$	317.2		$	(56.0	)	(17.7	)%
Retail gallons sold (millions)		746.7			781.1			(34.4	)	(4.4	)%
Degree days — % (warmer) than normal (c)		(1.5	)%		(2.5	)%		—		—

(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 5 to condensed consolidated financial statements). Partnership EBITDA (and operating income) in the 2010 nine-month period include a pre-tax loss of $12.2 million associated with the discontinuance of interest rate hedges. Partnership EBITDA (and operating income) in the 2009 nine-month period includes a pre-tax gain of $39.9 million associated with the sale of the Partnership’s California LPG storage facility.
(c)	Deviation from average heating degree-days for the 30-year period 1971-2000 based upon national weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for 335 airports in the United States, excluding Alaska. Prior-year data has been adjusted to correct a NOAA error.

Based upon heating degree-day data, average temperatures in our service territories were 1.5% warmer than normal during the 2010 nine-month period compared with temperatures in the prior-year period that were 2.5% warmer than normal. Notwithstanding the slightly colder 2010 nine-month period weather, retail gallons sold were lower than in the prior-year period reflecting, among other things, the lingering effects of the economic recession and customer conservation.

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UGI CORPORATION AND SUBSIDIARIES

Retail propane revenues declined $13.3 million during the 2010 nine-month period reflecting a $74.6 million decrease due to the lower retail volumes sold partially offset by a $61.3 million increase as a result of higher average retail sales prices. Wholesale propane revenues increased $37.5 million principally reflecting higher year-over-year wholesale selling prices and, to a lesser extent, higher wholesale volumes sold. Average wholesale propane prices at Mont Belvieu, Texas, were approximately 57% higher during the 2010 nine-month period compared with such average wholesale propane prices during the 2009 nine-month period. The lower average wholesale propane prices in the prior-year nine-month period principally resulted from a precipitous decline in such prices that occurred during the first quarter of Fiscal 2009. Other non-propane revenues were $8.0 million lower in the 2010 nine-month period due in large part to lower installation and other services revenue. Total cost of sales increased $35.3 million, to $1,165.1 million, principally reflecting the higher 2010 wholesale propane product costs and the higher wholesale volumes sold partially offset by the impact on cost of sales of the lower retail volumes sold.

Total margin was $19.1 million lower in the 2010 nine-month period primarily due to the lower retail volumes sold partially offset by slightly higher average retail unit margins.

The $53.0 million decrease in Partnership EBITDA during the 2010 nine-month period reflects (1) the absence of a $39.9 million pre-tax gain recorded in the prior-year nine-month period associated with the November 2008 sale of the Partnership’s California LPG storage facility; (2) the previously mentioned $19.1 million decline in 2010 nine-month period total margin; and (3) the $12.2 million loss from the discontinuance of interest rate hedges. During the three months ended March 31, 2010, the Partnership’s management determined that it was likely that it would not issue a previously anticipated $150 million of long-term debt during the summer of 2010. As a result, the Partnership discontinued cash flow hedge accounting treatment for interest rate protection agreements associated with this previously anticipated debt issuance and recorded a $12.2 million loss which is reflected in other (income) expense, net on the Condensed Consolidated Statements of Income for the nine months ended June 30, 2010. These previously mentioned declines in EBITDA were partially offset by a $14.3 million decrease in operating and administrative expenses largely due to lower self-insured liability and casualty expenses and lower compensation and benefits expense.

Operating income in the 2010 nine-month period decreased $56.0 million reflecting the previously mentioned $53.0 million decrease in EBITDA and slightly higher depreciation and amortization expense on fixed assets acquired during the past year. Partnership interest expense was $3.5 million lower in the 2010 nine-month period reflecting lower interest expense on lower long-term debt outstanding.

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UGI CORPORATION AND SUBSIDIARIES

International Propane:							Increase
For the nine months ended June 30,	2010			2009			(Decrease)
(Millions of euros) (a)
Revenues	€	631.7		€	590.7		€	41.0		6.9	%
Total margin (b)	€	289.5		€	331.6		€	(42.1	)	(12.7	)%
Operating income	€	89.4		€	117.6		€	(28.2	)	(24.0	)%
Income before income taxes	€	74.1		€	102.7		€	(28.6	)	(27.8	)%
(Millions of dollars)
Revenues	$	885.1		$	780.6		$	104.5		13.4	%
Total margin (b)	$	403.9		$	438.3		$	(34.4	)	(7.8	)%
Operating income	$	127.6		$	154.1		$	(26.5	)	(17.2	)%
Income before income taxes	$	106.3		$	133.6		$	(27.3	)	(20.4	)%
Antargaz retail gallons sold		237.9			247.4			(9.5	)	(3.8	)%
Degree days — % (warmer) than normal (c)		(0.1	)%		(1.0	)%		—		—

(a)	Euro amounts exclude amounts associated with the Company’s propane operation in China which amounts are not material.
(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.

International Propane operating results in the 2010 nine-month period reflect the consolidation of Zentraleuropa LPG Holdings GmbH (“ZLH”) for the full nine-month period. In the 2009 nine-month period, ZLH was consolidated only for the period subsequent to Flaga’s acquisition in January 2009 of the 50% interest in ZLH it did not already own.

Based upon heating degree day data, temperatures in Antargaz’ service territory were essentially normal during the 2010 nine-month period compared with temperatures that were slightly warmer than normal during the prior-year period. Temperatures in Flaga’s service territory were slightly colder than the prior year. Average LPG wholesale product prices were higher in the 2010 nine-month period compared with such prices in the prior-year period. The average wholesale commodity price for propane in northwest Europe during the 2010 nine-month period was approximately 54% higher than such price during the same period last year, and average wholesale butane prices were approximately 60% higher. The lower average LPG wholesale prices in the prior-year period reflect a precipitous decline in propane and butane wholesale prices principally during the first quarter of Fiscal 2009. Antargaz’ 2010 nine-month period retail propane volumes were lower than in the prior-year period principally as a result of reduced demand for crop drying earlier in the period, due to an exceptionally dry 2009 summer, the effects of customer conservation and the lingering effects of the economic recession in France.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. During the 2010 nine-month period, the average currency translation rate was $1.38 per euro compared to a rate of $1.33 per euro during the prior-year nine-month period. The difference in exchange rates did not have a material impact on International Propane net income.

International Propane euro-based revenues increased €41.0 million or 6.9%. The higher 2010 nine-month period revenues resulted from the full-period consolidation of ZLH and higher revenues reflecting higher wholesale LPG product costs partially offset by the lower retail volume sales. In U.S. dollars, revenues increased $104.5 million or 13.4% principally reflecting the effects of the weaker U.S. dollar on euro base-currency revenues. International Propane’s total cost of sales increased to €342.2 million in the 2010 nine-month period from €259.1 million in the prior year, an increase of 32.1%, reflecting the higher per-unit LPG commodity costs and the consolidation of ZLH. On a U.S. dollar basis, cost of sales increased to $481.2 million from $342.3 million in the prior-year period, an increase of 40.6%, principally reflecting the higher euro base-currency cost of sales and the effects of the weaker U.S. dollar.

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UGI CORPORATION AND SUBSIDIARIES

International Propane euro-denominated total margin decreased €42.1 million or 12.7% in the 2010 nine-month period principally reflecting lower average Antargaz retail unit margins and the lower Antargaz retail gallons sold partially offset by incremental total margin from the full-period consolidation of ZLH. Antargaz’ euro-denominated retail unit margins were lower in the 2010 nine-month period compared with the prior-year period as the prior-year unit margins were higher than normal due to the rapid and sharp decline in LPG commodity costs that occurred as Antargaz entered the Fiscal 2009 winter heating season. In U.S. dollars, total margin decreased $34.4 million or 7.8% reflecting the lower euro-denominated total margin partially offset by the effects of the weaker dollar on translated euro base-currency revenues and cost of sales.

International Propane euro base-currency operating income decreased €28.2 million or 24.0% principally reflecting the previously mentioned decrease in International Propane total margin offset by the absence of a €7.1 million charge associated with the Antargaz Competition Authority matter recorded in the prior-year period and lower current-year operating and administrative expenses. International Propane euro base-currency operating and administrative expenses declined in the current year as lower Antargaz employee compensation and benefits expense, lower vehicle expense and a decrease in the French business tax were partially offset by higher Flaga operating and administrative expenses and greater depreciation expense resulting from the full-period consolidation of ZLH. On a U.S. dollar basis, operating income decreased $26.5 million or 17.2% reflecting the previously mentioned decrease in U.S. dollar-denominated total margin partially offset by the absence of the $10.0 million charge for the Antargaz Competition Authority Matter recorded in the prior-year period. Euro base-currency income before income taxes was €28.6 million or 27.8% lower than in the prior-year period principally reflecting the decline in operating income and a €0.8 million increase in loss from Antargaz and Flaga equity investees. In U.S. dollars, income before income taxes decreased $27.3 million or 20.4%.

Gas Utility:							Increase
For the nine months ended June 30,	2010			2009			(Decrease)
(Millions of dollars)
Revenues	$	922.3		$	1,130.1		$	(207.8	)	(18.4	)%
Total margin (a)	$	338.1		$	334.4		$	3.7		1.1	%
Operating income	$	168.6		$	149.8		$	18.8		12.6	%
Income before income taxes	$	138.1		$	118.1		$	20.0		16.9	%
System throughput — billions of cubic feet (“bcf”)		124.9			126.4			(1.5	)	(1.2	)%
Degree days — % (warmer) colder than normal (b)		(4.5	)%		3.9	%		—		—

(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.

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UGI CORPORATION AND SUBSIDIARIES

Temperatures in the Gas Utility service territory based upon heating degree days were 4.5% warmer than normal in the 2010 nine-month period compared with temperatures that were 3.9% colder than normal in the prior-year period. Total distribution system throughput decreased 1.5 bcf in the 2010 nine-month period principally reflecting the effects of the warmer weather on core-market customers, the lingering effects of the economic recession and customer conservation partially offset by an increase in delivery service volumes, principally low margin interruptible volumes.

Gas Utility revenues decreased $207.8 million during the 2010 nine-month period principally reflecting a decline in revenues from retail core-market customers. The decrease in retail core-market revenues principally resulted from the lower retail core-market volumes and lower average PGC rates partially offset by the effects of the PNG Gas and CPG Gas base operating revenue increases that became effective August 28, 2009. Gas Utility’s cost of gas was $584.2 million in the 2010 nine-month period compared with $795.7 million in the prior-year period principally reflecting the lower retail core-market sales and the lower average PGC rates.

Notwithstanding the decrease in distribution system volumes, Gas Utility total margin increased $3.7 million in the 2010 nine-month period. The increase is principally the result of the PNG Gas and CPG Gas base operating revenue increases partially offset by the effect on total margin from the lower core-market volumes.

Gas Utility operating income during the 2010 nine-month period increased $18.8 million principally reflecting lower operating and administrative costs and the previously mentioned increase in total margin. The 2010 nine-month period operating and administrative costs include, among other things, lower charges associated with environmental matters, lower provisions for uncollectible accounts and lower UGI corporate allocated expenses. These decreases in operating and administrative expenses were partially offset by higher 2010 nine-month period pension expense. The increase in income before income taxes reflects the previously mentioned higher operating income and lower interest expense due to lower average bank loan borrowings.

Electric Utility:
For the nine months ended June 30,	2010		2009		Decrease
(Millions of dollars)
Revenues	$	90.9	$	104.8	$	(13.9	)	(13.3	)%
Total margin (a)	$	27.9	$	32.0	$	(4.1	)	(12.8	)%
Operating income	$	11.1	$	13.8	$	(2.7	)	(19.6	)%
Income before income taxes	$	9.8	$	12.5	$	(2.7	)	(21.6	)%
Distribution sales — millions of kilowatt hours (“gwh”)		723.8		735.8		(12.0	)	(1.6	)%

(a) Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $5.0 million and $5.7 million during the nine-month periods ended June 30, 2010 and 2009, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Condensed Consolidated Statements of Income.

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UGI CORPORATION AND SUBSIDIARIES

Temperatures based upon heating degree days were approximately 5.9% warmer than in the prior-year period. Electric Utility’s kilowatt-hour sales in the 2010 nine-month period were 1.6% lower than in the prior year. The decline in sales principally reflects the effects of the warmer 2010 nine-month period weather on heating-related sales volumes and the lingering effects of the economic recession. These decreases were partially offset by higher air-conditioning sales on warmer late spring and early 2010 summer weather. Electric Utility revenues decreased $13.9 million principally as a result of the previously mentioned lower DS rates effective January 1, 2010 and the lower sales. Electric Utility cost of sales declined to $58.0 million in the 2010 nine-month period compared to $67.1 million in the 2009 nine-month period principally reflecting lower purchased power costs and the effects of the lower sales.

Electric Utility total margin declined $4.1 million in the 2010 nine-month period reflecting the reduction in margin resulting from the implementation of lower DS rates effective January 1, 2010 and, to a much lesser extent, the effects of the lower 2010 nine-month period sales.

Electric Utility operating income and income before income taxes in the 2010 nine-month period were both $2.7 million lower reflecting the lower total margin partially offset by lower operating and administrative expenses.

Energy Services:					Increase
For the nine months ended June 30,	2010		2009		(Decrease)
(Millions of dollars)
Revenues	$	949.5	$	1,007.1	$	(57.6	)	(5.7	)%
Total margin (a)	$	118.6	$	104.8	$	13.8		13.2	%
Operating income	$	75.4	$	60.0	$	15.4		25.7	%
Income before income taxes	$	75.4	$	60.0	$	15.4		25.7	%

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

Energy Services total revenues decreased $57.6 million in the 2010 nine-month period due to lower average natural gas marketing and electric generation sales prices partially offset by the effects of (1) higher retail power sales; (2) higher average propane sales prices and higher propane volumes sold; and (3) a 2.8% increase in natural gas marketing volumes sold.

Total margin from Energy Services increased $13.8 million principally reflecting (1) higher natural gas unit margins and, to a lesser extent, the higher natural gas volumes sold and (2) higher total retail power margin on higher volumes sold and greater average unit margins. The increases in natural gas marketing and retail power total margin includes the impact of marketing initiatives focused on the small commercial customer segment. These increases in margin were partially offset by a decrease in margin from asset management activities and lower electric generation total margin from lower average unit margins. The increases in Energy Services’ operating income and income before income taxes largely reflects the previously mentioned increase in total margin and lower operating and administrative costs including, among other things, lower asset management fees paid and lower electric generation operating and maintenance costs.

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UGI CORPORATION AND SUBSIDIARIES

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

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 in commodity futures brokerage accounts restricted from withdrawal, totaled $241.8 million at June 30, 2010 compared with $280.1 million at September 30, 2009. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at June 30, 2010 and September 30, 2009, UGI had $118.6 million and $102.7 million, respectively, of cash and cash equivalents.

The Company’s debt outstanding at June 30, 2010 totaled $2,064.9 million (including current maturities of long-term debt of $572.9 million) compared to $2,296.2 million of debt outstanding (including current maturities of long-term debt of $94.5 million) at September 30, 2009. Total debt outstanding at June 30, 2010 consists of (1) $884.1 million of Partnership debt; (2) $527.4 million (€431.3 million) of International Propane debt; (3) $640 million of UGI Utilities’ debt; and (4) $13.4 million of other debt. Long-term debt maturing in the next twelve months classified as current at June 30, 2010 principally comprises (1) $464.7 million (€380 million) associated with Antargaz’ Senior Facilities Term loan due March 2011; (2) $80 million of AmeriGas OLP First Mortgage Notes due July 2010; (3) $14.7 million of AmeriGas Partners Senior Notes due May 2011; and (4) $9.0 million (€7.4 million) of Flaga term loans.

AmeriGas Partners’ total debt at June 30, 2010 includes $779.7 million of AmeriGas Partners’ Senior Notes, $80 million of AmeriGas OLP First Mortgage Notes and $9.4 million of other long-term debt. AmeriGas Partners’ total debt at June 30, 2010 also includes $15 million of AmeriGas OLP bank loan borrowings.

International Propane’s total debt at June 30, 2010 includes $464.7 million (€380 million) outstanding under Antargaz’ Senior Facilities term loan and a combined $39.9 million (€32.6 million) outstanding under Flaga’s two term loans. Total International Propane debt outstanding at June 30, 2010 also includes combined borrowings of $20.2 million (€16.5 million) outstanding under Flaga’s working capital facilities and $2.6 million (€2.2 million) of other long-term debt.

UGI Utilities’ total debt at June 30, 2010 includes long-term debt comprising $383 million of Senior Notes and $257 million of Medium-Term Notes. At June 30, 2010, there were no amounts outstanding under UGI Utilities’ Revolving Credit Agreement.

As previously mentioned, as a result of the adoption of new accounting guidance, noncontrolling interests in our consolidated subsidiaries, principally AmeriGas Partners, are now reflected in equity on our consolidated balance sheets. The new classification of noncontrolling interests in equity had the effect of decreasing the Company’ ratio of debt to total equity for all periods presented.

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UGI CORPORATION AND SUBSIDIARIES

AmeriGas Partners. In order to meet its short-term cash needs, AmeriGas OLP has a $200 million credit agreement (“Credit Agreement”) which expires on October 15, 2011. AmeriGas OLP also has a $75 million unsecured revolving credit facility (“2009 AmeriGas Supplemental Credit Agreement”) with three major banks. AmeriGas OLP’s Credit Agreement consists of (1) a $125 million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 million to finance the purchase of propane businesses or propane business assets or, to the extent it is not so used, for working capital and general purposes. The 2009 AmeriGas Supplemental Credit Agreement permits AmeriGas OLP to borrow up to $75 million for working capital and general purposes. The 2009 AmeriGas Supplemental Credit Agreement was amended on July 1, 2010 to, among other things, extend the termination date to June 30, 2011.

At June 30, 2010, there were $15 million of borrowings outstanding under the Credit Agreement and no amounts outstanding under the 2009 AmeriGas Supplemental Credit Agreement. Issued and outstanding letters of credit under the Revolving Credit Facility, which reduce the amount available for borrowings, totaled $35.7 million at June 30, 2010. 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 AmeriGas OLP credit agreements during the nine months ended June 30, 2010 were $26.6 million and $126 million, respectively. The average daily and peak bank loan borrowings outstanding under AmeriGas OLP credit agreements during the nine months ended June 30, 2009 were $58.3 million and $184.5 million, respectively. The higher average and peak bank loan borrowings in the 2009 nine-month period principally 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 June 30, 2010, AmeriGas OLP’s available borrowing capacity under the credit agreements was $224.3 million.

Based on 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. In July 2010, The Partnership repaid $80 million of maturing AmeriGas OLP First Mortgage Notes from borrowings under its Revolving Credit Agreement.

International Propane. Antargaz has a Senior Facilities Agreement that expires on March 31, 2011. The Senior Facilities Agreement consists of (1) a €380 million variable-rate term loan and (2) a €50 million revolving credit facility. Antargaz has executed interest rate swap agreements to fix the underlying euribor rate for the duration of the term loan. Antargaz had no amounts outstanding under the revolving credit facility at June 30, 2010, September 30, 2009 or June 30, 2009. The €380 million variable-rate term loan matures on March 31, 2011. Antargaz intends to refinance this maturing debt, subject to market conditions, on a long-term basis by March 2011. Antargaz has entered into forward-starting interest rate swaps to hedge the underlying euribor rate of interest relating to 4 ¹/2 years of quarterly interest payments on €300 million notional amount of long-term debt commencing March 31, 2011 associated with the anticipated refinancing.

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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 €8.6 million ($10.5 million) was outstanding at June 30, 2010. Flaga also has an €8 million euro-denominated working capital facility of which €8.0 million ($9.8 million) was outstanding at June 30, 2010. Issued and outstanding guarantees, which reduce available borrowings under the working capital facilities, totaled €5.0 million ($6.1 million) at June 30, 2010. Amounts outstanding under the working capital facilities are classified as bank loans. During the 2010 nine-month period, average and peak bank loan borrowings totaled €11.7 million and €16.5 million, respectively. During the 2009 nine-month period, average and peak bank loan borrowings totaled €15.1 million and €20.2 million, respectively.

UGI Utilities. UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement which expires in August 2011. At June 30, 2010, there were no borrowings under its Revolving Credit Agreement. Borrowings under the Revolving Credit Agreement are classified as bank loans on the Condensed Consolidated Balance Sheets. During the 2010 and 2009 nine-month periods, average daily bank loan borrowings were $93.1 million and $200.9 million, respectively, and peak bank loan borrowings totaled $203 million and $312 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January. During the prior-year nine-month period ended June 30, 2009, average daily and peak bank loan borrowings were higher than the current year due in large part to higher margin deposits associated with natural gas futures accounts as a result of declines in wholesale natural gas prices.

Energy Services. In April 2010, Energy Services amended its $200 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper. The Receivables Facility expires in April 2011, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility’s back-up purchasers. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts and capital expenditures.

Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables following GAAP for accounting for transfers and servicing 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 the nine months ended June 30, 2010 and 2009, Energy Services sold trade receivables totaling $933.3 million and $1,029.5 million, respectively, to ESFC. During the nine months ended June 30, 2010 and 2009, ESFC sold an aggregate $233.6 million and $508.9 million, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At June 30, 2010, the outstanding balance of ESFC receivables was $61.8 million and there was no amount sold to the commercial paper conduit. At June 30, 2009, the outstanding balance of ESFC receivables was $24.1 million which is net of $44.4 million that was sold to the commercial paper conduit and removed from the balance sheet. During the prior-year nine-month period, sales of receivables by ESFC to the commercial paper conduit were higher than the current-year period due in large part to the need to fund greater levels of margin deposits in natural gas futures accounts resulting from a decline in wholesale natural gas prices.

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Dividends and Distributions. On April 27, 2010, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.25 per common share or $1.00 per common share on an annual basis. This dividend reflects a 25% increase from the previous quarterly dividend rate of $0.20. The new quarterly dividend rate was effective with the dividend payable on July 1, 2010 to shareholders of record on June 15, 2010. On April 26, 2010, the General Partner’s Board of Directors approved a quarterly distribution of $0.705 per Common Unit equal to an annual rate of $2.82 per Common Unit. This distribution reflects an approximate 5% increase from the previous quarterly rate of $0.67 per Common Unit. The new quarterly rate was effective with the distribution payable on May 18, 2010 to unitholders of record on May 10, 2010. On July 27, 2010, UGI’s Board of Directors approved a quarterly dividend of $0.25 per common share payable October 1, 2010 to shareholders of record on September 15, 2010. On July 26, 2010, the General Partner’s Board of Directors approved a quarterly distribution of $0.705 per Common Unit payable August 18, 2010 to unitholders of record on August 10, 2010.

Income Taxes — Change in Tax Accounting for Utility Repairs and Maintenance Expenses. The Company received Internal Revenue Service (“IRS”) consent to change its tax method of accounting for capitalizing certain repairs and maintenance costs associated with its Gas Utility and Electric Utility assets beginning with the tax year ended September 30, 2009. The filing of the Company’s Fiscal 2009 tax returns using the new tax method resulted in federal and state income tax benefits totaling approximately $30.2 million which has been, or will be, used to offset Fiscal 2010 federal and state income tax liabilities. The filing of UGI Utilities’ Fiscal 2009 stand alone Pennsylvania income tax return also produced an approximate $43.4 million state net operating loss (“NOL”) carryforward, resulting in a net deferred tax benefit of approximately $2.8 million.

Under current Pennsylvania state income tax law, the NOL stated above can be carried forward by UGI Utilities for 20 years and used to reduce future Pennsylvania taxable income. Because the Company believes that it is more likely than not that it will fully utilize this state NOL prior to its expiration, no valuation allowance has been recorded. The change in tax method did not affect the Company’s net income (loss) for any periods presented. For further information, See Note 2 to condensed consolidated financial statements.

Subsequent Event — Sale of Atlantic Energy. On July 30, 2010, Energy Services sold all of its interest in its second-tier, wholly owned subsidiary Atlantic Energy, Inc. (“Atlantic Energy”) to DCP Midstream Partners, L.P. for $49.0 million cash plus an amount for inventory and other working capital. Atlantic Energy owns and operates a 20 million gallon marine import and transshipment facility located in the port of Chesapeake, Virginia. The Company expects to record an after-tax gain of approximately $16.0 million which will be reflected in results for the quarter ending September 30, 2010.

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Cash Flows

Due to the seasonal nature of the Company’s businesses, cash flows from operating activities 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 fourth and first fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest. Cash flow from operating activities in the prior-year nine-month period was higher than normal due to the effects on the Partnership’s and Antargaz’ cash flow from changes in operating working capital resulting from last year’s precipitous decline in propane product costs.

Operating Activities. Cash flow provided by operating activities was $516.7 million in the 2010 nine-month period compared to $593.3 million in the 2009 nine-month period. Cash flow from operating activities before changes in operating working capital was $656.6 million in the 2010 nine-month period compared to the prior-year’s $527.1 million of cash flow from operating activities before changes in operating working capital. The increase in cash flow before changes in operating working capital primarily reflects greater noncash charges for deferred income taxes and greater cash flow associated with settled commodity derivative contracts. Cash required to fund changes in operating working capital totaled $139.9 million in the 2010 nine-month period compared to $66.2 million of net cash provided by changes in operating working capital in the prior-year nine-month period. The higher prior-year nine-month period cash flows from changes in operating working capital reflects, among other things, the beneficial impact from changes in the Partnership’s and Antargaz’ accounts receivable and inventories, due to the previously mentioned significant decline in LPG product costs in Fiscal 2009, and greater prior-year period proceeds from sales of receivables under Energy Services securitization facility to fund greater natural gas futures account deposits.

Investing Activities. Cash flow used in investing activities was $284.8 million in the 2010 nine-month period compared with $485.0 million of cash used in the prior-year period. The significantly higher cash used in investing activities in the prior year principally reflects the net cash used for the acquisition by UGI Utilities of CPG Gas. Cash flows from investing activities in the prior year also includes net proceeds of $42.4 million from the sale of the Partnership’s California LPG storage facility. Cash used by investing activities in the 2010 nine-month period includes $13.6 million of cash invested in a limited partnership that focuses on the alternative energy sector.

Financing Activities. Cash flow used by financing activities was $251.8 million in the 2010 nine-month period compared with $113.6 million in the prior-year period. Net bank loan repayments totaled $123.3 million in the 2010 nine-month period which comprises a $154 million decrease in bank loans at UGI Utilities offset in part by $15 million of bank loan borrowings at AmeriGas OLP and $15.7 million of bank loan borrowings at Flaga. Cash flow from financing activities in the 2009 nine-month period principally reflects the issuance of $108 million of UGI Utilities Senior Notes to fund a portion of the October 1, 2008 acquisition of CPG Gas and increases in UGI Utilities bank loans principally to fund a portion of the acquisition of CPG Gas and natural gas brokerage accounts margin deposits. The prior-year nine-month period cash flows used by financing activities also reflects the March 2009 scheduled repayment of $70 million of AmeriGas OLP First Mortgage Notes.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

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

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

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Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at June 30, 2010 were not material.

Energy Services purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. Although Energy Services’ FTRs are economically effective as hedges of congestion charges, they do not currently qualify for hedge accounting treatment.

In order to manage market price risk relating to substantially all of Energy Services’ fixed-price sales contracts for natural gas and electricity, Energy Services purchases over-the-counter and exchange-traded natural gas and electricity 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 suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas or electricity 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.

The fair value of unsettled commodity price risk sensitive derivative instruments held at June 30, 2010 (excluding Gas Utility’s and Electric Utility’s commodity derivative instruments) was a liability of $39.7 million. A hypothetical 10% adverse change in (1) the market price of LPG and gasoline; (2) the market price of natural gas; and (3) the market price of electricity and electricity transmission congestion charges would result in a decrease in fair value of $37.3 million at June 30, 2010. Gas Utility’s exchange-traded natural gas futures and option contracts (comprising losses of $0.6 million at June 30, 2010), and Electric Utility’s FTRs (comprising gains of $0.3 million at June 30, 2010), are excluded from the amounts above because any associated net gains or losses are refundable to or recoverable from customers in accordance with Gas Utility and Electric Utility ratemaking.

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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 its March 2011 maturity date and Flaga has fixed the underlying euribor interest rate on a substantial portion of its term loans through their scheduled maturity dates through the use of interest rate swaps. At June 30, 2010 combined borrowings outstanding under these agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled approximately $36.9 million. Antargaz intends to refinance its variable-rate term loan maturing debt, subject to market conditions, on a long-term basis by March 2011. Antargaz has entered into forward-starting interest rate swaps to hedge the underlying euribor rate of interest relating to 4 ¹/2 years of quarterly interest payments on €300 million notional amount of long-term debt commencing March 31, 2011.

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

The fair value of unsettled interest rate risk sensitive derivative instruments held at June 30, 2010 was a liability of $16.4 million. A hypothetical 10% adverse change in the three-month LIBOR and the three- and nine-month Euribor would result in a decrease in fair value of $4.2 million.

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 June 30, 2010, the fair value of unsettled net investment hedges was a gain of $11.0 million. 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 $56.1 million, which amount would be reflected in other comprehensive income. In addition, in order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar denominated LPG product purchases during the months of October through March through the use of forward foreign exchange contracts.

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The fair value of unsettled foreign currency exchange rate risk sensitive derivative instruments held at June 30, 2010 was an asset of $16.9 million. A hypothetical 10% adverse change in the value of the euro versus the U.S. dollar would result in a decrease in fair value of $12.6 million.

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

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise major energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. Declines in natural gas, LPG and electricity product costs can require our business units to post collateral with counterparties or make margin deposits in brokerage accounts. At June 30, 2010, September 30, 2009 and June 30, 2009, restricted cash in brokerage accounts totaled $22.9 million, $7.0 million, and $64.8 million, respectively.

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

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

(b)

Change in Internal Control over Financial Reporting

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

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PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

In 2005, the Swigers 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.

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

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

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.

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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 million and asserted that UGI Utilities is responsible for approximately $103 million of this amount. The Northeast Companies subsequently withdrew their claims with respect to three of the sites and UGI Utilities acknowledged that it had operated one of the sites, Waterbury North, pursuant to a lease. In April 2009, the court conducted a trial to determine whether UGI Utilities operated any of the nine remaining sites that were owned and operated by former subsidiaries. On May 22, 2009, the court granted judgment in favor of UGI Utilities with respect to all nine sites. The Northeast Companies are expected to complete additional environmental investigations at Waterbury North by the end of 2010, after which there will be a second phase of the trial to determine what, if any, contamination at Waterbury North is related to UGI Utilities’ period of operation. The Northeast Companies previously estimated that remediation costs at Waterbury North could total $25 million.

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

We filed our written response to the Statement of Objections with the Competition Authority on October 21, 2009. The Competition Authority completed its review of Antargaz’ response and issued its Report on April 26, 2010. Antargaz filed its response to this Report on June 28, 2010. A hearing date has not been scheduled by the Competition Authority. Based on our assessment of the information contained in the Report, we believe that we have good defenses to the objections and that the reserve established by management for this matter is adequate. However, the final resolution could result in payment of an amount significantly different from the amount we have recorded. We are unable to predict the timing of the final resolution of this matter.

ITEM 1A. RISK FACTORS

In addition to the other information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended September 30, 2009, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

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ITEM 6. EXHIBITS

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

Incorporation by Reference
Exhibit No.		Exhibit	Registrant	Filing	Exhibit
	10.1	UGI Corporation 2009 Deferral Plan as Amended and Restated Effective June 1, 2010.
	10.2	AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on behalf of AmeriGas Partners, L.P. Effective July 30, 2010.	AmeriGas Partners, L.P.	Form 8-K (7/30/10)		10.1
	10.3	Amendment No. 1 to Credit Agreement, dated as of July 1, 2010, among the Partnership, as Borrower, AmeriGas Propane, Inc., as Guarantor, Petrolane Incorporated, as Guarantor, Citizens Bank of Pennsylvania, as Syndication Agent, JPMorgan Chase Bank, N.A., as Documentation Agent and Wells Fargo Bank, N.A., as Administrative Agent.	AmeriGas Partners, L.P.	Form 8-K (7/1/10)		10.1
	10.4	Gas Supply and Delivery Service Agreement between UGI Utilities, Inc. and UGI Energy Services, Inc. effective as of May 1, 2007.	UGI Utilities	Form 10-Q (6/30/10)		10.1
	10.5	SST Service Agreement dated November 1, 2004 between Columbia Gas Transmission Corporation and UGI Utilities, Inc.	UGI Utilities	Form 10-Q (6/30/10)		10.2
	31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2010, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	101	The following financial statements from UGI Corporation and Subsidiaries’ Quarterly Report on Form 10-Q for the quarter and nine months ended June 30, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets; (ii) the Condensed Consolidated Statements of Income; (iii) the Condensed Consolidated Statements of Cash Flows; and (iv) Notes to Condensed Financial Statements, tagged as blocks of text.

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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 thereunto duly authorized.

	UGI Corporation
	(Registrant)
Date: August 6, 2010	By:	/s/ Peter Kelly
		Peter Kelly
		Vice President - Finance and Chief Financial Officer
Date: August 6, 2010	By:	/s/ Davinder Athwal
		Davinder Athwal
		Vice President - Accounting and Financial Control and Chief Risk Officer

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UGI CORPORATION AND SUBSIDIARIES

EXHIBIT INDEX

10.1	UGI Corporation 2009 Deferral Plan as Amended and Restated Effective June 1, 2010.
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2010, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2010, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	The following financial statements from UGI Corporation and Subsidiaries’ Quarterly Report on Form 10-Q for the quarter and nine months ended June 30, 2010, formatted in XBRL (Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets; (ii) the Condensed Consolidated Statements of Income; (iii) the Condensed Consolidated Statements of Cash Flows; and (iv) Notes to Condensed Financial Statements, tagged as blocks of text.

EX-10.1

Exhibit 10.1

UGI CORPORATION

2009 DEFERRAL PLAN

As amended and restated effective June 1, 2010

TABLE OF CONTENTS

	Page
BACKGROUND	1
ARTICLE 1 DEFINITIONS	1
ARTICLE 2 ELIGIBILITY	4
ARTICLE 3 BENEFITS	5
ARTICLE 4 DISTRIBUTIONS TO PARTICIPANTS	7
ARTICLE 5 VESTING	11
ARTICLE 6 FUNDING	11
ARTICLE 7 INVESTMENTS	11
ARTICLE 8 ADMINISTRATION	13
ARTICLE 9 CLAIMS PROCEDURE	15
ARTICLE 10 AMENDMENT	16
ARTICLE 11 TERMINATION	16
ARTICLE 12 MISCELLANEOUS	16
EXHIBIT A DISTRIBUTION ELECTION FORM — UGI SERP PARTICIPANTS	20
EXHIBIT B DISTRIBUTION ELECTION FORM — AMERIGAS SERP PARTICIPANTS	23
EXHIBIT C DISTRIBUTION ELECTION FORM — UGI NON-EMPLOYEE DIRECTORS	26
EXHIBIT D DISTRIBUTION ELECTION FORM — 2009 UGI SERP PARTICIPANTS	29
EXHIBIT E DISTRIBUTION ELECTION FORM — AMERIGAS NON-EMPLOYEE DIRECTORS	32

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BACKGROUND

UGI Corporation currently maintains the UGI Corporation Supplemental Executive Retirement Plan (“UGI SERP”), the UGI Corporation 2009 Supplemental Executive Retirement Plan (“2009 UGI SERP) (collectively, the “UGI Plans”) and the UGI Corporation 2004 Omnibus Equity Compensation Plan, as amended (“Equity Plan”), and AmeriGas Propane Inc. currently maintains the AmeriGas Propane, Inc. Supplemental Executive Retirement Plan (“AmeriGas SERP”). On April 26, 2010, the AmeriGas Board approved the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on behalf of AmeriGas Partners, L.P. (“2010 AmeriGas LTIP”), subject to approval by the unitholders of AmeriGas Partners, L.P. (“APLP”). UGI Corporation has granted stock units to non-employee directors under the Equity Plan or a predecessor plan and AmeriGas Propane, Inc. may grant phantom units to non-employee directors under the 2010 AmeriGas LTIP.

UGI Corporation and AmeriGas Propane, Inc. desire to allow employees who are participants in the UGI Plans or the AmeriGas SERP, and non-employee directors who hold stock units or phantom units, to defer benefits under the UGI Plans, AmeriGas SERP, stock units or phantom units after separation from service. UGI Corporation and AmeriGas Propane, Inc. have adopted this amended and restated Plan to allow such deferral of benefits. Non-employee directors of the AmeriGas Board are eligible to participate in the Plan as of the date on which the APLP unitholders approve the 2010 AmeriGas LTIP.

All shares of UGI Corporation common stock that are to be distributed pursuant to stock units deferred under this Plan shall be issued under the Equity Plan and shall in all respects be subject to the terms of the Equity Plan. All common units of APLP that are to be distributed pursuant to phantom units deferred under this Plan shall be issued under the 2010 AmeriGas LTIP and shall in all respect be subject to the terms of the 2010 AmeriGas LTIP.

ARTICLE 1

Definitions

1.1	“2009 UGI SERP” means the UGI Corporation 2009 Supplemental Executive Retirement Plan.
1.2	“2010 AmeriGas LTIP” means the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on behalf of AmeriGas Partners, L.P.
1.3	“Account” means a bookkeeping account established pursuant to Section 3.1 to reflect the total amount standing to the credit of the Participant under the Plan.
1.4	“Administrative Committee” shall mean the committee designated by the Compensation Committee to administer the Plan.
1.5	“Affiliated Company” means any affiliate or subsidiary of the Company, including AmeriGas Propane, Inc.

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1.6 “Agreement” means the written instrument that sets forth the terms and conditions of a grant issued under the UGI Plans or AmeriGas SERP, or Stock Units, including all amendments thereto.

1.7 “AmeriGas Board” means the Board of Directors of AmeriGas Propane, Inc., as constituted from time to time.

1.8 “AmeriGas LTIP Change of Control” means a “Change of Control” as defined in the 2010 AmeriGas LTIP.

1.9	“AmeriGas SERP” means the AmeriGas Propane, Inc. Supplemental Executive Retirement Plan, as amended.
1.10	“APLP” means AmeriGas Partners, L.P.

1.11 “APLP Partnership Agreement” means the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P., dated as of July 27, 2009, as amended from time to time.

1.12	“Beneficiary” means the person designated by a Participant to receive any benefits payable after the Participant’s death. The Company shall provide a form for this purpose. In the event a Participant has not filed a Beneficiary designation with the Company or none of the designated Beneficiaries are living at the date of the Participant’s death, the Beneficiary shall be the Participant’s estate.
1.13	“Board” means the Board of Directors of the Company.
1.14	“Change of Control” means “Change of Control” of the Company, as defined in the Equity Plan.
1.15	“Code” means the Internal Revenue Code of 1986, as amended.

1.16 “Common Unit” means a unit representing a fractional part of the partnership interests of all limited partners and assignees with respect to APLP and having the rights and obligations specified with respect to common units in the APLP Partnership Agreement.

1.17	“Compensation Committee” means the Compensation and Management Development Committee of the Board.
1.18	“Company” means UGI Corporation and its successors.

1.19 “Deferral Election” means an election to defer benefits under the UGI Plans, AmeriGas SERP benefits, Stock Units or Phantom Units as described in Section 3.2.

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1.20 “Distribution Equivalent” means an amount determined by multiplying the number of Common Units subject to Phantom Units by the per-Common Unit cash distribution, or the per Common Unit fair market value of any distribution in consideration other than cash, paid by APLP on its Common Units.

1.21	“Dividend Equivalent” means an amount determined by multiplying the number of shares of common stock of the Company subject to Stock Units by the per-share cash dividend, or the per-share fair market value of any dividend in consideration other than cash, paid by the Company on its common stock.
1.22	“Effective Date” of the Plan is January 1, 2009.

1.23 “Employee” means any individual employed by the Employer as an officer, senior manager or other highly compensated employee.

1.24	“Employer” means the Company and its Affiliated Companies, either collectively or individually, as the context requires.
1.25	“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.
1.26	“Equity Plan” means the Company’s 2004 Omnibus Equity Compensation Plan, as amended.

1.27 “Grant Letter” means the written instrument that sets forth the terms and conditions of the Phantom Units, including all amendments thereto.

1.28 “Key Employee” means a Employee who, at any time during the 12-month period ending on the identification date, is a “specified employee” under section 409A of the Code, as determined by the Compensation Committee or its delegate. The determination of Key Employees, including the number and identity of persons considered specified employees and the identification date, shall be made by the Compensation Committee or its delegate in accordance with the provisions of section 409A of the Code and the regulations issued thereunder.

1.29 “Non-Employee Director” means a member of the Board or AmeriGas Board, as applicable, who is not an employee of the Employer.

1.30 “Participant” means any Employee or Non-Employee Director who satisfies the eligibility requirements set forth in Article 2 and elects to participate in the Plan.

1.31 “Phantom Units” means phantom units issued to Non-Employee Directors of the AmeriGas Board under the 2010 AmeriGas LTIP.

1.32 “Plan” means this UGI Corporation 2009 Deferral Plan.

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1.33 “Postponement Period” means, for a Key Employee, the period of six months after Separation from Service (or such other period as may be required by section 409A of the Code), during which payments may not be made to the Key Employee under section 409A of the Code.

1.34	“Re-Deferral Election” means an election to re-defer the payment date of an Account as described in Section 4.3.
1.35	“Retirement Distribution Account” means a distribution account described in Section 4.2.

1.36 “Separation from Service” means a Participant’s separation from service with the Employer within the meaning of section 409A of the Code and the regulations promulgated thereunder.

1.37	“Stock Units” means the stock units issued to Non-Employee Directors under the Equity Plan or a predecessor plan.
1.38	“UGI Plans” means collectively, the UGI SERP and the 2009 UGI SERP.
1.39	“UGI SERP” means the UGI Corporation Supplemental Executive Retirement Plan, as amended.

1.40 “Unit Value” means, at any time, the value of each Stock Unit or Phantom Unit, as applicable, which shall be equal to the Fair Market Value (as defined in the Equity Plan or 2010 AmeriGas LTIP, as applicable) of a share of the Company’s common stock or a Common Unit, as applicable, on such date.

ARTICLE 2

Eligibility

2.1

Participation.

Each Employee who has earned an accrued benefit under the UGI Plans or the AmeriGas SERP, and each Non-Employee Director who receives a grant of Stock Units or Phantom Units shall be eligible to participate in the Plan. Non-Employee Directors of the AmeriGas Board shall become eligible to participate in the Plan as of the date on which the APLP unitholders approve the 2010 AmeriGas LTIP, or, if later, as of the date of the Non-Employee Director’s first election to the AmeriGas Board. Each such Employee or Non-Employee Director may elect to become a Participant by electing to have an Account established under this Plan upon Separation from Service, as described in Section 3.2 below.

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ARTICLE 3

Benefits

3.1	Account.
	The Employer shall create and maintain on its books an Account for each Participant after Separation from Service, to which it shall credit amounts credited to the Plan pursuant to this Article 3. The Employer shall also credit each Participant’s Account with deemed earnings, Dividend Equivalents or Distribution Equivalents, as applicable, in accordance with the provisions of Article 7 below.

3.2 Deferral Elections with respect to the UGI Plans, AmeriGas SERP, Stock Units and Phantom Units.

(a) An Employee who has an accrued benefit in the UGI SERP or the AmeriGas SERP as of December 1, 2008, may elect in 2008 to have his or her benefit under the UGI SERP or AmeriGas SERP at Separation from Service credited to the Employee’s Account under this Plan as of the date of the Employee’s Separation from Service. A Non-Employee Director who holds Stock Units as of December 31, 2008, may elect in 2008 to have his or her Stock Units at Separation from Service credited to the Non-Employee Director’s Account under this Plan as of the date of the Non-Employee Director’s Separation from Service.

(b) An Employee who first accrues a benefit in the UGI SERP after December 31, 2008, may elect to have his or her benefit under the UGI SERP credited to the Employee’s Account under this Plan as of the date of the Employee’s Separation from Service. The election must be made no later than 30 days following the first day of the calendar year following the calendar year in which the Employee first accrues a benefit under the UGI SERP, or as otherwise required by section 409A.

(c) An Employee who first accrues a benefit in the AmeriGas SERP after December 31, 2008, may elect to have his or her benefit under the AmeriGas SERP credited to the Employee’s Account under this Plan as of the date of the Employee’s Separation from Service. The election must be made before the first year in which the Employee accrues a benefit under the AmeriGas SERP (or any other nonqualified deferred compensation plan that is aggregated with the AmeriGas SERP for purposes of section 409A) or in the case of a newly hired Employee, not later than 30 days after the Employee first becomes eligible to participate in the AmeriGas SERP (or any other nonqualified deferred compensation plan that is aggregated with the AmeriGas SERP for purposes of section 409A), with respect to compensation for services to be performed after the election, in accordance with section 409A.

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(d) A Non-Employee Director of the Board who first receives Stock Units after December 31, 2008, may elect to have his or her Stock Units credited to the Non-Employee Director’s Account under this Plan as of the date of the Non-Employee Director’s Separation from Service. The election must be made before the first year in which the Non-Employee Director receives Stock Units or, in the case of a newly elected (after January 1, 2009) Non-Employee Director, not later than 30 days after the Non-Employee Director first becomes eligible to participate in the Plan, with respect to compensation for services to be performed after the election, in accordance with section 409A.

(e) A Non-Employee Director of the AmeriGas Board who receives Phantom Units under the 2010 AmeriGas LTIP may elect to have his or her Phantom Units credited to the Non-Employee Director’s Account under this Plan as of the date of the Non-Employee Director’s Separation from Service. For Non-Employee Directors of the AmeriGas Board who first become eligible to participate in the Plan upon APLP unitholder approval of the 2010 AmeriGas LTIP, the election must be made no later than 30 days after they first become eligible to participate in the Plan, with respect to compensation for services to be performed after the election, in accordance with section 409A. Subsequently, newly elected Non-Employee Directors of the AmeriGas Board must make the election no later than 30 days after the Non-Employee Director first becomes eligible to participate in the Plan, with respect to compensation for services to be performed after the election, in accordance with section 409A.

(f) An Employee who first accrues a benefit in the 2009 UGI SERP on or after October 1, 2009, may elect to have his or her benefit under the 2009 UGI SERP credited to the Employee’s Account under this Plan as of the date of the Employee’s Separation from Service. The election must be made before the first year in which the Employee accrues a benefit under the 2009 UGI SERP (or any other nonqualified deferred compensation plan that is aggregated with the 2009 UGI SERP for purposes of section 409A) or, in the case of a newly hired Employee, not later than 30 days after the Employee first becomes eligible to participate in the 2009 UGI SERP (or any other nonqualified deferred compensation plan that is aggregated with the 2009 UGI SERP for purposes of section 409A), with respect to compensation for services to be performed after the election, in accordance with section 409A.

(g) Each Employee or Non-Employee Director who makes an election under subsection (a), (b), (c), (d), (e) or (f) shall elect, at the same time, the form and time of payment of the benefits to be credited to his or her Account under this Plan, as described in Section 3.3 below.

(h) Notwithstanding the foregoing, the Administrative Committee may impose such rules and restrictions as it deems appropriate on Deferral Elections, in accordance with section 409A, including rules and restrictions with respect to the ability of newly promoted Employees to make Deferral Elections under the Plan.

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3.3	Election of Form and Time of Payment.
	When an Employee or Non-Employee Director makes an election pursuant to Section 3.2, the Employee or Non-Employee Director shall select one or more of the following forms and times of payment under the Plan for amounts credited from the UGI SERP, AmeriGas SERP, Stock Units or Phantom Units, as applicable:

(a) An Employee may elect that the Employee’s benefits under the UGI Plans or the AmeriGas SERP be paid in a lump sum payment within 30 business days after the Employee’s Separation from Service date, subject to the Postponement Period for section 409A. A Non-Employee Director may elect that his or her Stock Units or Phantom Units shall be paid in a lump sum payment within 30 business days after his or her Separation from Service date. To the extent that any benefits under the UGI Plans, AmeriGas SERP benefits, Stock Units or Phantom Units are to be paid in a lump sum under this subsection (a), such benefits, Stock Units or Phantom Units shall be paid in accordance with the UGI Plans, AmeriGas SERP, Stock Unit Agreements or Phantom Unit Grant Letters, as applicable, and no Account for such benefits, Stock Units or Phantom Units will be established under this Plan.

(b) A Participant may elect that as of the Participant’s Separation from Service date, the amounts deferred from the UGI Plans, AmeriGas SERP, Stock Units or Phantom Units, as applicable, shall be credited to a Retirement Distribution Account and shall be paid in installments over two to 10 years. The payments shall commence 14 months after the Participant’s Separation from Service date and shall be paid annually thereafter in the calendar year following the first payment and subsequent calendar years.

(c) A Participant may elect that as of the Participant’s Separation from Service date, the amounts deferred from the UGI Plans, AmeriGas SERP, Stock Units or Phantom Units, as applicable, shall be credited to up to five Retirement Distribution Accounts, each of which shall be paid in a lump sum in the year specified by the Participant. The first Retirement Distribution Account shall become payable 14 months after the Participant’s Separation from Service date, unless the Participant has elected otherwise in accordance with the Plan.

3.4	Delivery Instructions
	Each Participant’s deferral election must be made in writing on the distribution election form attached hereto as Exhibits A, B, C, D or E, as applicable, or similar forms, and must be filed with the Company’s Corporate Secretary.

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ARTICLE 4

Distributions to Participants

4.1	Separation from Service.
	When a Participant Separates from Service, the amounts to be credited from the UGI Plans, AmeriGas SERP, Stock Units or Phantom Units, as applicable, shall be credited to the Participant’s Account under this Plan in accordance with the Participant’s distribution election pursuant to Section 3.3. The amounts shall be distributed as follows:

(a) If the Participant has elected a lump sum payment under Section 3.3(a), the amount shall be distributed in a lump sum payment as described in Section 3.3(a) under the UGI Plans, AmeriGas SERP, Stock Unit Agreement or Phantom Unit Grant Letter, as applicable.

(b) If the Participant has elected installment payments under Section 3.3(b), the amount shall be distributed in the number of installments elected, as described in Section 3.3(b). The installments will be paid annually, and each installment will be calculated as the amount credited to the Participant’s Retirement Distribution Account immediately before the distribution date, divided by the number of remaining years in the payment schedule.

(c) If the Participant has elected one to five Retirement Distribution Accounts under Section 3.3(c), each Retirement Distribution Account shall be paid in a lump sum on the specified date after the Participant’s Separation from Service.

(d) If a Participant has not elected the form and timing of payment, the amount will be distributed in a lump sum payment as described in Section 3.3(a).

(e) Notwithstanding the foregoing or any elections to the contrary, if the total amounts credited to the Participant’s aggregate Retirement Distribution Accounts is less than $25,000 at the Participant’s Separation from Service date, distribution shall be made in a lump sum payment as described in Section 3.3(a).

4.2 Death

(a) If a Participant dies before Separation from Service, the Participant’s benefit under the UGI SERP will be paid to his or her surviving spouse in the form designated by the Participant under Section 3.3. If a Participant dies before Separation from Service and does not have a surviving spouse, no death benefit will be paid under the UGI SERP. If a Participant dies after Separation from Service, the Participant’s benefit under the UGI SERP will be paid to his or her Beneficiary in the form and at the time designated by the Participant under Section 3.3.

(b) If a Participant dies before or after Separation from Service, the Participant’s benefit under the AmeriGas SERP, the 2009 UGI SERP, the Participant’s Stock Units or Phantom Units, as applicable, will be paid to his or her Beneficiary in the form and at the time designated by the Participant under Section 3.3.

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4.3	Re-Deferral Elections.
	Subject to the timing requirements described below, a Participant may change his or her elections regarding the time and form of distribution (a “Re-Deferral Election”), as follows:

(a) A Participant who has previously elected to receive his or her distribution in the form of a lump sum (or whose distribution is payable in a lump sum by operation of the Plan) may elect to re-defer all or any part of that scheduled distribution to a later date pursuant to subsection (b) below. A Participant who has previously elected to receive his or her distribution in the form of installments may elect to re-defer the entire distribution amount to a later date, provided that the election must be made pursuant to subsection (b) below before the installment payments begin.

(b) Any Re-Deferral Election (i) will be irrevocable when made, (ii) may not accelerate the payment (in the case of installments, the Re-Deferral Election may not accelerate the first scheduled payment), (iii) will not be effective as to any payment scheduled to be made within 12 months of the Re-Deferral Election and (iv) must defer the first payment to which the Re-Deferral Election applies for at least five additional years. All Re-Deferral Elections must be made in accordance with section 409A of the Code.

(c) No Re-Deferral Election may be made by a Participant who Separates from Service before the Participant has attained age 55 and has completed 10 years of service with the Employer. No Re-Deferral Election may be made after a Participant’s death. No Re-Deferral Election may be made after the tenth anniversary of the Participant’s Separation from Service.

(d) In addition, in no event may a Participant make a Re-Deferral Election unless the Participant’s Retirement Distribution Account to be re-deferred is at least $25,000 at the time of the election.

(e) Notwithstanding the foregoing, the Company reserves the right to reject any new Re-Deferral Election, in which case the applicable Account will be distributed in accordance with the Participant’s deferral election or Re-Deferral Election then in effect.

(f) A Participant’s Re-Deferral Election must be made in writing and filed with the Company’s Corporate Secretary. The Company must acknowledge receipt of the Re-Deferral Election in order for the Re-Deferral Election to be valid. The Re-Deferral Election must designate a form and time of payment described in Section 3.3, except that the payment date shall be postponed as described in the Re-Deferral Election. All references in Sections 4.1 and 4.2 to payment dates and forms under Section 3.3 shall be deemed to include any applicable Re-Deferral Elections.

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4.4 Change of Control.

(a) The following provisions apply in the event of a Change of Control of the Company, notwithstanding anything in the Plan to the contrary:

(i) A Change of Control will not affect the form and timing of distribution of the benefits under the UGI Plans and the AmeriGas SERP that are deferred under this Plan.

(ii) In the event of a Change of Control that is a change in control event under section 409A of the Code, the Company shall redeem all the Stock Units then credited to the Participant’s Account and the redemption amount shall be paid in cash on the closing date of the Change of Control. The amount paid shall equal the product of the number of Stock Units being redeemed multiplied by the Unit Value at the date of the Change of Control.

(iii) In the event that the transaction constituting a Change of Control is not a change in control event under section 409A of the Code, the Participant’s Stock Units shall be redeemed and paid in cash within 30 business days after the Participant’s Separation from Service date, instead of upon the Change of Control. (For example, an acquisition by any person of 20% or more of the voting power of the Company’s stock may be a Change of Control under the Equity Plan, whereas the section 409A definition requires that the person acquire 30% of the voting power of the stock). If the Change of Control is not a change in control event under section 409A of the Code and the Participant Separated from Service before the Change of Control, the Participant’s Stock Units shall be paid in cash at the applicable date specified in Section 4.1, 4.2 or 4.3. If payment is delayed after the Change of Control pursuant to this subsection (iii), the Compensation Committee may provide for the Stock Units to be valued at the Unit Value as of the date of the Change of Control and interest to be credited on the amount so determined at a market rate for the period between the Change of Control date and the payment date.

(b) The following provisions apply in the event of an AmeriGas LTIP Change of Control, notwithstanding anything in the Plan to the contrary:

(i) In the event of an AmeriGas LTIP Change of Control that is a change in control event under section 409A of the Code, APLP shall redeem all the Phantom Units then credited to the Participant’s Account and the redemption amount shall be paid in cash on the closing date of the AmeriGas LTIP Change of Control. The amount paid shall equal the product of the number of Phantom Units being redeemed multiplied by the Unit Value at the date of the AmeriGas LTIP Change of Control.

(ii) In the event that the transaction constituting an AmeriGas LTIP Change of Control is not a change in control event under section 409A of the Code, the Participant’s Phantom Units shall be redeemed and paid in cash within 30 business days after the Participant’s Separation from Service date, instead of upon the AmeriGas LTIP Change of Control. If the AmeriGas LTIP Change of Control is not a change in control event under section 409A of the Code and the Participant Separated from Service before the AmeriGas LTIP Change of Control, the Participant’s Phantom Units shall be paid in cash at the applicable date specified in Section 4.1, 4.2 or 4.3. If payment is delayed after the AmeriGas LTIP Change of Control, pursuant to this subsection (ii), the Compensation Committee may provide for the Phantom Units to be valued at the Unit Value as of the date of the AmeriGas LTIP Change of Control and interest to be credited on the amount so determined at a market rate for the period between the AmeriGas LTIP Change of Control date and the payment date.

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4.5 Medium of Payment. All distributions under the Plan shall be made in cash, except that (i) distributions of Stock Units (including Dividend Equivalents) shall be made 65% in Company common stock issued under the Equity Plan and 35% in cash, or as otherwise specified under the applicable Stock Unit Agreement or under Section 4.4, and (ii) distributions of Phantom Units (including Distribution Equivalents) shall be made 65% in Common Units issued under the 2010 AmeriGas LTIP and 35% in cash, or as otherwise specified under the applicable Phantom Unit Grant Letter or under Section 4.4.

4.6

Section 409A Six-Month Delay.

Notwithstanding any provision of the Plan to the contrary, distributions upon a Separation from Service to a Participant who is a Key Employee shall not be made during the Participant’s Postponement Period. If payment is required to be delayed for the Postponement Period pursuant to section 409A, the accumulated amounts withheld on account of section 409A shall be paid in a lump sum payment within 15 days of the Postponement Period. If the Participant dies during the Postponement Period prior to the distribution of the Participant’s Retirement Distribution Account, the amounts withheld on account of section 409A shall be paid to the Participant’s estate within 60 days after the Participant’s death.

ARTICLE 5

Vesting

5.1 The balance credited to a Participant’s Account shall be fully vested at all times.

ARTICLE 6

Funding

6.1 The Board may, but shall not be required to, authorize the establishment of a rabbi trust for the benefits described herein. In any event, the Company’s obligation hereunder shall constitute a general, unsecured obligation, payable solely out of its general assets, and no Participant shall have any right to any specific assets of the Company or any such vehicle.

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ARTICLE 7

Investments

7.1 After a Participant’s Separation from Service, amounts credited to the Plan from the UGI Plans, AmeriGas SERP, Stock Units or Phantom Units shall be credited with earnings and losses as follows:

(a) Amounts credited to a Participant’s Retirement Distribution Account from the UGI Plans or the AmeriGas SERP that are to be paid pursuant to Section 3.3(b) or 3.3(c) shall be deemed to be invested in investment funds according to procedures established by the Administrative Committee. The Participant may select the investment funds from among the funds made available by the Administrative Committee. If a Participant does not select the investment funds, the amounts credited for the Participant shall be deemed invested in a target retirement fund selected by the Administrative Committee.

(b) Stock Units that are credited to the Plan and are to be paid pursuant to Section 3.3(b) or 3.3(c) shall continue to be held in the form of Stock Units. Dividend Equivalents shall be credited to the Participant’s Account with respect to Stock Units when dividends are paid on Company common stock, in an amount equal to the Dividend Equivalent associated with the Stock Units held by the Participant on the record date for the dividend. On the last day of each calendar year, the amount of the Dividend Equivalents credited to the Participant’s Account during that calendar year shall be converted to a number of Stock Units, based on the Unit Value on the last day of that calendar year. In the event of a Change of Control or in the event the Participant dies or Separates from Service prior to the last day of a calendar year, as soon as practicable following such event, and in no event later than the date on which Stock Units are distributed, the Company shall convert the amount of Dividend Equivalents previously credited to the Participant’s Account during the calendar year to a number of Stock Units based on the Unit Value on the date of such Change of Control, death or Separation from Service, as applicable.

(c) Phantom Units that are credited to the Plan and are to be paid pursuant to Section 3.3(b) or 3.3(c) shall continue to be held in the form of Phantom Units. Distribution Equivalents shall be credited to the Participant’s Account with respect to Phantom Units when distributions are paid on Common Units, in an amount equal to the Distribution Equivalent associated with the Phantom Units held by the Participant on the record date for the distribution. On the last day of each calendar year, the amount of the Distribution Equivalents credited to the Participant’s Account during that calendar year shall be converted to a number of Phantom Units, based on the Unit Value on the last day of that calendar year. In the event of an AmeriGas LTIP Change of Control or in the event the Participant dies or Separates from Service prior to the last day of a calendar year, as soon as practicable following such event, and in no event later than the date on which Phantom Units are distributed, the Company shall convert the amount of Distribution Equivalents previously credited to the Participant’s Account during the calendar year to a number of Phantom Units based on the Unit Value on the date of such AmeriGas LTIP Change of Control, death or Separation from Service, as applicable.

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7.2 Each Participant’s Account shall be adjusted periodically to take into account the gains, losses and income returns of the deemed investments selected by the Participant or as otherwise provided under this Article 7. The Employer shall not be required to invest any funds in the forms of investment made available hereunder and, in any event, any such investments shall at all times remain the property of the Employer.

ARTICLE 8

Administration

8.1 Appointment and Tenure of Administrative Committee Members. The Administrative Committee shall consist of one or more persons who shall be appointed by and serve at the pleasure of the Compensation Committee. Any Administrative Committee member may resign by delivering his or her written resignation to the Compensation Committee. Vacancies arising by the death, resignation or removal of an Administrative Committee member may be filled by the Compensation Committee.

8.2 Meetings; Majority Rule. Any and all acts of the Administrative Committee taken at a meeting shall be by a majority of all members of the Administrative Committee. The Administrative Committee may act by vote taken in a meeting (at which a majority of members shall constitute a quorum). The Administrative Committee may also act by unanimous consent in writing without the formality of convening a meeting.

8.3 Delegation. The Administrative Committee may, by majority decision, delegate to each or any one of its members, authority to sign any documents on its behalf, or to perform ministerial acts, but no person to whom such authority is delegated shall perform any act involving the exercise of any discretion without first obtaining the concurrence of a majority of the members of the Administrative Committee, even though such person alone may sign any document required by third parties. The Administrative Committee shall elect one of its members to serve as Chairperson. The Chairperson shall preside at all meetings of the Administrative Committee or shall delegate such responsibility to another Administrative Committee member. The Administrative Committee shall elect one person to serve as Secretary to the Administrative Committee. All third parties may rely on any communication signed by the Secretary, acting as such, as an official communication from the Administrative Committee.

13

8.4 Authority and Responsibility of the Administrative Committee. The Administrative Committee shall have only such authority and responsibilities as are delegated to it by the Compensation Committee or specifically provided herein. The Administrative Committee shall have full power and express discretionary authority to administer and interpret the Plan, to make factual determinations and to adopt or amend such rules and regulations for implementing the Plan and for the conduct of its business as it deems necessary or advisable, in its sole discretion. The Administrative Committee’s authorities and responsibilities shall also include:

(a) maintenance and preservation of records relating to Participants, former Participants, and their beneficiaries;

(b) preparation and distribution to Participants of all information and notices required under Federal law or the provisions of the Plan;

(c) preparation and filing of all governmental reports and other information required under law to be filed or published;

(d) engagement of assistants and professional advisers;

(e) arrangement for bonding, if required by law; and

(f) promulgation of procedures for determination of claims for benefits.

8.5 Compensation of Administrative Committee Members. The members of the Administrative Committee shall serve without compensation for their services as such, but all expenses of the Administrative Committee shall be paid or reimbursed by the Company.

8.6 Administrative Committee Discretion. Any discretion, actions, or interpretations to be made under the Plan by the Administrative Committee shall be made in its sole discretion, need not be uniformly applied to similarly situated individuals, and shall be final, binding, and conclusive on the parties. All benefits under the Plan shall be provided conditional upon the Participant’s acknowledgement, in writing or by acceptance of the benefits, that all decisions and determinations of the Administrative Committee shall be final and binding on the Participant, his or her Beneficiaries and any other person having or claiming an interest under the Plan.

8.7 Indemnification of the Administrative Committee. Each member of the Administrative Committee shall be indemnified by the Company against costs, expenses and liabilities (other than amounts paid in settlement to which the Company does not consent) reasonably incurred by him or her in connection with any action to which he or she may be a party by reason of his or her service as a member of the Administrative Committee, except in relation to matters as to which he or she shall be adjudged in such action to be personally guilty of gross negligence or willful misconduct in the performance of his or her duties. The foregoing right to indemnification shall be in addition to such other rights as the Administrative Committee member may enjoy as a matter of law or by reason of insurance coverage of any kind, but shall not extend to costs, expenses and/or liabilities otherwise covered by insurance or that would be so covered by any insurance then in force if such insurance contained a waiver of subrogation. Rights granted hereunder shall be in addition to and not in lieu of any rights to indemnification to which the Administrative Committee member may be entitled pursuant to the by-laws of the Company. Service on the Administrative Committee shall be deemed in partial fulfillment of the Administrative Committee member’s function as an employee, officer and/or director of the Company, if he or she serves in that capacity as well as in the role of Administrative Committee member.

14

Article 9

Claims Procedure

9.01 Claim. Any person or entity claiming a benefit, requesting an interpretation or ruling under the Plan (hereinafter referred to as “claimant”), or requesting information under the Plan shall present the request in writing to the Administrative Committee, which shall respond in writing or electronically. The notice advising of the denial shall be furnished to the claimant within 90 days of receipt of the benefit claim by the Administrative Committee, unless special circumstances require an extension of time to process the claim. If an extension is required, the Administrative Committee shall provide notice of the extension prior to the termination of the 90 day period. In no event may the extension exceed a total of 180 days from the date of the original receipt of the claim.

9.02 Denial of Claim. If the claim or request is denied, the written or electronic notice of denial shall state:

(a) The reasons for denial;

(b) Reference to the specific Plan provisions on which the denial is based;

(c) A description of any additional material or information required and an explanation of why it is necessary; and

(d) An explanation of the Plan’s claims review procedures and the time limits applicable to such procedures, including the right to bring a civil action under section 502(a) of ERISA.

9.03 Final Decision. The decision on review shall normally be made within 60 days after the Administrative Committee’s receipt of claimant’s claim or request. If an extension of time is required for a hearing or other special circumstances, the claimant shall be notified and the time limit shall be 120 days. The decision shall be in writing or in electronic form and shall:

(a) State the specific reasons for the denial;

(b) Reference the relevant Plan provisions;

(c) State that the claimant is entitled to receive, upon request and free of charge, and have reasonable access to and copies of all documents, records and other information relevant to the claim for benefits; and

(d) State that the claimant may bring an action under section 502(a) of ERISA.

All decisions on review shall be final and binding on all parties concerned.

15

9.04 Review of Claim. Any claimant whose claim or request is denied or who has not received a response within 60 days may request a review by notice given in writing or electronic form to the Administrative Committee. Such request must be made within 60 days after receipt by the claimant of the written or electronic notice of denial, or in the event the claimant has not received a response, 60 days after receipt by the Administrative Committee of the claimant’s claim or request. The claim or request shall be reviewed by the Administrative Committee which may, but shall not be required to, grant the claimant a hearing. On review, the claimant may have representation, examine pertinent documents, and submit issues and comments in writing.

ARTICLE 10

Amendment

10.1 The provisions of the Plan may be amended at any time and from time to time by the Compensation Committee for any reason without either the consent of or prior notice to any Participant; provided, however, that no such amendment shall serve to reduce the benefit that has been credited to an Account on behalf of a Participant as of the effective date of the amendment.

ARTICLE 11

Termination

11.1 While it is the Company’s intention to continue the Plan indefinitely in operation, the Compensation Committee may terminate the Plan in whole or in part at any time for any reason without either the consent of or prior notice to any Participant. No such termination shall reduce the benefit that has been credited to an Account on behalf of a Participant as of the effective date of the termination, but the Company may distribute all accrued benefits upon termination of the Plan in accordance with section 409A of the Code.

16

ARTICLE 12

Miscellaneous

12.1 Nonalienation of Benefits. None of the payments, benefits or rights of any Participant under the Plan shall be subject to any claim of any creditor, and, in particular, to the fullest extent permitted by law, all such payments, benefits and rights shall be free from attachment, garnishment, trustee’s process, or any other legal or equitable process available to any creditor of such Participant. No Participant shall have the right to alienate, anticipate, commute, pledge, encumber or assign any of the benefits or payments which he or she may expect to receive, contingently or otherwise, under the Plan.

12.2 Compensation. Any amounts payable hereunder shall not be deemed salary or other compensation to a Participant for the purposes of computing benefits to which the Participant may be entitled under any other arrangement established by the Employer for the benefit of its employees.

12.3 No Contract of Employment. Neither the establishment of the Plan, nor any modification thereof, nor the creation of any fund, trust or account, nor the payment of any benefits shall be construed as giving any Participant or Employee, or any person whomsoever, the right to be retained in the service of the Company or any other participating employer hereunder, and all Participants and other Employees shall remain subject to discharge to the same extent as if the Plan had never been adopted.

12.4 Severability of Provisions. If any provision of the Plan shall be held invalid or unenforceable, such invalidity or unenforceability shall not affect any other provisions hereof, and the Plan shall be construed and enforced as if such provision had not been included.

12.5 Heirs, Assigns and Personal Representatives. The Plan shall be binding upon the heirs, executors, administrators, successors and assigns of the parties, including each Participant, present and future.

12.6 Successors. Unless the Compensation Committee directs otherwise before a Change of Control, in the event of a Change of Control, the Company shall require any successor or successors (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company thereof, (i) to acknowledge expressly that this Plan is binding upon and enforceable against such successor in accordance with the terms hereof, (ii) to become jointly and severally obligated with the Company to perform the obligations under this Plan, and (iii) to agree not to amend or terminate the Plan for a period of three years after the date of succession without the consent of the affected Participant.

12.7 Headings and Captions. The headings and captions herein are provided for reference and convenience only, and shall not be considered part of the Plan, and shall not be employed in the construction of the Plan.

12.8 Controlling Law. The Plan shall be construed and enforced according to the laws of the Commonwealth of Pennsylvania, exclusive of conflict of law provisions thereof, to the extent not preempted by Federal law, which shall otherwise control.

12.9 Payments to Minors, Etc. Any benefit payable to or for the benefit of a minor, an incompetent person or other person incapable of receipting therefore shall be deemed paid when paid to such person’s guardian or to the party providing or reasonably appearing to provide for the care of such person, and such payment shall fully discharge the Company, the Board, the Compensation Committee, the Administrative Committee and all other parties with respect thereto.

17

12.10 Reliance on Data and Consents. The Company, the Board, the Compensation Committee, the Administrative Committee and all other persons or entities associated with the operation of the Plan, and the provision of benefits thereunder, may reasonably rely on the truth, accuracy and completeness of all data provided by the Participant, including, without limitation, data with respect to age, health and marital status. Furthermore, the Company, the Board, the Compensation Committee and the Administrative Committee may reasonably rely on all consents, elections and designations filed with the Plan or those associated with the operation of the Plan by any Participant, or the representatives of any such person without duty to inquire into the genuineness of any such consent, election or designation. None of the aforementioned persons or entities associated with the operation of the Plan or the benefits provided under the Plan shall have any duty to inquire into any such data, and all may rely on such data being current to the date of reference, it being the duty of the Participants to advise the appropriate parties of any change in such data.

12.11 Section 409A

(a) The Plan is intended to comply with the requirements of section 409A of the Code, and shall in all respects be administered in accordance with section 409A. Notwithstanding anything in the Plan to the contrary, distributions may only be made under the Plan upon an event and in a manner permitted by section 409A of the Code. To the extent that any provision of the Plan would cause a conflict with the requirements of section 409A of the Code, or would cause the administration of the Plan to fail to satisfy the requirements of section 409A, such provision shall be deemed null and void to the extent permitted by applicable law. In no event shall a Participant, directly or indirectly, designate the calendar year of payment, except as permitted by section 409A of the Code.

(b) If a Participant is subject to tax under the Federal Insurance Contribution Act (FICA) on his or her Account before distributions are to be made under the Plan, a distribution may be made under the Plan to pay the FICA tax imposed under section 3101 of the Code, section 3121(a) of the Code, and section 3121(v)(2) of the Code, or to pay the income tax at source on wages imposed under section 3401 of the Code or the corresponding withholding provisions of applicable state, local, or foreign tax laws as a result of the payment of the FICA amount, and to pay the additional income tax at source on wages attributable to the pyramiding section 3401 of the Code wages and taxes. The total payment made pursuant to this subsection must not exceed the aggregate FICA and related tax amount permitted under section 409A of the Code.

18

12.11 Stock Units Subject to Equity Plan Provisions. In addition to the provisions of this Plan, Stock Units shall be governed by the Equity Plan and the Terms and Conditions established with respect to the Equity Plan, both of which are incorporated herein by reference. Stock Units shall be interpreted and administered in accordance with the Equity Plan, including provisions pertaining to (i) the registration, qualification or listing of the shares of Company common stock, (ii) changes in capitalization of the Company and (iii) other requirements of applicable law.

12.12 Phantom Units Subject to 2010 AmeriGas LTIP Provisions. In addition to the provisions of this Plan, Phantom Units shall be governed by the 2010 AmeriGas LTIP and the Terms and Conditions established with respect to the 2010 AmeriGas LTIP, both of which are incorporated herein by reference. Phantom Units shall be interpreted and administered in accordance with the 2010 AmeriGas LTIP, including provisions pertaining to (i) the registration, qualification or listing of the Common Units, (ii) changes in capitalization of APLP and (iii) other requirements of applicable law.

19

Exhibit A

Distribution Election Form — UGI SERP Participants

UGI Corporation
2009 Deferral Plan Distribution Election Form — UGI SERP Participants

Name

Address

Daytime Phone Number

Under the UGI Corporation 2009 Deferral Plan (the “Deferral Plan”), you may elect to have your accrued benefit in the UGI Corporation Supplemental Executive Retirement Plan (“UGI SERP”) at separation from service credited to the Deferral Plan upon your separation from service. If you wish to do this, you must also elect the time and form of payment of the account that will be established for you under the Deferral Plan. The alternative times and forms of payment are listed below.

You should review the Deferral Plan document for a complete description of how the Deferral Plan works. The capitalized terms used below are defined in the Deferral Plan. This election is subject to the terms and conditions of the Deferral Plan, which are incorporated herein by reference.

Please complete and return this form to the Corporate Secretary, UGI Corporation, 460 Gulph Road, King of Prussia, PA 19406.

I. TIME AND FORM OF PAYMENT (After Separation from Service)

Note: You may check one form of payment for your entire UGI SERP benefit, or you may specify that your UGI SERP benefit will be paid in several forms of payment, by specifying whole percentages. If you specify several forms of payment, you should make sure that the percentages add up to 100%.

Upon Separation from Service, I elect to have my UGI SERP benefit distributed as follows:

A. Lump Sum Payment:

• Lump sum payment at my Separation from Service. (Note: Under section 409A of the Internal Revenue Code, this payment will be made six months following your Separation from Service.)

This election applies to                     % of my UGI SERP benefit.

B. Installment Payments:

• Payments in                      (Note: Fill in 2 to 10) annual installments, commencing 14 months following my Separation from Service, and annually thereafter in the calendar year following the first payment and subsequent calendar years.

This election applies to                     % of my UGI SERP benefit.

20

C. One to Five Retirement Distribution Accounts:

• Retirement Distribution Account #1 — Lump sum payment 14 months following my Separation from Service. This election applies to                     % of my UGI SERP benefit.

• Retirement Distribution Account #2 — Lump sum payment in the first calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my UGI SERP benefit.

• Retirement Distribution Account #3 — Lump sum payment in the second calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my UGI SERP benefit.

• Retirement Distribution Account #4 — Lump sum payment in the third calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my UGI SERP benefit.

• Retirement Distribution Account #5 — Lump sum payment in the fourth calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my UGI SERP benefit.

Note: These elections are irrevocable. Under the Deferral Plan and section 409A of the Internal Revenue Code, you may make a Re-Deferral Election to postpone a payment, but not to accelerate a payment. Any Re-Deferral Election must be made at least one year before the scheduled payment date and must postpone payment for at least five years beyond the scheduled payment date. Re-Deferral Elections are subject to other restrictions described in the Deferral Plan.

II. BENEFICIARY DESIGNATION

Note: If you die before your Separation from Service, only your surviving spouse will receive a benefit under the UGI SERP. No other death benefits are provided under the UGI SERP in the event of death before Separation from Service.

If you die after Separation from Service but before your UGI SERP benefit has been completely distributed, your unpaid benefit will be payable to your designated Beneficiary. If you designate more than one Beneficiary, you should make sure that the percentages add up to 100%.

Beneficiary Designation: I designate the following persons to be the Beneficiary of my UGI SERP benefit (including my account under the Deferral Plan) if I die after Separation from Service. If any designated Beneficiary is not living (or is not in existence) at my death, then that Beneficiary’s share shall be allocated pro rata to the other surviving Beneficiaries. If no designated Beneficiary is living (or is in existence) at my death, then my Beneficiary shall be my estate. (Note: If more than one Beneficiary is named, please indicate percentage to be paid to each.)

		%
Name	Street
Relationship	City
State	Zip

21

		%
Name	Street
Relationship	City
State	Zip
		%
Name	Street
Relationship	City
State	Zip

The foregoing Beneficiary designation supersedes and replaces any previous Beneficiary designation that I may have made under the UGI SERP or the Deferral Plan.

III. ACKNOWLEDGMENT AND SIGNATURE

By signing this election form, I understand that these elections are made in accordance with and are subject to the terms of the Deferral Plan. I understand and agree that the Deferral Plan’s Administrative Committee shall have full power and express discretionary authority to interpret and administer the Deferral Plan and to make all determinations with respect to the Deferral Plan. All actions taken by the Deferral Plan’s Administrative Committee shall be final, conclusive and binding upon all participants, beneficiaries, spouses and all other persons having an interest therein.

These elections are irrevocable and are subject to the terms of the Deferral Plan.

Date Name

[To be completed by [_____]]

Filing Date

Date received by [_____]:  _____, _____ 

22

Exhibit B

Distribution Election Form — AmeriGas SERP Participants

UGI Corporation
2009 Deferral Plan Distribution Election Form — AmeriGas SERP Participants

Name

Address

Daytime Phone Number

Under the UGI Corporation 2009 Deferral Plan (the “Deferral Plan”), you may elect to have your accrued benefit in the AmeriGas Propane, Inc. Supplemental Executive Retirement Plan (“AmeriGas SERP”) at separation from service credited to the Deferral Plan upon your separation from service. If you wish to do this, you must also elect the time and form of payment of the account that will be established for you under the Deferral Plan. The alternative times and forms of payment are listed below.

You should review the Deferral Plan document for a complete description of how the Deferral Plan works. The capitalized terms used below are defined in the Deferral Plan. This election is subject to the terms and conditions of the Deferral Plan, which are incorporated herein by reference.

Please complete and return this form to the Corporate Secretary, UGI Corporation, 460 Gulph Road, King of Prussia, PA 19406.

I. TIME AND FORM OF PAYMENT (After Separation from Service)

Note: You may check one form of payment for your entire AmeriGas SERP benefit, or you may specify that your AmeriGas SERP benefit will be paid in several forms of payment, by specifying whole percentages. If you specify several forms of payment, you should make sure that the percentages add up to 100%.

Upon Separation from Service, I elect to have my AmeriGas SERP benefit distributed as follows:

A. Lump Sum Payment:

• Lump sum payment at my Separation from Service. (Note: Under section 409A of the Internal Revenue Code, this payment will be made six months following your Separation from Service.)

This election applies to                     % of my AmeriGas SERP benefit.

B. Installment Payments:

• Payments in                      (Note: Fill in 2 to 10) annual installments, commencing 14 months following my Separation from Service, and annually thereafter in the calendar year following the first payment and subsequent calendar years.

This election applies to                     % of my AmeriGas SERP benefit.

23

C. One to Five Retirement Distribution Accounts:

• Retirement Distribution Account #1 — Lump sum payment 14 months following my Separation from Service. This election applies to                     % of my AmeriGas SERP benefit.

• Retirement Distribution Account #2 — Lump sum payment in the first calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my AmeriGas SERP benefit.

• Retirement Distribution Account #3 — Lump sum payment in the second calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my AmeriGas SERP benefit.

• Retirement Distribution Account #4 — Lump sum payment in the third calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my AmeriGas SERP benefit.

• Retirement Distribution Account #5 — Lump sum payment in the fourth calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my AmeriGas SERP benefit.

Note: These elections are irrevocable. Under the Deferral Plan and section 409A of the Internal Revenue Code, you may make a Re-Deferral Election to postpone a payment, but not to accelerate a payment. Any Re-Deferral Election must be made at least one year before the scheduled payment date and must postpone payment for at least five years beyond the scheduled payment date. Re-Deferral Elections are subject to other restrictions described in the Deferral Plan.

II. BENEFICIARY DESIGNATION

If you die before receiving your entire AmeriGas SERP benefit, your benefit under the AmeriGas SERP will be payable to your designated Beneficiary. If you designate more than one Beneficiary, you should make sure that the percentages add up to 100%.

Beneficiary Designation: I designate the following persons to be the Beneficiary of my AmeriGas SERP benefit (including my account under the Deferral Plan) if I die before or after Separation from Service. If any designated Beneficiary is not living (or is not in existence) at my death, then that Beneficiary’s share shall be allocated pro rata to the other surviving Beneficiaries. If no designated beneficiary is living (or in existence) at my death, then my Beneficiary shall be my estate. (Note: If more than one Beneficiary is named, please indicate percentage to be paid to each.)

		%
Name	Street
Relationship	City
State	Zip

24

		%
Name	Street
Relationship	City
State	Zip
		%
Name	Street
Relationship	City
State	Zip

The foregoing Beneficiary designation supersedes and replaces any previous Beneficiary designation that I may have made under the AmeriGas SERP or the Deferral Plan.

III. ACKNOWLEDGMENT AND SIGNATURE

By signing this election form, I understand that these elections are made in accordance with and are subject to the terms of the Deferral Plan. I understand and agree that the Deferral Plan’s Administrative Committee shall have full power and express discretionary authority to interpret and administer the Deferral Plan and to make all determinations with respect to the Deferral Plan. All actions taken by the Deferral Plan’s Administrative Committee shall be final, conclusive and binding upon all participants, beneficiaries, spouses and all other persons having an interest therein.

These elections are irrevocable and are subject to the terms of the Deferral Plan.

Date Name

[To be completed by [_____]]

[To be completed by [_____]]

Filing Date

Date received by [_____]:  _____, _____ 

25

Exhibit C

Distribution Election Form — Non-Employee Directors

UGI Corporation
2009 Deferral Plan Distribution Election Form — UGI Non-Employee Directors

Name

Address

Daytime Phone Number

Under the UGI Corporation 2009 Deferral Plan (the “Deferral Plan”), you may elect to have your outstanding Stock Units at separation from service credited to the Deferral Plan upon your separation from service. If you wish to do this, you must also elect the time and form of payment of the account that will be established for you under the Deferral Plan. The alternative times and forms of payment are listed below.

You should review the Deferral Plan document for a complete description of how the Deferral Plan works. The capitalized terms used below are defined in the Deferral Plan. This election is subject to the terms and conditions of the Deferral Plan, which are incorporated herein by reference.

Please complete and return this form to the Corporate Secretary, UGI Corporation, 460 Gulph Road, King of Prussia, PA 19406.

I. TIME AND FORM OF PAYMENT (After Separation from Service)

Note: You may check one form of payment for all of your Stock Units, or you may specify that your Stock Units be paid in several forms of payment, by specifying whole percentages. If you specify several forms of payment, you should make sure that the percentages add up to 100%.

Upon Separation from Service, I elect to have my Stock Units distributed as follows:

A. Lump Sum Payment:

• Lump sum payment at my Separation from Service.

This election applies to                     % of my Stock Units.

B. Installment Payments:

• Payments in  _____  (Note: Fill in 2 to 10) annual installments, commencing 14 months following my Separation from Service, and annually thereafter in the calendar year following the first payment and subsequent calendar years.

This election applies to                     % of my Stock Units.

26

C. One to Five Retirement Distribution Accounts:

• Retirement Distribution Account #1 — Lump sum payment 14 months following my Separation from Service. This election applies to                     % of my Stock Units.

• Retirement Distribution Account #2 — Lump sum payment in the first calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my Stock Units.

• Retirement Distribution Account #3 — Lump sum payment in the second calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my Stock Units.

• Retirement Distribution Account #4 — Lump sum payment in the third calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my Stock Units.

• Retirement Distribution Account #5 — Lump sum payment in the fourth calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my Stock Units.

Note: These elections are irrevocable. Under the Deferral Plan and section 409A of the Internal Revenue Code, you may make a Re-Deferral Election to postpone a payment, but not to accelerate a payment. Any Re-Deferral Election must be made at least one year before the scheduled payment date and must postpone payment for at least five years beyond the scheduled payment date. Re-Deferral Elections are subject to other restrictions described in the Deferral Plan.

II. BENEFICIARY DESIGNATION

If you die before payment of all your Stock Units, your Stock Units will be payable to your designated Beneficiary, notwithstanding any provision of your Stock Unit agreement to the contrary. If you designate more than one Beneficiary, you should make sure that the percentages add up to 100%.

Beneficiary Designation: I designate the following persons to be the Beneficiary under the Deferral Plan if I die before or after Separation from Service. If any designated Beneficiary is not living (or is not in existence) at my death, then that Beneficiary’s share shall be allocated pro rata to the other surviving Beneficiaries. If no designated Beneficiary is living (or in existence) at my death, then my Beneficiary shall be my estate. (Note: If more than one Beneficiary is named, please indicate percentage to be paid to each.)

		%
Name	Street
Relationship	City
State	Zip

27

		%
Name	Street
Relationship	City
State	Zip
		%
Name	Street
Relationship	City
State	Zip

The foregoing Beneficiary designation supersedes and replaces any previous Beneficiary designation that I may have made with respect to the Stock Units under the Deferral Plan.

III. ACKNOWLEDGMENT AND SIGNATURE

By signing this election form, I understand that these elections are made in accordance with and are subject to the terms of the Deferral Plan. I understand and agree that the Deferral Plan’s Administrative Committee shall have full power and express discretionary authority to interpret and administer the Deferral Plan and to make all determinations with respect to the Deferral Plan. All actions taken by the Deferral Plan’s Administrative Committee shall be final, conclusive and binding upon all participants, beneficiaries, spouses and all other persons having an interest therein.

These elections are irrevocable and are subject to the terms of the Deferral Plan.

Date Name

[To be completed by [_____]]

Filing Date

Date received by [_____]:  _____,  _____ 

28

Exhibit D

Distribution Election Form — 2009 UGI SERP Participants

UGI Corporation
2009 Deferral Plan Distribution Election Form — 2009 UGI SERP Participants

Name

Address

Daytime Phone Number

Under the UGI Corporation 2009 Deferral Plan (the “Deferral Plan”), you may elect to have your accrued benefit in the UGI Corporation 2009 Supplemental Executive Retirement Plan (“2009 UGI SERP”) at separation from service credited to the Deferral Plan upon your separation from service. If you wish to do this, you must also elect the time and form of payment of the account that will be established for you under the Deferral Plan. The alternative times and forms of payment are listed below.

You should review the Deferral Plan document for a complete description of how the Deferral Plan works. The capitalized terms used below are defined in the Deferral Plan. This election is subject to the terms and conditions of the Deferral Plan, which are incorporated herein by reference.

Please complete and return this form to the Corporate Secretary, UGI Corporation, 460 Gulph Road, King of Prussia, PA 19406.

I. TIME AND FORM OF PAYMENT (After Separation from Service)

Note: You may check one form of payment for your entire 2009 UGI SERP benefit, or you may specify that your 2009 UGI SERP benefit will be paid in several forms of payment, by specifying whole percentages. If you specify several forms of payment, you should make sure that the percentages add up to 100%.

Upon Separation from Service, I elect to have my 2009 UGI SERP benefit distributed as follows:

A. Lump Sum Payment:

• Lump sum payment at my Separation from Service. (Note: Under section 409A of the Internal Revenue Code, this payment will be made six months following your Separation from Service.)

This election applies to                     % of my 2009 UGI SERP benefit.

B. Installment Payments:

• Payments in  _____  (Note: Fill in 2 to 10) annual installments, commencing 14 months following my Separation from Service, and annually thereafter in the calendar year following the first payment and subsequent calendar years.

This election applies to                     % of my 2009 UGI SERP benefit.

29

C. One to Five Retirement Distribution Accounts:

• Retirement Distribution Account #1 — Lump sum payment 14 months following my Separation from Service. This election applies to                     % of my 2009 UGI SERP benefit.

• Retirement Distribution Account #2 — Lump sum payment in the first calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my 2009 UGI SERP benefit.

• Retirement Distribution Account #3 — Lump sum payment in the second calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my 2009 UGI SERP benefit.

• Retirement Distribution Account #4 — Lump sum payment in the third calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my 2009 UGI SERP benefit.

• Retirement Distribution Account #5 — Lump sum payment in the fourth calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my 2009 UGI SERP benefit.

Note: These elections are irrevocable. Under the Deferral Plan and section 409A of the Internal Revenue Code, you may make a Re-Deferral Election to postpone a payment, but not to accelerate a payment. Any Re-Deferral Election must be made at least one year before the scheduled payment date and must postpone payment for at least five years beyond the scheduled payment date. Re-Deferral Elections are subject to other restrictions described in the Deferral Plan.

II. BENEFICIARY DESIGNATION

If you die before receiving your entire 2009 UGI SERP benefit, your benefit under the 2009 UGI SERP will be payable to your designated Beneficiary. If you designate more than one Beneficiary, you should make sure that the percentages add up to 100%.

Beneficiary Designation: I designate the following persons to be the Beneficiary of my 2009 UGI SERP benefit (including my account under the Deferral Plan) if I die after Separation from Service. If any designated Beneficiary is not living (or is not in existence) at my death, then that Beneficiary’s share shall be allocated pro rata to the other surviving Beneficiaries. If no designated Beneficiary is living (or is in existence) at my death, then my Beneficiary shall be my estate. (Note: If more than one Beneficiary is named, please indicate percentage to be paid to each.)

		%
Name	Street
Relationship	City
State	Zip

30

		%
Name	Street
Relationship	City
State	Zip
		%
Name	Street
Relationship	City
State	Zip

The foregoing Beneficiary designation supersedes and replaces any previous Beneficiary designation that I may have made under the 2009 UGI SERP or the Deferral Plan.

III. ACKNOWLEDGMENT AND SIGNATURE

By signing this election form, I understand that these elections are made in accordance with and are subject to the terms of the Deferral Plan. I understand and agree that the Deferral Plan’s Administrative Committee shall have full power and express discretionary authority to interpret and administer the Deferral Plan and to make all determinations with respect to the Deferral Plan. All actions taken by the Deferral Plan’s Administrative Committee shall be final, conclusive and binding upon all participants, beneficiaries, spouses and all other persons having an interest therein.

These elections are irrevocable and are subject to the terms of the Deferral Plan.

Date Name

[To be completed by [_____]]

Filing Date

Date received by [_____]:  _____,  _____ 

31

Exhibit E

Distribution Election Form — AmeriGas Non-Employee Directors

UGI Corporation
2009 Deferral Plan Distribution Election Form — AmeriGas Non-Employee Directors

Name

Address

Daytime Phone Number

Under the UGI Corporation 2009 Deferral Plan (the “Deferral Plan”), you may elect to have your outstanding phantom units under the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on behalf of AmeriGas Partners, L.P. (“Phantom Units”) at separation from service credited to the Deferral Plan upon your separation from service. If you wish to do this, you must also elect the time and form of payment of the account that will be established for you under the Deferral Plan. The alternative times and forms of payment are listed below.

You should review the Deferral Plan document for a complete description of how the Deferral Plan works. The capitalized terms used below are defined in the Deferral Plan. This election is subject to the terms and conditions of the Deferral Plan, which are incorporated herein by reference.

Please complete and return this form to the Corporate Secretary, UGI Corporation, 460 Gulph Road, King of Prussia, PA 19406.

I. TIME AND FORM OF PAYMENT (After Separation from Service)

Note: You may check one form of payment for all of your Phantom Units, or you may specify that your Phantom Units will be paid in several forms of payment, by specifying whole percentages. If you specify several forms of payment, you should make sure that the percentages add up to 100%.

Upon Separation from Service, I elect to have my Phantom Units distributed as follows:

A. Lump Sum Payment:

• Lump sum payment at my Separation from Service.

This election applies to                     % of my Phantom Units.

B. Installment Payments:

• Payments in  _____  (Note: Fill in 2 to 10) annual installments, commencing 14 months following my Separation from Service, and annually thereafter in the calendar year following the first payment and subsequent calendar years.

This election applies to                     % of my Phantom Units.

32

C. One to Five Retirement Distribution Accounts:

• Retirement Distribution Account #1 — Lump sum payment 14 months following my Separation from Service. This election applies to                     % of my Phantom Units.

• Retirement Distribution Account #2 — Lump sum payment in the first calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my Phantom Units.

• Retirement Distribution Account #3 — Lump sum payment in the second calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my Phantom Units.

• Retirement Distribution Account #4 — Lump sum payment in the third calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my Phantom Units.

• Retirement Distribution Account #5 — Lump sum payment in the fourth calendar year following payment of Retirement Distribution Account #1. This election applies to                     % of my Phantom Units.

Note: These elections are irrevocable. Under the Deferral Plan and section 409A of the Internal Revenue Code, you may make a Re-Deferral Election to postpone a payment, but not to accelerate a payment. Any Re-Deferral Election must be made at least one year before the scheduled payment date and must postpone payment for at least five years beyond the scheduled payment date. Re-Deferral Elections are subject to other restrictions described in the Deferral Plan.

II. BENEFICIARY DESIGNATION

If you die before payment of all your Phantom Units, your Phantom Units will be payable to your designated Beneficiary. If you designate more than one Beneficiary, you should make sure that the percentages add up to 100%.

Beneficiary Designation: I designate the following persons to be the Beneficiary under the Deferral Plan if I die before or after Separation from Service. If any designated Beneficiary is not living (or is not in existence) at my death, then that Beneficiary’s share shall be allocated pro rata to the other surviving Beneficiaries. If no designated beneficiary is living (or in existence) at my death, then my Beneficiary shall be my estate. (Note: If more than one Beneficiary is named, please indicate percentage to be paid to each.)

		%
Name	Street
Relationship	City
State	Zip

33

		%
Name	Street
Relationship	City
State	Zip
		%
Name	Street
Relationship	City
State	Zip

The foregoing Beneficiary designation supersedes and replaces any previous Beneficiary designation that I may have made with respect to the Phantom Units under the Deferral Plan.

III. ACKNOWLEDGMENT AND SIGNATURE

By signing this election form, I understand that these elections are made in accordance with and are subject to the terms of the Deferral Plan. I understand and agree that the Deferral Plan’s Administrative Committee shall have full power and express discretionary authority to interpret and administer the Deferral Plan and to make all determinations with respect to the Deferral Plan. All actions taken by the Deferral Plan’s Administrative Committee shall be final, conclusive and binding upon all participants, beneficiaries, spouses and all other persons having an interest therein.

These elections are irrevocable and are subject to the terms of the Deferral Plan.

Date Name

To be completed by [_____]]

Filing Date

Date received by [_____]:  _____,  _____ 

34

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Lon R. Greenberg, certify that:

1. I have reviewed this periodic report on Form 10-Q of UGI Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 6, 2010

/s/ Lon R. Greenberg  

Lon R. Greenberg 

Chairman and Chief Executive Officer of
UGI Corporation 

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Peter Kelly, certify that:

1. I have reviewed this periodic report on Form 10-Q of UGI Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 6, 2010

/s/ Peter Kelly  

Peter Kelly 

Vice President - Finance and
Chief Financial Officer of UGI Corporation 

EX-32

EXHIBIT 32

Certification by the Chief Executive Officer and Chief Financial Officer
Relating to a Periodic Report Containing Financial Statements

I, Lon R. Greenberg, Chief Executive Officer, and I, Peter Kelly, Chief Financial Officer, of UGI Corporation, a Pennsylvania corporation (the “Company”), hereby certify that to our knowledge:

(1)	The Company’s periodic report on Form 10-Q for the period ended June 30, 2010 (the “Form 10-Q”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and
(2)	The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

CHIEF EXECUTIVE OFFICER	CHIEF FINANCIAL OFFICER
/s/ Lon R. Greenberg	/s/ Peter Kelly
Lon R. Greenberg	Peter Kelly
Date: August 6, 2010	Date: August 6, 2010