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, 2011

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) 337-7000
(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

Indicate 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 29, 2011, there were 111,804,420 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, 2011, September 30, 2010 and June 30, 2010		1
Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2011 and 2010		2
Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2011 and 2010		3
Notes to Condensed Consolidated Financial Statements		4 – 35
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		36 – 56
Item 3. Quantitative and Qualitative Disclosures About Market Risk		57 – 60
Item 4. Controls and Procedures		61
Part II Other Information
Item 1. Legal Proceedings		62
Item 1A. Risk Factors		62
Item 6. Exhibits		62 – 63
Signatures		64
Exhibit 31.1
Exhibit 31.2
Exhibit 32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

- i -

UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Millions of dollars)

	June 30,			September 30,			June 30,
	2011			2010			2010
ASSETS
Current assets:
Cash and cash equivalents	$	317.8		$	260.7		$	241.8
Restricted cash		10.2			34.8			22.9
Accounts receivable (less allowances for doubtful accounts of $45.0, $34.6 and $44.5, respectively)		595.7			467.8			503.4
Accrued utility revenues		7.4			14.0			9.7
Inventories		271.6			314.0			249.2
Deferred income taxes		26.8			32.6			26.7
Derivative financial instruments		10.5			11.3			17.5
Prepaid expenses and other current assets		50.2			84.9			40.4
Total current assets		1,290.2			1,220.1			1,111.6
Property, plant and equipment (less accumulated depreciation and amortization of $2,065.9, $1,916.5 and $1,866.2, respectively)		3,228.0			3,053.2			2,875.5
Goodwill		1,612.0			1,562.7			1,475.9
Intangible assets, net		159.5			150.1			138.1
Other assets		384.0			388.2			230.5
Total assets	$	6,673.7		$	6,374.3		$	5,831.6
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	38.5		$	573.6		$	572.9
Bank loans		206.1			200.4			35.2
Accounts payable		338.7			372.6			297.9
Derivative financial instruments		21.2			58.0			48.0
Other current liabilities		430.4			470.1			379.5
Total current liabilities		1,034.9			1,674.7			1,333.5
Long-term debt		2,039.5			1,432.2			1,456.8
Deferred income taxes		678.3			601.4			510.9
Deferred investment tax credits		5.0			5.3			5.4
Other noncurrent liabilities		535.1			599.1			531.0
Total liabilities		4,292.8			4,312.7			3,837.6
Commitments and contingencies (note 10)
Equity:
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized — 300,000,000 shares; issued — 115,507,094, 115,400,294 and 115,375,794 shares, respectively)		934.9			906.1			896.1
Retained earnings		1,137.3			966.7			992.1
Accumulated other comprehensive income (loss)		67.6			(10.1	)		(115.8	)
Treasury stock, at cost		(28.6	)		(38.2	)		(42.4	)
Total UGI Corporation stockholders’ equity		2,111.2			1,824.5			1,730.0
Noncontrolling interests		269.7			237.1			264.0
Total equity		2,380.9			2,061.6			1,994.0
Total liabilities and equity	$	6,673.7		$	6,374.3		$	5,831.6

See accompanying notes to condensed consolidated financial statements.

- 1 -

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,
	2011			2010			2011			2010
Revenues	$	1,105.4		$	961.9		$	5,052.0		$	4,701.0
Costs and expenses:
Cost of sales (excluding depreciation shown below)		731.0			615.5			3,317.5			3,009.2
Operating and administrative expenses		304.3			267.6			966.4			892.7
Utility taxes other than income taxes		3.6			4.2			13.4			13.6
Depreciation		50.8			46.1			149.0			140.4
Amortization		7.0			5.6			19.6			16.9
Other income, net		(8.5	)		(8.3	)		(40.4	)		(12.2	)
		1,088.2			930.7			4,425.5			4,060.6
Operating income		17.2			31.2			626.5			640.4
Loss from equity investees		(0.2	)		(1.9	)		(0.8	)		(1.9	)
Loss on extinguishment of debt		—			—			(18.8	)		—
Interest expense		(35.0	)		(33.6	)		(102.6	)		(101.9	)
(Loss) income before income taxes		(18.0	)		(4.3	)		504.3			536.6
Income tax benefit (expense)		4.5			0.1			(147.2	)		(162.5	)
Net (loss) income		(13.5	)		(4.2	)		357.1			374.1
Less: net income (loss) attributable to noncontrolling interests, principally AmeriGas Partners		6.3			7.6			(101.8	)		(115.2	)
Net (loss) income attributable to UGI Corporation	$	(7.2	)	$	3.4		$	255.3		$	258.9
(Loss) earnings per common share attributable to UGI stockholders:
Basic	$	(0.06	)	$	0.03		$	2.29		$	2.37
Diluted	$	(0.06	)	$	0.03		$	2.26		$	2.35
Average common shares outstanding (thousands):
Basic		112,020			109,683			111,515			109,331
Diluted		112,020			110,699			113,046			110,188
Dividends declared per common share	$	0.26		$	0.25		$	0.76		$	0.65

See accompanying notes to condensed consolidated financial statements.

- 2 -

UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Millions of dollars)

	Nine Months Ended
	June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	357.1		$	374.1
Reconcile to net cash from operating activities:
Depreciation and amortization		168.6			157.3
Deferred income taxes, net		24.8			46.9
Provision for uncollectible accounts		19.8			26.2
Net change in realized gains and losses deferred as cash flow hedges		13.8			31.4
Loss on extinguishment of debt		18.8			—
Other, net		18.4			20.7
Net change in:
Accounts receivable and accrued utility revenues		(93.1	)		(147.3	)
Inventories		56.7			106.9
Utility deferred fuel costs		33.0			(1.0	)
Accounts payable		(51.3	)		(10.0	)
Other current assets		(6.8	)		(6.2	)
Other current liabilities		(92.6	)		(82.3	)
Net cash provided by operating activities		467.2			516.7
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(245.3	)		(228.8	)
Acquisitions of businesses, net of cash acquired		(49.6	)		(25.4	)
Decrease (increase) in restricted cash		24.6			(15.9	)
Other, net		(1.7	)		(14.7	)
Net cash used by investing activities		(272.0	)		(284.8	)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock		(84.7	)		(71.1	)
Distributions on AmeriGas Partners publicly held Common Units		(69.7	)		(66.2	)
Issuances of debt		981.5			—
Repayments of debt		(987.3	)		(9.5	)
Increase (decrease) in bank loans		5.4			(123.3	)
Receivables Facility net repayments		(12.1	)		—
Issuances of UGI Common Stock		24.9			16.6
Other		3.4			1.7
Net cash used by financing activities		(138.6	)		(251.8	)
EFFECT OF EXCHANGE RATE CHANGES ON CASH		0.5			(18.4	)
Cash and cash equivalents increase (decrease)	$	57.1		$	(38.3	)
Cash and cash equivalents:
End of period	$	317.8		$	241.8
Beginning of period		260.7			280.1
Increase (decrease)	$	57.1		$	(38.3	)

See accompanying notes to condensed consolidated financial statements.

- 3 -

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) an energy marketing, midstream infrastructure, storage and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”

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

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

- 4 -

UGI CORPORATION AND SUBSIDIARIES

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

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

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, 2010 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 Annual Report on Form 10-K for the year ended September 30, 2010 (“Company’s 2010 Annual Financial Statements and Notes”). 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.

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

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

- 5 -

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,
	2011		2010		2011		2010
Denominator (thousands of shares):
Average common shares outstanding for basic computation		112,020		109,683		111,515		109,331
Incremental shares issuable for stock options and awards		—		1,016		1,531		857
Average common shares outstanding for diluted computation		112,020		110,699		113,046		110,188

Comprehensive Income (Loss). The following table presents the components of comprehensive income (loss) for the three and nine months ended June 30, 2011 and 2010:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Net (loss) income	$	(13.5	)	$	(4.2	)	$	357.1		$	374.1
Other comprehensive (loss) income		(0.5	)		(58.2	)		76.5			(84.4	)
Comprehensive (loss) income (including noncontrolling interests)		(14.0	)		(62.4	)		433.6			289.7
Less: comprehensive income (loss) attributable to noncontrolling interests		10.8			21.4			(100.6	)		(107.7	)
Comprehensive (loss) income attributable to UGI Corporation	$	(3.2	)	$	(41.0	)	$	333.0		$	182.0

Other comprehensive (loss) income principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, 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.

Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in a decrease in regulatory assets (see Note 7) and an after-tax increase in other comprehensive income of $2.1 which is reflected in other comprehensive income in the nine months ended June 30, 2011.

Reclassifications. We have reclassified certain prior-year period balances to conform to the current-period presentation.

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

- 6 -

UGI CORPORATION AND SUBSIDIARIES

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

3. Accounting Changes

Adoption of New Accounting Standard

Transfers of Financial Assets. Effective October 1, 2010, the Company adopted new guidance regarding accounting for transfers of financial assets. Among other things, the new guidance eliminates the concept of Qualified Special Purpose Entities (“QSPEs”). It also amends previous derecognition guidance. The adoption of the new accounting guidance changed the Company’s accounting prospectively for sales of undivided interests in accounts receivable to the commercial paper conduit of a major bank under the Energy Services Receivables Facility. Effective October 1, 2010, trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the commercial paper conduit. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet. Also effective October 1, 2010, the Company records interest expense on amounts owed to the commercial paper conduit. Prior to October 1, 2010, losses on sales of accounts receivable to the commercial paper conduit were reflected in other income, net. Additionally, effective October 1, 2010 borrowings and repayments associated with the Energy Services Receivables Facility are reflected in cash flows from financing activities. Previously such transactions were reflected in cash flows from operating activities. For further information, see Note 6.

New Accounting Standards Not Yet Adopted

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

Presentation of Comprehensive Income. In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income,” which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) Topic 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. ASU 2011-05 does not change the items that must be reported in other comprehensive income. The change in presentation is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011 and the guidance is required to be applied retrospectively. Early adoption is permitted.

- 7 -

UGI CORPORATION AND SUBSIDIARIES

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

4. Intangible Assets

The Company’s intangible assets comprise the following:

	June 30,			September 30,			June 30,
	2011			2010			2010
Goodwill (not subject to amortization)	$	1,612.0		$	1,562.7		$	1,475.9
Other intangible assets:
Customer relationships, noncompete agreements and other	$	240.6		$	215.4		$	202.9
Trademarks (not subject to amortization)		51.9			46.3			41.5
Gross carrying amount		292.5			261.7			244.4
Accumulated amortization		(133.0	)		(111.6	)		(106.3	)
Net carrying amount	$	159.5		$	150.1		$	138.1

The increases in goodwill and other intangible assets during the nine months ended June 30, 2011 principally reflects the effects of acquisitions and currency translation. Amortization expense of intangible assets was $5.4 and $15.1 for the three and nine months ended June 30, 2011, respectively, and $4.9 and $14.8 for the three and nine months ended June 30, 2010, 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 remainder of Fiscal 2011 and the next four fiscal years is as follows: remainder of Fiscal 2011 — $5.0; Fiscal 2012 — $20.7; Fiscal 2013 — $20.1; Fiscal 2014 — $19.2; Fiscal 2015 — $16.2.

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, our propane distribution business in China and certain International Propane nonoperating entities (“Flaga & Other”); (4) Gas Utility; (5) Electric Utility; and (6) Midstream & Marketing. We refer to both international segments collectively as “International Propane.”

- 8 -

UGI CORPORATION AND SUBSIDIARIES

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

The accounting policies of our reportable segments are the same as those described in Note 2, “Significant Accounting Policies” in the Company’s 2010 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 Midstream & Marketing 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, 2011:

							Reportable Segments
																			International Propane
							AmeriGas			Gas			Electric			Energy						Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services			Antargaz			Other			& Other (b)
Revenues	$	1,105.4		$	(40.0	) (c)	$	470.8		$	148.1		$	24.1		$	217.1		$	161.0		$	102.3		$	22.0
Cost of sales	$	731.0		$	(39.1	) (c)	$	300.8		$	78.8		$	14.6		$	193.1		$	95.3		$	74.6		$	12.9
Segment profit:
Operating income (loss)	$	17.2		$	—		$	6.7		$	17.2		$	2.4		$	8.4		$	(11.4	)	$	(3.6	)	$	(2.5	)
Loss from equity investees		(0.2	)		—			—			—			—			—			(0.2	)		—			—
Interest expense		(35.0	)		—			(15.7	)		(9.9	)		(0.7	)		(0.6	)		(7.1	)		(0.8	)		(0.2	)
(Loss) income before income taxes	$	(18.0	)	$	—		$	(9.0	)	$	7.3		$	1.7		$	7.8		$	(18.7	)	$	(4.4	)	$	(2.7	)
Partnership EBITDA (a)							$	31.1
Noncontrolling interests’ net loss	$	(6.3	)	$	—		$	(6.1	)	$	—		$	—		$	—		$	(0.2	)	$	—		$	—
Depreciation and amortization	$	57.8		$	—		$	24.5		$	11.6		$	1.1		$	1.8		$	13.5		$	4.7		$	0.6
Capital expenditures	$	78.5		$	—		$	18.6		$	20.9		$	1.0		$	18.7		$	12.0		$	6.6		$	0.7
Total assets (at period end)	$	6,673.7		$	(81.0	)	$	1,772.1		$	2,002.0		$	156.5		$	572.2		$	1,678.2		$	407.3		$	166.4
Bank loans (at period end)	$	206.1		$	—		$	176.0		$	—		$	—		$	—		$	—		$	30.1		$	—
Goodwill (at period end)	$	1,612.0		$	—		$	695.8		$	180.1		$	—		$	2.8		$	641.1		$	85.3		$	6.9

Three Months Ended June 30, 2010:

							Reportable Segments
																		International Propane
							AmeriGas			Gas			Electric			Energy					Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other			& Other (b)
Revenues	$	961.9		$	(22.2	) (c)	$	396.6		$	149.1		$	25.3		$	198.6	$	150.8		$	41.0		$	22.7
Cost of sales	$	615.5		$	(20.7	) (c)	$	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 (a)							$	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

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

Three months ended June 30,	2011			2010
Partnership EBITDA	$	31.1		$	27.2
Depreciation and amortization		(24.5	)		(21.8	)
Noncontrolling interest (i)		0.1			(0.1	)
Operating income	$	6.7		$	5.3

(i)	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(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)	Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.

- 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, 2011:

							Reportable Segments
																			International Propane
							AmeriGas			Gas			Electric			Energy						Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services			Antargaz			Other			& Other (b)
Revenues	$	5,052.0		$	(172.9	) (c)	$	2,077.8		$	921.7		$	84.7		$	857.0		$	889.7		$	332.4		$	61.6
Cost of sales	$	3,317.5		$	(170.3	) (c)	$	1,300.9		$	562.3		$	53.4		$	738.6		$	554.0		$	243.8		$	34.8
Segment profit:
Operating income (loss)	$	626.5		$	0.2		$	252.9		$	193.2		$	9.0		$	76.7		$	101.0		$	(0.2	)	$	(6.3	)
Loss from equity investees		(0.8	)		—			—			—			—			—			(0.8	)		—			—
Loss on extinguishment of debt		(18.8	)		—			(18.8	)		—			—			—			—			—			—
Interest expense		(102.6	)		—			(47.4	)		(30.2	)		(1.8	)		(2.0	)		(18.5	)		(2.1	)		(0.6	)
Income (loss) before income taxes	$	504.3		$	0.2		$	186.7		$	163.0		$	7.2		$	74.7		$	81.7		$	(2.3	)	$	(6.9	)
Partnership EBITDA (a)							$	301.9
Noncontrolling interests’ net income	$	101.8		$	—		$	101.2		$	—		$	—		$	—		$	0.6		$	—		$	—
Depreciation and amortization	$	168.6		$	—		$	70.4		$	36.1		$	3.1		$	5.4		$	38.4		$	13.7		$	1.5
Capital expenditures	$	246.1		$	—		$	59.2		$	54.5		$	5.1		$	81.5		$	31.8		$	12.6		$	1.4
Total assets (at period end)	$	6,673.7		$	(81.0	)	$	1,772.1		$	2,002.0		$	156.5		$	572.2		$	1,678.2		$	407.3		$	166.4
Bank loans (at period end)	$	206.1		$	—		$	176.0		$	—		$	—		$	—		$	—		$	30.1		$	—
Goodwill (at period end)	$	1,612.0		$	—		$	695.8		$	180.1		$	—		$	2.8		$	641.1		$	85.3		$	6.9

Nine Months Ended June 30, 2010:

							Reportable Segments
																		International Propane
							AmeriGas			Gas			Electric			Energy					Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other			& Other (b)
Revenues	$	4,701.0		$	(146.9	) (c)	$	1,939.3		$	922.3		$	90.9		$	949.5	$	755.3		$	129.8		$	60.8
Cost of sales	$	3,009.2		$	(142.3	) (c)	$	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 (a)							$	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

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

Nine months ended June 30,	2011			2010
Partnership EBITDA	$	301.9	(ii)	$	323.7	(iii)
Depreciation and amortization		(70.4	)		(65.0	)
Loss on extinguishment of debt		18.8			—
Noncontrolling interest (i)		2.6			2.5
Operating income	$	252.9		$	261.2

(i)	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(ii)	Includes $18.8 loss associated with the extinguishment of Partnership debt.
(iii)	Includes $12.2 loss associated with the discontinuance of Partnership interest rate protection agreements.
(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)	Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.

- 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 2012, 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. Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC.

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

During the nine months ended June 30, 2011 and 2010, Energy Services transferred trade receivables to ESFC totaling $923.5 and $933.3, respectively. During the nine months ended June 30, 2011 and 2010, ESFC sold an aggregate $68.0 and $233.6, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At June 30, 2011, the balance of ESFC receivables was $50.9 and there was no amount sold to the commercial paper conduit. At June 30, 2010, the outstanding balance of ESFC receivables was $61.8 and there was no amount 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 2010 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,
	2011		2010		2010
Regulatory assets:
Income taxes recoverable	$	92.7	$	82.5	$	95.3
Underfunded pension and postretirement plans		116.0		159.2		10.3
Environmental costs		20.7		22.6		24.3
Deferred fuel and power costs		7.8		36.6		6.3
Other		8.9		5.8		5.5
Total regulatory assets	$	246.1	$	306.7	$	141.7
Regulatory liabilities:
Postretirement benefits	$	11.6	$	10.5	$	10.3
Environmental overcollections		6.2		7.2		8.3
Deferred fuel and power refunds		22.4		8.3		16.6
State tax benefits — distribution system repairs		6.2		6.7		11.0
Total regulatory liabilities	$	46.4	$	32.7	$	46.2

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

Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in a decrease in regulatory assets of $43.1 (see Note 8).

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, 2011, September 30, 2010 and June 30, 2010 were $1.1, $1.4 and $0.6, respectively.

- 13 -

UGI CORPORATION AND SUBSIDIARIES

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

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. As more fully described in Note 13, during Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value, with an associated adjustment to regulatory assets or liabilities in accordance with GAAP relating to rate-regulated entities and Electric Utility’s DS procurement, implementation and contingency plans. At June 30, 2011 and September 30, 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $10.1 and $19.7, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010 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, 2011, September 30, 2010 and June 30, 2010 were not material.

Other Regulatory Matters

Transfer of CPG Storage Assets. On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011 the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9. Compliance with the provisions of the PUC Order approving the transfer of the storage assets is not expected to have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.

- 14 -

UGI CORPORATION AND SUBSIDIARIES

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

CPG Base Rate Filing. On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5 annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). CPG requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the effective date for the rate increase to allow for investigation and public hearing. On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. Under the terms of the Joint Petition, CPG will be permitted to increase distribution rates by $8.0 in additional base rate revenue as well as $0.9 in revenues per year for use in CPG’s Energy and Efficiency Conservation Program. On July 19, 2011, a recommended decision was issued by the two assigned administrative law judges (“ALJs”) who recommended that the PUC approve the Joint Petition without modification. The recommended decision of the ALJs is subject to PUC approval. It is anticipated that this process will conclude by the end of Fiscal 2011.

8. Defined Benefit Pension and Other Postretirement Plans

In the U.S., we currently sponsor one defined benefit pension plan for employees hired prior to January 1, 2009 of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“Pension Plan”). We also provide postretirement health care benefits to certain retirees and 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.

- 15 -

UGI CORPORATION AND SUBSIDIARIES

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

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,
	2011			2010			2011			2010
Service cost	$	2.1		$	2.2		$	0.1		$	0.1
Interest cost		6.1			5.8			0.3			0.3
Expected return on assets		(6.4	)		(6.5	)		(0.1	)		(0.1	)
Amortization of:
Prior service cost (benefit)		0.1			—			(0.2	)		(0.1	)
Actuarial loss		1.7			1.5			0.1			0.1
Net benefit cost		3.6			3.0			0.2			0.3
Change in associated regulatory liabilities		—			—			0.8			0.7
Net expense	$	3.6		$	3.0		$	1.0		$	1.0

							Other
	Pension Benefits						Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Service cost	$	6.6		$	6.5		$	0.4		$	0.3
Interest cost		18.1			17.6			0.8			0.9
Expected return on assets		(19.4	)		(19.4	)		(0.4	)		(0.3	)
Amortization of:
Prior service cost (benefit)		0.2			—			(0.5	)		(0.3	)
Actuarial loss		5.7			4.4			0.3			0.2
Net benefit cost		11.2			9.1			0.6			0.8
Change in associated regulatory liabilities		—			—			2.4			2.2
Net expense	$	11.2		$	9.1		$	3.0		$	3.0

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. 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 $16.0 to the Pension Plan during the next twelve months. During the nine months ended June 30, 2011, the Company made contributions to the Pension Plan of $16.7. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to 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 for postretirement benefits other than pensions. The difference between such amounts calculated under GAAP and the amounts 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, 2011, nor are they expected to be material for all of Fiscal 2011.

- 16 -

UGI CORPORATION AND SUBSIDIARIES

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

We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans. We recorded pre-tax expense associated with these plans of $0.9 and $2.2 for the three and nine months ended June 30, 2011, respectively. 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.

Effective December 31, 2010, UGI Utilities merged its two defined benefit pension plans. The merged plan maintains the separate benefit formulas and specific rights and features of each predecessor plan. As a result of the merger and in accordance with GAAP relating to accounting for retirement benefits, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2010 which decreased other noncurrent liabilities by $46.7; decreased associated regulatory assets by $43.1; and increased pre-tax other comprehensive income by $3.6 (see Notes 2 and 7).

The following table provides a reconciliation of the projected benefit obligation (“PBO”), plan assets and the funded status of the merged Pension Plan as of December 31, 2010:

	Three Months
	Ended
	December 31,
	2010
Change in benefit obligations:
Benefit obligations — October 1, 2010	$	465.0
Service cost		2.2
Interest cost		5.8
Actuarial gain		(30.6	)
Benefits paid		(4.7	)
Benefit obligations — December 31, 2010	$	437.7
Change in plan assets:
Fair value of plan assets — October 1, 2010	$	287.9
Actual gain on assets		19.3
Employer contributions		1.8
Benefits paid		(4.7	)
Fair value of plan assets — December 31, 2010	$	304.3
Funded status of the merged plan — December 31, 2010	$	(133.4	)
At December 31, 2010:
Liabilities recorded in the balance sheet:
Unfunded liabilities — included in other current liabilities	$	(20.3	)
Unfunded liabilities — included in other noncurrent liabilities		(113.1	)
Net amount recognized	$	(133.4	)
Amounts recorded in regulatory assets and liabilities:
Prior service cost	$	0.3
Net actuarial loss		112.7
Total	$	113.0
Amounts recorded in stockholders’ equity:
Prior service cost	$	0.1
Net actuarial loss		9.8
Total	$	9.9

The accumulated benefit obligation (“ABO”) of the merged plan at December 31, 2010 is $391.2. Actuarial assumptions for the merged plan at December 31, 2010 are as follows: discount rate — 5.5%; expected return on plan assets — 8.5%; rate of increase in salary levels — 3.8%.

- 17 -

UGI CORPORATION AND SUBSIDIARIES

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

9. Debt

AmeriGas Partners. On January 20, 2011, AmeriGas Partners issued $470 principal amount of 6.50% Senior Notes due 2021. The proceeds from the issuance of the 6.50% Senior Notes were used in February 2011 to repay AmeriGas Partners’ $415 7.25% Senior Notes due May 15, 2015 pursuant to a January 5, 2011 tender offer and subsequent notice of redemption. The 6.50% Senior Notes due 2021 rank pari passu with AmeriGas Partners’ outstanding senior debt. In addition, in February 2011, AmeriGas Partners redeemed the outstanding $14.6 principal amount of AmeriGas Partners 8.875% Senior Notes due May 2011. The Partnership incurred a loss of $18.8 on these extinguishments of debt which amount is reflected on the Consolidated Statements of Income under the caption “Loss on extinguishment of debt.” The loss reduced net income attributable to UGI Corporation by $5.2 during the nine months ended June 30, 2011. The 6.50% Senior Notes of AmeriGas Partners restrict the ability of the Partnership and AmeriGas OLP to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets.

In addition, on June 21, 2011, AmeriGas OLP entered into an unsecured revolving credit agreement (the “AmeriGas 2011 Credit Agreement”) with a group of banks providing for borrowings up to $325 (including a $100 sublimit for letters of credit). Concurrently with entering into the AmeriGas 2011 Credit Agreement, AmeriGas OLP terminated its then-existing $200 revolving credit agreement dated as of November 6, 2006 and its $75 credit agreement dated as of April 17, 2009. The AmeriGas 2011 Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a two-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas 2011 Credit Agreement, plus a margin. The margin on base rate borrowings (which ranges from 0.75% to 1.75%), Eurodollar Rate borrowings (which ranges from 1.75% to 2.75%), and the AmeriGas 2011 Credit Agreement facility fee rate (which ranges from 0.30% to 0.50%) are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (“EBITDA”), each as defined in the AmeriGas 2011 Credit Agreement. The AmeriGas 2011 Credit Agreement restricts the incurrence of additional indebtedness and also restricts certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas 2011 Credit Agreement requires that AmeriGas OLP and AmeriGas Partners not exceed ratios of total indebtedness to EBITDA, as defined for each of those entities, and that AmeriGas Partners maintains a minimum ratio of EBITDA to interest expense, as defined.

Antargaz Refinancing. In March 2011, Antargaz entered into a new five-year variable rate term loan agreement with a consortium of banks (“2011 Senior Facilities Agreement”). The proceeds from the new term loan were used on March 16, 2011 to repay Antargaz’ existing Senior Facilities Agreement that was due March 31, 2011.

- 18 -

UGI CORPORATION AND SUBSIDIARIES

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

The new agreement consists of (1) a €380 variable-rate term loan and (2) a €40 revolving credit facility. Scheduled maturities under the term loan are €38 due May 2014, €34.2 due May 2015, and €307.8 due March 2016. Antargaz’ term loan and revolving credit facility bear interest at one-, two-, three- or six-month euribor, plus a margin, as defined by the 2011 Senior Facilities Agreement. The margin on the term loan and revolving credit facility borrowings (which ranges from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the 2011 Senior Facilities Agreement. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of 3.71% through the date of the term loan’s final maturity in March 2016. At June 30, 2011, the effective interest rate on Antargaz’ term loan was 4.66%. The 2011 Senior Facilities Agreement is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivables. In addition, UGI has guaranteed up to €100 of payments under the 2011 Senior Facilities Agreement. The 2011 Senior Facilities Agreement restricts the ability of Antargaz to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires Antargaz to maintain a ratio of net debt to EBITDA on a French generally accepted accounting basis, as defined in the agreement, that shall not exceed 3.50 to 1.00.

UGI Utilities 2011 Credit Agreement. On May 25, 2011, UGI Utilities entered into an unsecured revolving credit agreement (the “UGI Utilities 2011 Credit Agreement”) with a group of banks providing for borrowings up to $300 (including a $100 sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2011 Credit Agreement, UGI Utilities terminated its then-existing $350 revolving credit agreement dated as of August 11, 2006. Under the UGI Utilities 2011 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 2.0% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2011 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. The UGI Utilities 2011 Credit Agreement is currently scheduled to expire in May 2012, but may be extended by UGI Utilities to October 2015 if on or before May 23, 2012, the Company satisfies certain requirements relating to approval by the PUC. The Company is in the process of seeking such regulatory approval.

Flaga Working Capital Facility Extensions. During the three months ended June 30, 2011, Flaga extended the expiration dates of its two multi-currency working capital facilities, which provide for combined borrowings of €24, to September 2011. Also during the three months ended June 30, 2011, Flaga extended the expiration dates of its two euro-denominated working capital facilities, which provide for combined borrowings of €12, to March 2012.

- 19 -

UGI CORPORATION AND SUBSIDIARIES

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

10. 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, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

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

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

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.

- 20 -

UGI CORPORATION AND SUBSIDIARIES

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

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

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

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

- 21 -

UGI CORPORATION AND SUBSIDIARIES

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

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

Other Matters

Purported AmeriGas Class Action Lawsuits. On May 27, 2009, the General Partner was named as a defendant in a purported class action lawsuit in the Superior Court of the State of California in which plaintiffs challenged AmeriGas OLP’s weight disclosure with regard to its portable propane grill cylinders. After that initial suit, various AmeriGas entities were named in more than a dozen similar suits that were filed in various courts throughout the United States. All of those cases were consolidated and transferred to the United States District Court for the Western District of Missouri. On May 19, 2010, the Court granted the class’ motion seeking preliminary approval of the parties’ settlement. On October 4, 2010, the Court ruled that the settlement was fair, reasonable and adequate to the class and granted final approval of the settlement.

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

Swiger, et al. v. UGI/AmeriGas, Inc. et al. In 1996, a fire occurred at the residence of Samuel and Brenda Swiger (the “Swigers”) when propane that leaked from an underground line ignited. In July 1998, the Swigers filed a class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of Monongalia County, West Virginia, in which they sought to recover an unspecified amount of compensatory and punitive damages and attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants had installed propane gas lines, resulting from the defendants’ alleged failure to install underground propane lines at depths required by applicable safety standards. On December 14, 2010, AmeriGas OLP and its affiliates entered into a settlement agreement with the class, which was preliminarily approved by the Circuit Court of Monongalia County on January 13, 2011.

- 22 -

UGI CORPORATION AND SUBSIDIARIES

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

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

BP America Production Company v. Amerigas Propane, L.P. On July 15, 2011, BP America Production Company (“BP”) filed a complaint against AmeriGas Propane, L.P. in the District Court of Denver County, Colorado, alleging, among other things, breach of contract and breach of the covenant of good faith and fair dealing relating to amounts billed for certain goods and services provided to BP since 2005 (the “Services”). The Services relate to the installation of propane-fueled equipment and appliances, and the supply of propane, to approximately 400 residential customers at the request of and for the account of BP. The complaint seeks an unspecified amount of direct, indirect, consequential, special and compensatory damages, including attorneys’ fees, costs and interest and other appropriate relief. It also seeks an accounting to determine the amount of the alleged overcharges related to the Services. We recently commenced an investigation into these allegations. Because of the preliminary nature of this investigation, which is ongoing, the amount of loss, if any, cannot be reasonably estimated.

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. The Statement alleged that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through 2004. On December 17, 2010, the Competition Authority issued its decision dismissing all objections against Antargaz. The appeal period has expired without an appeal having been filed. As a result of the decision, during the three-month period ended December 31, 2010 the Company reversed its previously recorded nontaxable accrual for this matter which increased net income by $9.4. This amount is reflected in other income, net, on the Condensed Consolidated Statement of Income.

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

- 23 -

UGI CORPORATION AND SUBSIDIARIES

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

11. 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, 2011 and 2010:

				UGI Shareholders
									Accumulated
									Other
	Non-								Comprehensive
	controlling			Common		Retained			Income			Treasury			Total
	Interests			Stock		Earnings			(Loss)			Stock			Equity
Nine Months Ended June 30, 2011:
Balance September 30, 2010	$	237.1		$	906.1	$	966.7		$	(10.1	)	$	(38.2	)	$	2,061.6
Net income		101.8					255.3									357.1
Net gains on derivative instruments		14.8								10.8						25.6
Reclassifications of net (gains) losses on derivative instruments		(16.0	)							27.0						11.0
Benefit plans										2.1						2.1
Foreign currency translation adjustments										37.8						37.8
Comprehensive income		100.6					255.3			77.7						433.6
Dividends and distributions		(69.7	)				(84.7	)								(154.4	)
Equity transactions		0.5			28.8								9.6			38.9
Other		1.2														1.2
Balance June 30, 2011	$	269.7		$	934.9	$	1,137.3		$	67.6		$	(28.6	)	$	2,380.9
Nine Months Ended June 30, 2010:
Balance September 30, 2009	$	225.4		$	875.6	$	804.3		$	(38.9	)	$	(49.6	)	$	1,816.8
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	)
Equity transactions		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

- 24 -

UGI CORPORATION AND SUBSIDIARIES

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

12. 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, 2011, September 30, 2010 and June 30, 2010:

	Asset (Liability)
	Quoted Prices
	in Active			Significant
	Markets for			Other
	Identical Assets			Observable			Unobservable
	and Liabilities			Inputs			Inputs
	(Level 1)			(Level 2)			(Level 3)		Total
June 30, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	0.6		$	10.1		$	—	$	10.7
Interest rate contracts	$	—		$	5.0		$	—	$	5.0
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(12.2	)	$	(11.6	)	$	—	$	(23.8	)
Foreign currency contracts	$	—		$	(6.1	)	$	—	$	(6.1	)
Interest rate contracts	$	—		$	(3.6	)	$	—	$	(3.6	)
September 30, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	1.1		$	10.7		$	—	$	11.8
Foreign currency contracts	$	—		$	0.8		$	—	$	0.8
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(49.4	)	$	(20.3	)	$	—	$	(69.7	)
Foreign currency contracts	$	—		$	(2.9	)	$	—	$	(2.9	)
Interest rate contracts	$	—		$	(18.5	)	$	—	$	(18.5	)
June 30, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	0.4		$	3.2		$	—	$	3.6
Foreign currency contracts	$	—		$	16.9		$	—	$	16.9
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(25.4	)	$	(18.1	)	$	—	$	(43.5	)
Interest rate contracts	$	—		$	(16.4	)	$	—	$	(16.4	)

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

- 25 -

UGI CORPORATION AND SUBSIDIARIES

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

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, 2011 were $2,078.0 and $2,170.4, respectively. 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. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt.

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

13. Disclosures About Derivative Instruments and Hedging Activities

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

- 26 -

UGI CORPORATION AND SUBSIDIARIES

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

Commodity Price Risk

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

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At June 30, 2011 and 2010, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 18.6 million dekatherms and 11.3 million dekatherms, respectively. At June 30, 2011, the maximum period over which Gas Utility is hedging natural gas market price risk is 16 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with ASC No. 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 7).

Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At June 30, 2011, the fair values of Electric Utility’s forward purchase power agreements comprising a loss of $10.1 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying June 30, 2011 Condensed Consolidated Balance Sheet. In accordance with ASC 980, Electric Utility has recorded equal and offsetting amounts in regulatory assets on the June 30, 2011 Condensed Consolidated Balance Sheet. At June 30, 2011, volumes under Electric Utility’s forward electricity purchase contracts were 874.4 million kilowatt hours and the maximum period over which these contracts extend is 35 months.

- 27 -

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 associated with certain default service customers, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 7). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At June 30, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 287.3 million kilowatt hours and 739.3 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At June 30, 2011 and 2010, the volumes associated with Midstream & Marketing’s FTRs totaled 1,955.2 million kilowatt hours and 1,415.0 million kilowatt hours, respectively.

In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas and electricity futures contracts. In addition, beginning April 1, 2011, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Because the contracts associated with the anticipated sale of stored natural gas or propane do not qualify for hedge accounting treatment, any gains or losses on the derivative contracts are recognized in earnings prior to gains or losses from the sale of the stored gas. Such derivative gains or losses during the three months ended June 30, 2011 were not material. At June 30, 2011, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 2.3 million dekatherms and 0.9 million gallons, respectively.

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

- 28 -

UGI CORPORATION AND SUBSIDIARIES

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

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

	Volumes
	June 30,
Commodity	2011		2010
LPG (millions of gallons)		145.0		150.5
Natural gas (millions of dekatherms)		21.2		33.3
Electricity (millions of kilowatt-hours)		1,200.8		928.0

At June 30, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 15 months with a weighted average of 7 months; the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 30 months with a weighted average of 9 months; and the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity price risk (excluding Electric Utility) is 21 months with a weighted average of 7 months. At June 30, 2011, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 11 months.

We account for commodity price risk contracts (other than those contracts that are not eligible for hedge accounting and Gas Utility and Electric Utility contracts that are subject to regulatory treatment) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in 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 Condensed Consolidated Statements of Income. At June 30, 2011, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $8.7.

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 entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on a substantial portion of its term loans, in each case through the respective scheduled maturity dates. As of June 30, 2011 and 2010, the total notional amounts of existing or anticipated variable-rate debt subject to interest rate swap agreements were €398.8 and €706.2, respectively.

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At June 30, 2011, the total notional amount of unsettled IRPAs was $173.0. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt forecasted to occur in September 2012 and September 2013.

- 29 -

UGI CORPORATION AND SUBSIDIARIES

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

As previously disclosed, during the three months ended March 31, 2010, the Partnership’s management determined that it was likely that it would not issue $150 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 long-term debt issuance and recorded a $12.2 loss which is reflected in other income, net, on the Condensed Consolidated Statements of Income for the nine months ended 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, 2011, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $1.7 (which excludes the impact of AmeriGas Partners’ debt refinancing described in Note 15).

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At June 30, 2011 and 2010, we were hedging a total of $141.4 and $72.8 of U.S. dollar-denominated LPG purchases, respectively. At June 30, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 32 months with a weighted average of 12 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our International Propane euro-denominated net investments. At June 30, 2011 and 2010, we were hedging a total of €14.5 and €48.3, respectively, of our euro-denominated net investments. As of June 30, 2011, our foreign currency contracts extend through March 2014.

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 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, 2011, the amount of net losses associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $4.0. Gains and losses on net investment hedges remain in AOCI until such foreign net investment is sold or liquidated.

- 30 -

UGI CORPORATION AND SUBSIDIARIES

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

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and option contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. At June 30, 2011 and 2010, restricted cash in these accounts totaled $10.2 and $22.9, 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, 2011. We generally do not have credit-risk-related contingent features in our derivative contracts.

- 31 -

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 fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2011 and 2010:

	Derivative Assets					Derivative (Liabilities)
		Fair Value					Fair Value
	Balance Sheet	June 30,				Balance Sheet	June 30,
	Location	2011		2010		Location	2011			2010
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	6.0	$	0.3	Derivative financial instruments and Other noncurrent liabilities	$	(12.6	)	$	(42.8	)
Foreign currency contracts
	Derivative financial instruments and Other assets		—		16.9	Derivative financial instruments and Other noncurrent liabilities		(6.1	)		—
Interest rate contracts
	Other assets		5.0		—	Derivative financial instruments and Other noncurrent liabilities		(3.6	)		(16.4	)
Total Derivatives Designated as Hedging Instruments		$	11.0	$	17.2		$	(22.3	)	$	(59.2	)
Derivatives Accounted for under ASC 980:
Commodity contracts	Derivative financial instruments	$	0.2	$	0.6	Derivative financial instruments and Other noncurrent liabilities	$	(11.2	)	$	(0.8	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	$	4.5	$	2.8
Total Derivatives		$	15.7	$	20.6		$	(33.5	)	$	(60.0	)

- 32 -

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 on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three and nine months ended June 30, 2011 and 2010:

Three Months Ended June 30,:

	Gain (Loss)						Gain (Loss)						Location of
	Recognized in						Reclassified from						Gain (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2011			2010			2011			2010			Interests into Income
Cash Flow
Hedges:
Commodity contracts	$	(1.4	)	$	(14.6	)	$	3.9		$	(7.7	)	Cost of sales
Foreign currency contracts		(1.9	)		5.3			—			0.1		Cost of sales
Interest rate contracts		(13.2	)		(6.3	)		(2.4	)		(3.9	)	Interest expense / other income
Total	$	(16.5	)	$	(15.6	)	$	1.5		$	(11.5	)
Net Investment
Hedges:
Foreign currency contracts	$	(0.5	)	$	6.1
	Gain (Loss)
	Recognized in Income												Location of Gain (Loss)
	2011			2010									Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	—		$	(0.1	)							Operating expenses / other income
Commodity contracts		0.2			1.0								Cost of sales
Total	$	0.2		$	0.9

Nine Months Ended June 30,:

	Gain (Loss)						Gain (Loss)						Location of
	Recognized in						Reclassified from						Gain (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2011			2010			2011			2010			Interests into Income
Cash Flow
Hedges:
Commodity contracts	$	25.4		$	(30.1	)	$	(19.1	)	$	(14.1	)	Cost of sales
Foreign currency contracts		(3.4	)		12.2			(0.7	)		0.7		Cost of sales
Interest rate contracts		11.6			(7.2	)		(9.6	)		(24.4	)	Interest expense /other income
Total	$	33.6		$	(25.1	)	$	(29.4	)	$	(37.8	)
Net Investment
Hedges:
Foreign currency contracts	$	(1.1	)	$	11.2
	Gain (Loss)
	Recognized in Income												Location of Gain (Loss)
	2011			2010									Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	0.3		$	0.1								Operating expenses / other income
Commodity contracts		(0.4	)		1.4								Cost of sales
Total	$	(0.1	)	$	1.5

- 33 -

UGI CORPORATION AND SUBSIDIARIES

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

The amounts of derivative gains or losses representing ineffectiveness were not material for the three and nine months ended June 30, 2011 and 2010.

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

14. Inventories

Inventories comprise the following:

	June 30,		September 30,		June 30,
	2011		2010		2010
Non-utility LPG and natural gas	$	170.5	$	157.9	$	145.6
Gas Utility natural gas		50.1		111.5		60.3
Materials, supplies and other		51.0		44.6		43.3
Total inventories	$	271.6	$	314.0	$	249.2

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

The carrying values of natural gas storage inventories released under SCAAs with non-affiliates at June 30, 2011, September 30, 2010 and June 30, 2010 comprising 2.0 billion cubic feet (“bcf”), 8.0 bcf and 4.2 bcf of natural gas was $9.6, $41.9 and $23.2, respectively.

- 34 -

UGI CORPORATION AND SUBSIDIARIES

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

15. Subsequent Event — AmeriGas Refinancing

On July 27, 2011, AmeriGas Partners announced an offer to purchase for cash any and all of its $350 aggregate principal amount of outstanding 7 1/8% Senior Notes (“the 2016 Notes”) due May 2016 (the “Tender Offer”), subject to receipt of the proceeds of the issuance of $450 of 6.25% Senior Notes due 2019 (the “6.25% Notes”). The 6.25% Notes are expected to be issued on August 10, 2011. The proceeds from the offering will be used to finance the Tender Offer and for general corporate purposes, including to repay borrowings outstanding under the AmeriGas 2011 Credit Agreement. The Partnership intends to redeem any 2016 Notes that are not tendered in the Tender Offer. The Partnership expects to record a loss of approximately $20.0 associated with these transactions during the fourth quarter of Fiscal 2011 which is expected to reduce net income attributable to UGI Corporation by approximately $6.0.

- 35 -

UGI CORPORATION AND SUBSIDIARIES

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

Information contained in this Quarterly Report on Form 10-Q 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, counterparty 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; (17) the timing of development of Marcellus Shale gas production; and (18) the timing and success of our acquisitions, commercial initiatives and investments to grow our businesses.

These factors, and those factors set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010, 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.

- 36 -

UGI CORPORATION AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended June 30, 2011 (“2011 three-month period”) with the three months ended June 30, 2010 (“2010 three-month period”) and the nine months ended June 30, 2011 (“2011 nine-month period”) with the nine months ended June 30, 2010 (“2010 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 a net loss attributable to UGI Corporation of $(7.2) million for the 2011 three-month period compared to net income attributable to UGI Corporation of $3.4 million in the prior-year three-month period. Our 2011 three-month period net loss attributable to UGI Corporation includes greater seasonal losses from our International Propane operations reflecting the adverse effects of significantly warmer than normal late winter and spring weather and the adverse impact of continuing high LPG commodity prices on customer usage. Average temperatures in our Antargaz service territory were approximately 47% warmer than normal in the 2011 three-month period. The decline in the 2011 three-month period International Propane results was partially offset by modestly higher net income from our Gas Utility, principally resulting from greater total margin on higher volumes, and a slightly lower seasonal net loss from AmeriGas Propane reflecting higher total margin on increased retail sales. Midstream & Marketing results in the 2011 three-month period include higher natural gas and storage assets total margin partially offset by the effects of lower electric generation margin and the absence of income from Atlantic Energy, LLC’s (“Atlantic Energy’s”) import and transshipment facility which was sold in July 2010. The greater Midstream & Marketing total margin however was more than offset by slightly higher operating and administrative expenses and a higher effective income tax rate compared with the prior-year period.

For the 2011 nine-month period, we recorded net income attributable to UGI Corporation of $255.3 million compared to $258.9 million in the prior-year nine-month period. Results in the 2011 nine-month period include a $5.2 million after-tax loss associated with AmeriGas Partners’ February 2011 extinguishment of Senior Notes while net income attributable to UGI Corporation in the 2010 nine-month period includes a $3.3 million after-tax loss from the discontinuance of Partnership interest rate hedges. The 2011 nine-month period also reflects net income of $9.4 million from the reversal at Antargaz of a nontaxable reserve associated with the French Competition Authority Matter (see Note 10 to condensed consolidated financial statements).

- 37 -

UGI CORPORATION AND SUBSIDIARIES

Our 2011 nine-month period net income attributable to UGI Corporation primarily reflects greater net income from our Gas Utility principally the result of colder 2011-period weather and an improving economy. However this increase was more than offset principally by lower net income attributable to UGI Corporation from our International Propane and AmeriGas Propane operations. The 2011 nine-month period weather at Antargaz was warmer than the prior-year nine-month period reflecting significantly warmer late winter and spring weather which resulted in an early end to the heating season. In addition, average unit margins at Antargaz, primarily during the first quarter of Fiscal 2011, were negatively impacted by rapidly rising LPG product costs. AmeriGas Propane net income attributable to UGI Corporation was lower in the 2011 nine-month period principally reflecting the effects on volumes of significantly warmer early fall weather and, in our southern regions, significantly warmer late winter weather. The effects of these weather patterns and continued customer conservation, and the impact on the prior-year volumes of a strong crop-drying season, resulted in an overall decline in retail volumes sold. Midstream & Marketing’s contribution to net income attributable to UGI Corporation was slightly above the prior-year nine-month period as greater contributions principally from retail power marketing, winter peaking and asset management activities, and tax benefits associated with solar energy projects, were largely offset by the absence of earnings from Atlantic Energy and lower contribution from our electricity generation assets. The lower electricity generation contribution reflects in part the absence of earnings from UGID’s Hunlock Creek coal-fired generating station which was shut-down in May 2010 as it transitioned to a natural gas-fired generating station.

The U.S. dollar was weaker versus the euro during the 2011 three-month period which increased International Propane’s 2011 three-month period seasonal net loss by approximately 2 cents a share. On average, the U.S. dollar was stronger versus the euro during the 2011 nine-month period. The effects of the stronger dollar during the 2011 nine-month period reduced International Propane net income as compared to last year by approximately 4 cents a diluted share. These amounts include the effects of gains and losses on forward currency contracts used to hedge purchases of dollar-denominated LPG.

We believe that each of our business units has sufficient liquidity in the form of revolving credit facilities and, in the case of Energy Services, an accounts receivable securitization facility to fund business operations. UGI Utilities and AmeriGas OLP entered into new credit facilities during the third quarter of Fiscal 2011, and Energy Services extended its receivables securitization facility through April 2012. During the remainder of Fiscal 2011, Flaga intends to issue long-term debt to repay maturing term loans and to provide additional liquidity and to enter into a new multi-currency working capital facility.

- 38 -

UGI CORPORATION AND SUBSIDIARIES

2011 three-month period compared to the 2010 three-month period

Net income (loss) attributable to UGI Corporation by Business Unit:

	Three Months Ended						Variance - Favorable
	June 30,						(Unfavorable)
(Millions of dollars)	2011			2010			Amount			%
AmeriGas Propane	$	(2.0	)	$	(2.9	)	$	0.9			31.0	%
International Propane		(14.8	)		(3.5	)		(11.3	)		(322.9	)%
Gas Utility		4.5			2.4			2.1			87.5	%
Electric Utility		1.1			1.2			(0.1	)		(8.3	)%
Midstream & Marketing		4.5			5.5			(1.0	)		(18.2	)%
Corporate & Other		(0.5	)		0.7			(1.2	)		N.M.
Net (loss) income attributable to UGI Corporation	$	(7.2	)	$	3.4		$	(10.6	)		(311.8	)%
N.M. Variance is not meaningful.

AmeriGas Propane:

For the three months ended June 30,	2011			2010			Increase
(Millions of dollars)
Revenues	$	470.8		$	396.6		$	74.2	18.7	%
Total margin (a)	$	170.0		$	160.8		$	9.2	5.7	%
Partnership EBITDA (b)	$	31.1		$	27.2		$	3.9	14.3	%
Operating income	$	6.7		$	5.3		$	1.4	26.4	%
Retail gallons sold (millions)		155.1			150.1			5.0	3.3	%
Degree days — % (warmer) than normal (c)		(1.4	)%		(17.0	)%		—	—

(a)	Total margin represents total revenues less total cost of sales.
(b)	Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 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.

Based upon heating degree-day data, average temperatures in the Partnership’s service territories were 1.4% warmer than normal during the 2011 three-month period compared with temperatures that were 17.0% warmer than normal in the prior-year period. Retail propane gallons sold were higher than in the prior-year period principally reflecting the colder spring weather, improved commercial volumes and acquisitions made since last year partially offset by customer conservation.

- 39 -

UGI CORPORATION AND SUBSIDIARIES

Retail propane revenues increased $57.3 million during the 2011 three-month period reflecting a $46.1 million increase due to higher average retail selling prices and an $11.2 million increase as a result of the higher retail volumes sold. Wholesale propane revenues increased $14.2 million principally reflecting a $7.1 million increase resulting from higher year-over-year wholesale selling prices and a $7.1 million increase on higher volumes sold. Average wholesale propane commodity prices at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 38% higher in the 2011 three-month period compared to such prices in the 2010 three-month period. Revenues from fee income and other ancillary sales and services increased $2.7 million. Total cost of sales increased $65.0 million, to $300.8 million, principally reflecting the effects of the previously mentioned higher 2011 three-month period propane commodity prices and the higher sales.

Total margin increased $9.2 million in the 2011 three-month period primarily due to the higher retail volumes sold and, to a lesser extent, higher average retail unit margins and greater non-propane margin.

Partnership EBITDA in the 2011 three-month period increased $3.9 million reflecting the higher total margin ($9.2 million) and slightly higher other income ($3.2 million) offset in part by greater operating and administrative expenses ($8.4 million). The greater operating and administrative expenses principally reflect higher compensation and benefits costs ($5.1 million), higher vehicle fuel expenses ($2.8 million) and greater self-insured liability and casualty expenses ($1.9 million). Operating income in the 2011 three-month period increased $1.4 million reflecting the $3.9 million increase in Partnership EBITDA partially offset by slightly higher depreciation and amortization expense associated with acquisitions and plant and equipment expenditures made since the 2010 three-month period.

International Propane:

							Increase
For the three months ended June 30,	2011			2010			(Decrease)
(Millions of euros) (a)
Revenues	€	177.5		€	144.5		€	33.0		22.8	%
Total margin (b)	€	63.9		€	61.5		€	2.4		3.9	%
Operating (loss) income	€	(9.2	)	€	1.3		€	(10.5	)	(807.7	)%
Loss before income taxes	€	(14.8	)	€	(4.9	)	€	9.9		202.0	%
(Millions of dollars) (a)
Revenues	$	263.3		$	191.8		$	71.5		37.3	%
Total margin (b)	$	93.4		$	79.9		$	13.5		16.9	%
Operating (loss) income	$	(15.0	)	$	2.9		$	(17.9	)	(617.2	)%
Loss before income taxes	$	(23.1	)	$	(5.0	)	$	18.1		362.0	%
Antargaz retail gallons sold		41.2			49.3			(8.1	)	(16.4	)%
Antargaz degree days — % (warmer) than normal (c)		(47.4	)%		(9.6	)%		—		—
Flaga retail gallons sold		34.5			17.2			17.3		100.6	%
Flaga degree days — % (warmer) than normal (d)		(31.3	)%		(8.0	)%		—		—

(a)	Euro amounts represent amounts for Antargaz and Flaga. U.S. dollar amounts include amounts for Antargaz and Flaga as well as our operations in China and certain non-operating entities associated with our International Propane segment.
(b)	Total margin represents total revenues less total cost of sales.
(c)	Deviation from average heating degree days for the 30-year period 1971-2000 at locations in our French service territory.
(d)	Deviation from average heating degree days for the 30-year period 1971-2000 at locations in Flaga’s central and eastern European service territories.

- 40 -

UGI CORPORATION AND SUBSIDIARIES

Based upon heating degree-day data, temperatures in Antargaz’ service territory were approximately 47.4% warmer than normal during the 2011 three-month period and approximately 42% warmer than the prior-year period. Temperatures in Flaga’s service territory were also significantly warmer than normal and warmer than the prior year. Antargaz’ retail volumes declined principally due to the significantly warmer 2011 three-month period weather and, to a lesser extent, price-induced customer conservation resulting from higher year-over-year LPG product prices. Based upon posted wholesale LPG prices in Northwest Europe, euro-based average wholesale propane costs were approximately 26% higher, and average butane costs were approximately 29% higher, than in the prior-year three-month period. The increase in Flaga’s 2011 three-month period retail gallons sold reflects the effects of acquisitions completed in late Fiscal 2010 and early Fiscal 2011.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. During the 2011 three-month period, the average currency translation rate was $1.45 per euro compared to $1.28 per euro during the prior-year three-month period.

International Propane euro base-currency revenues increased €33.0 million or 22.8% reflecting higher revenues from Flaga (€38.4 million) partially offset by lower revenues from Antargaz (€5.4 million). The decrease in Antargaz revenues principally reflects the effects of (1) the lower retail volumes sold (€16.1 million) and (2) lower wholesale revenues (€1.9 million) partially offset by (3) the effects of higher average retail selling prices (€12.6 million). The higher Flaga revenues reflect the volume effects of the previously mentioned acquisitions and higher average selling prices. Higher 2011 three-month period average selling prices at Antargaz and Flaga reflect the previously mentioned year-over-year increase in wholesale LPG product prices. In U.S. dollars, revenues increased $71.5 million or 37.3% principally reflecting the previously mentioned higher euro base-currency revenues and the effects of the weaker dollar. International Propane’s euro base-currency total cost of sales were €113.6 million in the 2011 three-month period compared to €82.9 million in the prior year, an increase of €30.7 million or 37.0%, principally reflecting the higher LPG product costs and the higher retail sales at Flaga. On a U.S. dollar basis, cost of sales increased to $169.9 million from $111.9 million in the prior-year period, an increase of 51.8%, principally reflecting the previously mentioned higher euro base-currency cost of sales and the effects of the weaker dollar.

International Propane euro-denominated total margin was €2.4 million greater than the prior year as higher margin from Flaga (€10.4 million) principally associated with acquisitions was largely offset by lower total margin from Antargaz (€8.0 million). The decrease in Antargaz’ total margin principally reflects the lower retail LPG volumes sold. U.S dollar total margin was $13.5 million greater principally reflecting the previously mentioned higher euro-based total margin and the effects of the weaker U.S. dollar.

- 41 -

UGI CORPORATION AND SUBSIDIARIES

International Propane euro base-currency operating loss in the 2011 three-month period was principally the result of the lower total margin at Antargaz. The higher euro base-currency total margin at Flaga resulting from acquisitions during the last year was offset by higher Flaga euro base-currency operating and depreciation expenses associated with these acquired businesses. On a U.S. dollar basis, International Propane operating loss was $17.9 million greater than the prior year principally reflecting lower U.S. dollar-based operating income at Antargaz ($13.4 million). The lower euro base-currency and U.S. dollar income before income taxes principally reflects the previously mentioned decreases in base-currency and U.S dollar operating income.

Gas Utility:

							Increase
For the three months ended June 30,	2011			2010			(Decrease)
(Millions of dollars)
Revenues	$	148.1		$	149.1		$	(1.0	)	(0.7	)%
Total margin (a)	$	69.3		$	66.1		$	3.2		4.8	%
Operating income	$	17.2		$	13.8		$	3.4		24.6	%
Income before income taxes	$	7.3		$	3.8		$	3.5		92.1	%
System throughput — billions of cubic feet (“bcf”)		33.4			28.0			5.4		19.3	%
Degree days — % (warmer) than normal (b)		(17.3	)%		(25.7	)%		—		—

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

Temperatures in the Gas Utility service territory in the 2011 three-month period based upon heating degree days were 17.3% warmer than normal and 11.3% colder than the prior-year period. Total distribution system throughput increased 19.3% principally reflecting the effects of higher throughput to certain low-margin interruptible delivery service customers, the impact of colder early spring weather on throughput to core market customers, and the benefits of an improving economy. 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.

Gas Utility revenues decreased $1.0 million during the 2011 three-month period, notwithstanding the greater throughput, principally reflecting a decline in revenues from retail core market customers ($1.9 million). The decrease in retail core market revenues principally reflects lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices ($11.9 million) partially offset by the greater retail core market volumes. 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 $78.8 million in the 2011 three-month period compared with $83.0 million in the prior-year period reflecting the previously mentioned lower average PGC rates.

- 42 -

UGI CORPORATION AND SUBSIDIARIES

Gas Utility total margin increased $3.2 million in the 2011 three-month period. The increase reflects a $4.0 million increase in core market margin resulting from the higher core market throughput.

The increases in Gas Utility operating income and income before income taxes during the 2011 three-month period principally reflects the previously mentioned increase in total margin ($3.2 million).

Electric Utility:

					Increase
For the three months ended June 30,	2011		2010		(Decrease)
(Millions of dollars)
Revenues	$	24.1	$	25.3	$	(1.2	)	(4.7	)%
Total margin (a)	$	8.1	$	8.1	$	—		0.0	%
Operating income	$	2.4	$	2.6	$	(0.2	)	(7.7	)%
Income before income taxes	$	1.7	$	2.2	$	(0.5	)	(22.7	)%
Distribution sales — millions of kilowatt hours (“gwh”)		224.7		218.6		6.1		2.8	%

(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 in each of the three-month periods ended June 30, 2011 and 2010, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the condensed consolidated statements of income.

Electric Utility’s kilowatt-hour sales in the 2011 three-month period were 2.8% higher than in the prior-year three-month period on heating degree day weather that was 17% colder. Notwithstanding the effects on heating-related sales from the colder weather, Electric Utility revenues were less than the prior year principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity generation portion of their service. Electric Utility cost of sales declined to $14.6 million in the 2011 three-month period compared to $15.8 million in the 2010 three-month period principally reflecting the effects of the previously mentioned electricity generation supplier customer switching.

Electric Utility total margin was $8.1 million in the 2011 three-month period, equal to the margin recorded in the prior-year period.

Electric Utility 2011 three-month period operating income and income before income taxes declined $0.2 million and $0.5 million, respectively, principally reflecting slightly higher operating expenses and, with respect to income before income taxes, higher allocated interest charges.

Midstream & Marketing:

For the three months ended June 30,	2011		2010		Increase
(Millions of dollars)
Revenues	$	217.1	$	198.6	$	18.5	9.3	%
Total margin (a)	$	24.0	$	21.3	$	2.7	12.7	%
Operating income	$	8.4	$	6.9	$	1.5	21.7	%
Income before income taxes	$	7.8	$	6.9	$	0.9	13.0	%

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

- 43 -

UGI CORPORATION AND SUBSIDIARIES

Midstream & Marketing total revenues increased $18.5 million in the 2011 three-month period principally reflecting greater total revenues from natural gas marketing activities ($14.8 million) and retail power sales revenues ($9.8 million) on higher volumes sold. These increases in revenues were partially offset by the absence of revenues from Atlantic Energy’s import and transshipment facility ($10.6 million). As previously reported, Atlantic Energy was sold in July 2010.

The $2.7 million increase in Midstream & Marketing’s total margin principally reflects greater natural gas marketing total margin ($3.7 million) and incremental margin from storage services which began April 1, 2011 concurrent with the transfer of CPG Gas’ storage facilities to Midstream & Marketing. These increases were partially offset by lower margin from electric generation assets ($2.1 million) and the absence of margin in the 2011 three-month period from Atlantic Energy ($0.8 million). The decrease in electric generation total margin principally reflects absence of margin from UGID’s Hunlock Creek coal-fired generating station, which ceased operations in May 2010 to transition to a natural gas-fired generating station, and lower spot prices for electricity.

Midstream & Marketing’s operating income in the 2011 three-month period was $1.5 million greater than last year principally reflecting the previously mentioned increase in total margin ($2.7 million) partially offset by slightly higher operating and administrative expenses. The decline in income before income taxes reflects greater interest expense ($0.6 million) principally fees and deferred debt costs associated with Energy Services new credit facility (see Notes 3 and 6 to condensed consolidated financial statements).

Interest Expense and Income Taxes. Our consolidated interest expense was slightly higher in the 2011 three-month period principally reflecting higher International Propane and Midstream & Marketing interest expense partially offset by lower interest expense on Partnership long-term debt. Our estimated effective tax rate for the three months ended June 2011 was higher than the estimated rate for the 2010 three-month period as the prior-year three-month period included the effects of a greater change in the estimated annual effective tax rate on year-to-date pre-tax income.

2011 nine-month period compared to the 2010 nine-month period

Net income (loss) attributable to UGI Corporation by Business Unit:

	Nine Months Ended												Variance - Favorable
	June 30,												(Unfavorable)
				% of						% of
(Millions of dollars)	2011			Total			2010			Total			Amount			%
AmeriGas Propane (a)	$	50.6			19.8	%	$	56.5			21.8	%	$	(5.9	)		(10.4	)%
International Propane (b)		53.7			21.0	%		70.5			27.2	%		(16.8	)		(23.8	)%
Gas Utility		102.1			40.0	%		83.5			32.3	%		18.6			22.3	%
Electric Utility		4.5			1.8	%		5.7			2.2	%		(1.2	)		(21.1	)%
Midstream & Marketing		48.1			18.8	%		46.1			17.8	%		2.0			4.3	%
Corporate & Other		(3.7	)		(1.4	)%		(3.4	)		(1.3	)%		(0.3	)		N.M.
Net income attributable to UGI Corporation	$	255.3			100.0	%	$	258.9			100.0	%	$	(3.6	)		(1.4	)%

- 44 -

UGI CORPORATION AND SUBSIDIARIES

N.M. – Variance is not meaningful.
(a)	2011 nine-month period net income from AmeriGas Propane includes a $5.2 million loss associated with the early extinguishment of debt. 2010 nine-month period net income from AmeriGas Propane includes $3.3 million of loss associated with the discontinuance of Partnership interest rate hedges.
(b)	2011 nine-month period net income from International Propane includes $9.4 million of income from a nontaxable reserve reversal at Antargaz associated with the French Competition Authority Matter (see Note 10 to condensed consolidated financial statements).

AmeriGas Propane:

							Increase
For the nine months ended June 30,	2011			2010			(Decrease)
(Millions of dollars)
Revenues	$	2,077.8		$	1,939.3		$	138.5		7.1	%
Total margin (a)	$	776.9		$	774.2		$	2.7		0.3	%
Partnership EBITDA (b)	$	301.9		$	323.7		$	(21.8	)	(6.7	)%
Operating income (b)	$	252.9		$	261.2		$	(8.3	)	(3.2	)%
Retail gallons sold (millions)		727.8			746.7			(18.9	)	(2.5	)%
Degree days — % (warmer) than normal (c)		(0.1	)%		(1.6	)%		—		—

(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 for the nine months ended June 30, 2011 includes a pre-tax loss of $18.8 million associated with the extinguishment of debt. Partnership EBITDA and operating income for the nine months ended June 30, 2010 includes a pre-tax loss of $12.2 million associated with the discontinuance of interest rate hedges.
(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 near normal during the 2011 nine-month period compared with weather that was approximately 1.6% warmer than normal in the prior-year period. However, temperatures in the early fall of the 2011 period were significantly warmer than normal and we experienced an early end to the heating season weather in our southern regions. Retail propane gallons sold declined principally due to the effects of these weather patterns, customer conservation and the impact on AmeriGas Propane’s prior-year volumes of a strong crop-drying season partially offset by volumes acquired through acquisitions.

Retail propane revenues increased $115.3 million during the 2011 nine-month period reflecting higher average retail sales prices ($157.8 million) partially offset by lower retail volumes sold ($42.5 million). Wholesale propane revenues decreased $10.2 million principally reflecting higher wholesale selling prices ($19.5 million) partially offset by lower wholesale volumes sold ($9.3 million). Average wholesale propane prices at Mont Belvieu, Texas, a major supply location in the U.S., were approximately 21% higher during the 2011 nine-month period compared with average wholesale propane prices during the 2010 nine-month period. Revenues from fee income and ancillary sales and services increased $13.1 million in the 2011 nine-month period. Total cost of sales increased $135.8 million, to $1,300.9 million, principally reflecting the higher 2011 wholesale propane product costs.

- 45 -

UGI CORPORATION AND SUBSIDIARIES

Total margin was $2.7 million higher in the 2011 nine-month period as non-propane margin was offset in part by lower total retail margin ($5.3 million). The lower total retail margin reflects the effects of the lower retail volumes sold ($17.4 million) partially offset by the effects of slightly higher average retail unit margins ($12.1 million).

The $21.8 million decrease in Partnership EBITDA during the 2011 nine-month period includes (1) a loss on the extinguishment of Partnership Senior Notes ($18.8 million) and (2) modestly higher operating and administrative expenses ($22.4 million). The higher operating and administrative costs principally includes greater compensation and benefits expenses ($11.7 million) and an increase in vehicle fuel expenses ($5.9 million). The negative effects of these items on the change in Partnership EBITDA were partially offset by (1) the absence of a $12.2 million loss recorded in the prior-year nine-month period resulting from the discontinuance of interest rate hedges; (2) higher other income ($4.5 million); and (3) the previously mentioned greater total margin.

Operating income (which excludes the loss on extinguishment of debt) decreased $8.3 million in the 2011 nine-month period principally reflecting (1) higher combined operating, administrative and depreciation and amortization expenses ($27.7 million) partially offset by the absence of the loss on interest rate hedges recorded in the prior year ($12.2 million) and the previously mentioned higher other income ($4.5 million) and total margin ($2.7 million).

International Propane:

							Increase
For the nine months ended June 30,	2011			2010			(Decrease)
(Millions of euros) (a)
Revenues	€	875.7		€	631.7		€	244.0		38.6	%
Total margin (b)	€	306.4		€	289.5		€	16.9		5.8	%
Operating income	€	78.1	(c)	€	89.4		€	(11.3	)	(12.6	)%
Income before income taxes	€	62.9	(c)	€	74.1		€	(11.2	)	(15.1	)%
(Millions of dollars) (a)
Revenues	$	1,222.1		$	885.1		$	337.0		38.1	%
Total margin (b)	$	424.3		$	403.9		$	20.4		5.1	%
Operating income	$	100.8	(c)	$	127.6		$	(26.8	)	(21.0	)%
Income before income taxes	$	79.4	(c)	$	106.3		$	(26.9	)	(25.3	)%
Antargaz retail gallons sold		228.4			237.9			(9.5	)	(4.0	)%
Degree days — % (warmer) than normal (d)		(7.2	)%		(0.1	)%		—		—
Flaga retail gallons sold		120.4			54.0			66.4		123.0	%
Flaga degree days — % (warmer) than normal (e)		(2.3	)%		(0.9	)%		—		—

(a)	Euro amounts represent amounts for Antargaz and Flaga. U.S. dollar amounts include amounts for Antargaz and Flaga as well as our operations in China and certain non-operating entities associated with our International Propane segment.
(b)	Total margin represents total revenues less total cost of sales.
(c)	Includes €7.1 million ($9.4 million) from a nontaxable reserve reversal at Antargaz associated with the French Competition Authority Matter (see Note 10 to condensed consolidated financial statements).
(d)	Deviation from average heating degree days for the 30-year period 1971-2000 at locations in our French service territory.
(e)	Deviation from average heating degree days for the 30-year period 1971-2000 at locations in Flaga’s central and eastern European service territories.

- 46 -

UGI CORPORATION AND SUBSIDIARIES

Based upon heating degree-day data, temperatures in Antargaz’ service territory were approximately 7.2% warmer than normal and the prior year. Temperatures in Flaga’s service territory were also slightly warmer than normal and the prior year. Antargaz’ retail volumes declined principally due to the warmer 2011 nine-month period weather and, to a lesser extent, price-induced customer conservation resulting from higher year-over-year LPG product prices. LPG wholesale product prices rose rapidly principally during the first quarter of the 2011 nine-month period compared with more gradual price increases during the prior-year nine-month period. Based upon posted wholesale LPG prices in Northwest Europe, euro-based average propane costs were approximately 22% higher and average butane costs were approximately 20% higher than in the prior-year nine-month period. The significant increase in Flaga’s 2011 nine-month period retail gallons sold reflects the effects of acquisitions made in late Fiscal 2010 and early Fiscal 2011.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. The dollar was generally stronger during the 2011 heating season months and weaker during the third quarter of Fiscal 2011. The effects of these differences in exchange rates reduced International Propane net income as compared to last year by approximately 4 cents per diluted share which includes the effects of gains and losses on forward currency contracts used to hedge purchases of LPG.

International Propane euro base-currency revenues increased €244.0 million or 38.6% principally reflecting higher revenues from Antargaz (€105.8 million) and Flaga (€138.2 million). The increase in Antargaz revenues principally reflects the effects of (1) higher average retail selling prices (€76.6 million) and (2) higher wholesale revenues (€49.1 million). The higher Flaga revenues reflect the effects of late Fiscal 2010 and early Fiscal 2011 acquisitions and higher average retail prices. The higher average retail prices reflect the previously mentioned year-over-year increase in wholesale LPG product costs. In U.S. dollars, revenues increased $337.0 million or 38.1% principally reflecting the previously mentioned higher euro base-currency revenues. International Propane’s euro base-currency total cost of sales increased to €569.3 million in the 2011 nine-month period from €342.2 million in the prior year principally reflecting (1) the higher LPG product costs and (2) the greater Flaga retail volumes sold and Antargaz wholesale volumes sold. On a U.S. dollar basis, cost of sales increased to $797.8 million from $481.2 million in the prior-year period principally reflecting the higher euro base-currency LPG commodity costs and the previously mentioned higher Flaga retail and Antargaz wholesale volumes sold.

International Propane euro-denominated total margin increased €16.9 million or 5.8% in the 2011 nine-month period principally reflecting higher total margin from Flaga (€31.9 million) partially offset by lower total margin from Antargaz (€15.0 million). The increase in Flaga’s total margin reflects the greater retail gallons sold. The decrease in Antargaz’ total margin principally reflects the lower total volumes and the effects of rapidly rising LPG product costs on unit margins primarily during the first quarter of Fiscal 2011. U.S dollar total margin increased $20.4 million or 5.1% principally reflecting the previously mentioned higher euro base-currency total margin partially offset by the effects of the stronger dollar.

- 47 -

UGI CORPORATION AND SUBSIDIARIES

International Propane euro base-currency operating income decreased €11.3 million principally reflecting the previously mentioned lower total margin at Antargaz (€15.0 million) and lower operating income at Flaga (€2.5 million) offset by the reversal of the nontaxable reserve at Antargaz associated with the French Competition Authority Matter (€7.1 million). At Flaga, the higher euro base-currency total margin (€31.9 million) was offset by higher operating, administrative and depreciation expenses (€33.4 million) associated with the acquired businesses. On a U.S. dollar basis, operating income decreased $26.8 million, reflecting the decline in euro base-currency operating income and the combined effects of the stronger dollar during the 2011 nine-month period heating-season and the weaker dollar during the 2011 third fiscal quarter. The decreases in euro-based and U.S. dollar-based income before income taxes largely reflect the previously mentioned lower operating income.

Gas Utility:

							Increase
For the nine months ended June 30,	2011			2010			(Decrease)
(Millions of dollars)
Revenues	$	921.7		$	922.3		$	(0.6	)	(0.1	)%
Total margin (a)	$	359.4		$	338.1		$	21.3		6.3	%
Operating income	$	193.2		$	168.6		$	24.6		14.6	%
Income before income taxes	$	163.0		$	138.1		$	24.9		18.0	%
System throughput - billions of cubic feet (“bcf”)		143.5			124.9			18.6		14.9	%
Degree days — % colder (warmer) than normal (b)		4.2	%		(3.9	)%		—		—

(a)	Total margin represents total revenues less total cost of sales.
(b)	Percentage represents deviation from average heating degree days for the 15-year period 1995-2009 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

Temperatures in the Gas Utility service territory based upon heating degree days were 4.2% colder than normal in the 2011 nine-month period compared with temperatures that were 3.9% warmer than normal in the prior-year period. Total distribution system throughput increased 18.6 bcf reflecting higher throughput to certain low-margin interruptible delivery service customers, the effects of the colder weather on core market customers and the benefits of an improving economy.

Gas Utility revenues were about equal to the prior-year period principally reflecting a decline in revenues from core market customers ($34.5 million) partially offset by a $33.1 million increase in revenues from low-margin off-system sales. The decrease in core market revenues principally resulted from lower average retail core market PGC rates reflecting lower natural gas prices ($80.2 million) offset by the effects of the higher throughput. Gas Utility’s cost of gas was $562.3 million in the 2011 nine-month period compared with $584.2 million in the prior-year period principally reflecting the lower average PGC rates offset in part by an increase in retail core-market sales.

- 48 -

UGI CORPORATION AND SUBSIDIARIES

Gas Utility total margin increased $21.3 million in the 2011 nine-month period. The increase principally reflects a $20.1 million increase in core market margin reflecting the increase in core market throughput.

Gas Utility operating income and income before income taxes during the 2011 nine-month period increased $24.6 million and $24.9 million, respectively, principally reflecting the previously mentioned increase in total margin ($21.3 million) and higher other income ($2.6 million).

Electric Utility:

					Increase
For the nine months ended June 30,	2011		2010		(Decrease)
(Millions of dollars)
Revenues	$	84.7	$	90.9	$	(6.2	)	(6.8	)%
Total margin (a)	$	26.5	$	27.9	$	(1.4	)	(5.0	)%
Operating income	$	9.0	$	11.1	$	(2.1	)	(18.9	)%
Income before income taxes	$	7.2	$	9.8	$	(2.6	)	(26.5	)%
Distribution sales — millions of kilowatt hours (“gwh”)		754.2		723.8		30.4		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 $4.8 million and $5.0 million during the nine-month periods ended June 30, 2011 and 2010, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Condensed Consolidated Statements of Income.

Electric Utility’s kilowatt-hour sales in the 2011 nine-month period were 4.2% higher than in the prior-year nine-month period on heating degree day weather that was 8.1% colder. Notwithstanding the effects of the colder weather, Electric Utility revenues decreased $6.2 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity generation portion of their service and, to a much lesser extent, lower average default service (“DS”) rates compared to the provider of last resort (“POLR”) rates that were in effect through December 31, 2009. Under DS rates, Electric Utility is no longer subject to electricity price and congestion cost risk as it is permitted to pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in excess of actual costs of electricity as was possible under POLR rates. Electric Utility cost of sales declined to $53.4 million in the 2011 nine-month period compared to $58.0 million in the 2010 nine-month period principally reflecting the effects of the previously mentioned electricity generation supplier customer switching.

Electric Utility total margin declined $1.4 million in the 2011 nine-month period, notwithstanding the greater sales, principally reflecting the absence of margin from electric generation service beginning January 1, 2010.

Electric Utility 2011 nine-month period operating income and income before income taxes declined $2.1 million and $2.6 million, respectively, principally reflecting the previously mentioned lower total margin, higher operating and maintenance expenses and, with respect to income before income taxes, higher allocated interest expense.

- 49 -

UGI CORPORATION AND SUBSIDIARIES

Midstream & Marketing:

					Increase
For the nine months ended June 30,	2011		2010		(Decrease)
(Millions of dollars)
Revenues	$	857.0	$	949.5	$	(92.5	)	(9.7	)%
Total margin (a)	$	118.4	$	118.6	$	(0.2	)	(0.2	)%
Operating income	$	76.7	$	75.4	$	1.3		1.7	%
Income before income taxes	$	74.7	$	75.4	$	(0.7	)	(0.9	)%

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

Midstream & Marketing total revenues decreased $92.5 million in the 2011 nine-month period principally reflecting (1) the absence of revenues from Atlantic Energy’s import and transshipment facility ($87.6 million); (2) lower total revenues from natural gas marketing activities ($41.7) reflecting lower natural gas prices; and, to a much lesser extent, (3) the absence of revenues from the Hunlock Creek electric generating station which ceased operations in May 2010 to transition to a natural gas-fired generating station. These decreases in revenues were partially offset principally by an increase in retail power sales revenues ($30.7 million).

Total margin from Midstream & Marketing was about equal to the prior-year nine month period as lower electric generation total margin ($9.1 million) and the absence of margin from Atlantic Energy ($8.0 million) were principally offset by higher winter peaking margin ($4.8 million), greater natural gas and retail power marketing margin ($5.4 million), and greater income from capacity management and storage income ($6.0 million). The decrease in electric generation total margin principally reflects lower spot prices for electricity and the absence of margin from UGID’s Hunlock Creek coal-fired generating station which ceased operations in May 2010 to transition to a natural gas-fired generating station.

The increase in Midstream & Marketing’s operating income principally reflects lower current-year period operating and depreciation expenses associated with the Hunlock Creek coal-fired generating station and Atlantic Energy. The decline in income before income taxes reflects the increase in operating income more than offset by greater interest expense ($2.0 million) principally the result of the change in accounting for Energy Services’ Receivables Facility and fees and charges associated with Energy Services’ new credit agreement (see Notes 3 and 6 to condensed consolidated financial statements).

Interest Expense and Income Taxes. Our consolidated interest expense was slightly higher in the 2011 nine-month period principally reflecting higher Midstream & Marketing interest expense, due in part to the change in accounting for the Energy Services’ Receivables Facility, and higher Antargaz long-term debt interest expense partially offset by lower interest expense on Partnership long-term debt. Our annual estimated effective tax rate was lower in the 2011 nine-month period reflecting the effects of (1) the reversal of the $9.4 million nontaxable reserve associated with the French Competition Authority Matter at Antargaz; (2) the impact of federal tax credits associated with anticipated solar energy projects; and (3) a reduction in UGI Utilities’ income taxes reflecting the regulatory effects of greater state tax depreciation (as further described below under “Financial Condition & Liquidity”).

- 50 -

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 Midstream & Marketing, also from a receivables purchase facility. Long-term cash needs are generally met through issuance of long-term debt or equity securities.

Our cash and cash equivalents, excluding cash in commodity futures brokerage accounts restricted from withdrawal, totaled $317.8 million at June 30, 2011 compared with $260.7 million at September 30, 2010. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at June 30, 2011 and September 30, 2010, UGI had $105.3 million and $111.6 million, respectively, of cash and cash equivalents.

The Company’s debt outstanding at June 30, 2011 totaled $2,284.1 million (including current maturities of long-term debt of $38.5 million and bank loan borrowings of $206.1 million) compared to debt outstanding at September 30, 2010 of $2,206.2 million (including current maturities of long-term debt of $573.6 million and bank loan borrowings of $200.4 million). Total debt outstanding at June 30, 2011 consists of (1) $1,010.1 million of Partnership debt; (2) $621.1 million (€428.3 million) of International Propane debt; (3) $640 million of UGI Utilities’ debt; and (4) $12.9 million of other debt. There was no debt outstanding associated with Midstream & Marketing at June 30, 2011. Long-term debt maturing in the next twelve months principally comprises $31.5 million (€21.7 million) of Flaga term loans.

AmeriGas Partners’ total debt at June 30, 2011 includes $820 million of AmeriGas Partners’ Senior Notes, $176 million of AmeriGas OLP bank loan borrowings and $14.1 million of other long-term debt. On January 20, 2011, AmeriGas Partners issued $470 million principal amount of 6.50% Senior Notes due 2021. The proceeds from the issuance of the 6.50% Senior Notes were used to repay AmeriGas Partners’ $415 million 7.25% Senior Notes due May 15, 2015 pursuant to a January 5, 2011 tender offer and subsequent redemption. The 6.50% Senior Notes due 2021 rank pari passu with AmeriGas Partners’ outstanding senior debt. In addition, in February 2011, AmeriGas Partners redeemed $14.6 million principal amount of its 8.875% Senior Notes due May 2011. The Partnership incurred a loss on extinguishment of debt associated with refinancings of $18.8 million, which reduced the net income attributable to UGI Corporation by approximately $5.2 million. In July 2011, the Partnership announced its offer to purchase $350 million of its 7 1/8% Senior Notes due 2016 (see “Subsequent Event – AmeriGas Refinancing” below).

International Propane’s total debt at June 30, 2011 includes $551.1 million (€380 million) outstanding under Antargaz’ Senior Facilities term loan and a combined $36.5 million (€25.2 million) outstanding under Flaga’s two term loans. Total International Propane debt outstanding at June 30, 2011 also includes combined borrowings of $30.1 million (€20.8 million) outstanding under Flaga’s working capital facilities and $3.4 million (€2.3 million) of other long-term debt.

- 51 -

UGI CORPORATION AND SUBSIDIARIES

UGI Utilities’ total debt at June 30, 2011 includes $383 million of Senior Notes and $257 million of Medium-Term Notes. There were no amounts outstanding under UGI Utilities’ Revolving Credit Agreement at June 30, 2011.

AmeriGas Partners. In order to meet its short-term cash needs, AmeriGas OLP has a $325 million unsecured credit agreement (“2011 AmeriGas Credit Agreement”) which expires on October 15, 2015. Concurrently with entering into the 2011 AmeriGas Credit Agreement on June 21, 2011, AmeriGas OLP terminated its then-existing $200 million revolving credit agreement dated as of November 6, 2006 and its $75 million credit agreement dated as of April 17, 2009.

At June 30, 2011, there were $176 million of borrowings outstanding under the 2011 AmeriGas Credit Agreement. Borrowings under AmeriGas OLP credit agreements are classified as bank loans. Issued and outstanding letters of credit under AmeriGas OLP credit agreements, which reduce the amount available for borrowings, totaled $35.7 million at both June 30, 2011 and 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, 2011 were $161.8 million and $235 million, respectively. The average daily and peak bank loan borrowings outstanding under AmeriGas OLP credit agreements during the nine months ended June 30, 2010 were $26.6 million and $126 million, respectively. At June 30, 2011, AmeriGas OLP’s available borrowing capacity under the 2011 AmeriGas Credit Agreement was $113.3 million.

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

International Propane. In March 2011, Antargaz entered into a new five-year variable rate term loan agreement with a consortium of banks (“2011 Senior Facilities Agreement”). The proceeds from the new term loan were used on March 16, 2011 to repay Antargaz’ existing Senior Facilities Agreement borrowings.

The 2011 Senior Facilities Agreement consists of (1) a €380 million variable-rate term loan and (2) a €40 million revolving credit facility. Scheduled maturities under the term loan are €38 million due May 2014, €34.2 million due May 2015, and €307.8 million due March 2016. Antargaz’ term loan and revolving credit facility bear interest at one-, two-, three- or six-month euribor, plus a margin, as defined by the 2011 Senior Facilities Agreement. The margin on the term loan and revolving credit facility borrowings (which ranges from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the 2011 Senior Facilities Agreement. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of approximately 3.71% through the date of the term loan’s final maturity in March 2016. At June 30, 2011, the effective interest rate on Antargaz’ term loan was 4.66%.

- 52 -

UGI CORPORATION AND SUBSIDIARIES

Antargaz’ management believes that it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2011 with cash generated from operations and borrowings under its revolving credit facility.

Flaga GmbH currently has four working capital facilities providing for borrowings of up to €36 million. Flaga GmbH has two multi-currency working capital facilities that provide for borrowings and issuances of guarantees totaling €24 million. Flaga GmbH also has two euro-denominated working capital facilities that provide for borrowings and issuances of guarantees totaling €12 million. Total borrowings under these facilities were $26.8 million (€18.5 million) at June 30, 2011. Issued and outstanding guarantees, which reduce available borrowings under the working capital facilities, totaled $17.3 million (€11.9 million) at June 30, 2011. Amounts outstanding under the working capital facilities are classified as bank loans. During the 2011 nine-month period, average and peak borrowings under the working capital facilities totaled €17.6 million and €23.4 million, respectively. During the 2010 nine-month period, average and peak borrowings under the working capital facilities totaled €11.7 million and €16.5 million, respectively. During the three months ended June 30, 2011, Flaga extended the expiration of its €24 million and €12 million working capital facilities to September 2011 and March 2012, respectively.

Scheduled repayments under Flaga GmbH’s two term loans during the remainder of Fiscal 2011 total €21.0 million ($30.4 million). Flaga expects to refinance this debt on a long-term basis during the fourth quarter of Fiscal 2011 and to refinance its multi-currency working capital facilities prior to their expiration in September 2011.

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

UGI Utilities. On May 25, 2011, UGI Utilities entered into an unsecured, revolving credit agreement (the “UGI Utilities 2011 Credit Agreement”) with a group of banks providing for borrowings up to $300 million (including a $100 million sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2011 Credit Agreement, UGI Utilities terminated its then-existing $350 million revolving credit agreement dated as of August 11, 2006. The UGI Utilities 2011 Credit Agreement is currently scheduled to expire in May 2012, but may be extended by UGI Utilities to October 2015 if on or before May 23, 2012, the Company satisfies certain requirements relating to approval by the PUC. The Company is in the process of seeking such regulatory approval. At June 30, 2011, there were no amounts outstanding under the UGI Utilities 2011 Credit Agreement. Borrowings under the UGI Utilities 2011 Credit Agreement are classified as bank loans. During the 2011 and 2010 nine-month periods, average daily bank loan borrowings were $23.5 million and $93.1 million, respectively, and peak bank loan borrowings totaled $90 million and $203 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is greatest.

- 53 -

UGI CORPORATION AND SUBSIDIARIES

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

Midstream & Marketing. Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $170 million (including a $50 million sublimit for letters of credit) which expires in August 2013. There were no borrowings under this facility during the nine months ended June 30, 2011.

Energy Services also has a $200 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper. The Receivables Facility expires in April 2012, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility’s back-up purchasers. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts 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.

During the nine months ended June 30, 2011 and 2010, Energy Services transferred trade receivables totaling $923.5 million and $933.3 million, respectively, to ESFC. During the nine months ended June 30, 2011 and 2010, ESFC sold an aggregate $68.0 million and $233.6 million, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At June 30, 2011, the balance of ESFC receivables was $50.9 million and there were no amounts sold to the commercial paper conduit. At June 30, 2010, the outstanding balance of ESFC receivables was $61.8 million and there were no amounts sold to the commercial paper conduit. During the nine months ended June 30, 2011 and 2010, peak amounts sold under the Receivables Facility were $31.7 million and $45.7 million, respectively, and average daily amounts sold were $1.4 million and $11.1 million, respectively.

Based upon cash expected to be generated from operations, borrowings available under the Energy Services Credit Agreement and Receivables Facility, and capital contributions from UGI, Midstream & Marketing’s management believes that Midstream & Marketing will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2011.

Impact of Tax Depreciation Legislation. In 2010, U.S. federal tax legislation was enacted that allows taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010 through the end of calendar 2011, when such property is placed in service before 2012. In accordance with existing Pennsylvania tax statutes, Pennsylvania taxpayers will also be permitted to fully deduct such qualifying capital expenditures for Pennsylvania state corporate net income tax purposes. In accordance with Pennsylvania utility ratemaking practice, UGI Utilities’ Fiscal 2011 effective tax rate reflects the beneficial effects of this greater state tax depreciation. The additional state and federal tax depreciation deductions described above will reduce federal and state income taxes otherwise payable and increase UGI Utilities deferred income tax liabilities.

- 54 -

UGI CORPORATION AND SUBSIDIARIES

Dividends and Distributions. On April 28, 2011, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.26 per common share or $1.04 per common share on an annual basis. This dividend reflects a 4% increase from the previous quarterly dividend rate of $0.25. The new quarterly dividend rate was effective with the dividend payable on July 1, 2011 to shareholders of record on June 15, 2011. On April 27, 2011, the General Partner’s Board of Directors approved a quarterly distribution of $0.74 per Common Unit equal to an annual rate of $2.96 per Common Unit. This distribution reflects an approximate 5% increase from the previous quarterly rate of $0.705 per Common Unit. The new quarterly rate was effective with the distribution payable on May 18, 2011 to unitholders of record on May 10, 2011. On July 26, 2011, UGI’s Board of Directors approved a quarterly dividend of $0.26 per common share payable October 1, 2011 to shareholders of record on September 15, 2011. On July 25, 2011, the General Partner’s Board of Directors approved a quarterly distribution of $0.74 per Common Unit payable August 18, 2011 to unitholders of record on August 10, 2011.

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.

Operating Activities. Cash provided by operating activities was $467.2 million in the 2011 nine-month period compared to $516.7 million in the 2010 nine-month period. Cash flow from operating activities before changes in operating working capital was $621.3 million in the 2011 nine-month period compared to $656.6 million in the prior-year nine-month period. Cash required to fund changes in operating working capital totaled $154.1 million in the 2011 nine-month period compared to $139.9 million in the prior-year nine-month period. The higher cash required to fund changes in operating working capital reflects, among other things, the effects of the timing of payments and increased purchase price per gallon of LPG on accounts payable.

Investing Activities. Cash used in investing activities was $272.0 million in the 2011 nine-month period compared with $284.8 million of cash used in the prior-year period. Cash used for acquisitions of businesses in the 2011 nine-month period increased to $49.6 million compared with $25.4 million used in the prior-year period reflecting payments associated with an acquisition at Flaga and greater Partnership business acquisition expenditures. Changes in restricted cash balances in margin accounts provided $24.6 million of cash in the 2011 nine-month period compared with $15.9 million of such cash used in the prior-year period reflecting the effects of lower natural gas prices.

- 55 -

UGI CORPORATION AND SUBSIDIARIES

Financing Activities. Cash used in financing activities was $138.6 million in the 2011 nine-month period compared with $251.8 million in the prior-year period. As previously mentioned, during the 2011 nine-month period AmeriGas Propane redeemed its $415 million 7.25% AmeriGas Partners Senior Notes due 2015 and $14.6 million 8.875% Senior Notes due 2011 with proceeds from the issuance of $470 million of 6.50% AmeriGas Partners Senior Notes due 2021. In addition, Antargaz repaid its €380 million Senior Facilities Agreement with the proceeds from its new 2011 €380 million Senior Facilities Agreement due March 2016. As a result of the previously mentioned change in accounting for the Energy Services Receivables Facility effective October 1, 2010, net cash repayments of $12.1 million during the 2011 nine-month period are reflected in financing activities cash flows.

CPG Base Rate Filing

On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5 million annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). CPG requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the effective date for the rate increase to allow for investigation and public hearing. On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. Under the terms of the Joint Petition, CPG will be permitted to increase distribution rates by $8.0 million in additional base rate revenue as well as $0.9 million in revenues per year for CPG’s Energy and Efficiency Conservation Program. On July 19, 2011, a recommended decision was issued by the two assigned administrative law judges (“ALJs”) who recommended that the PUC approve the Joint Petition without modification. The recommended decision of the ALJs is subject to PUC approval. It is anticipated that this process will conclude by the end of Fiscal 2011.

Subsequent Event – AmeriGas Refinancing

On July 27, 2011, AmeriGas Partners announced an offer to purchase for cash any and all of its $350 million aggregate principal amount of outstanding 7 1/8% Senior Notes (“the 2016 Notes”) due May 2016 (the “Tender Offer”), subject to receipt of the proceeds of the issuance of $450 million of 6.25% Senior Notes due 2019 (the “6.25% Notes”). The 6.25% Notes are expected to be issued on August 10, 2011. The proceeds from the offering will be used to finance the Tender Offer and for general corporate purposes, including to repay borrowings outstanding under the AmeriGas 2011 Credit Agreement. The Partnership intends to redeem any 2016 Notes that are not tendered in the Tender Offer. The Partnership expects to record a loss of approximately $20.0 million associated with these transactions during the fourth quarter of Fiscal 2011 which is expected to reduce net income attributable to UGI Corporation by approximately $6.0 million.

- 56 -

UGI CORPORATION AND SUBSIDIARIES

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 as further described below. Antargaz has used over-the-counter derivative commodity instruments and may from time-to-time enter into other derivative contracts, similar to those used by the Partnership. Flaga has used and may use derivative commodity instruments to reduce market risk associated with a portion of its LPG purchases. Over-the-counter derivative commodity instruments used to hedge forecasted purchases of propane are generally settled at expiration of the contract.

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

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

- 57 -

UGI CORPORATION AND SUBSIDIARIES

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, 2011 were not material.

Midstream & Marketing purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. In addition, beginning April 1, 2011, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Although Midstream & Marketing’s FTRs and NYMEX futures contracts associated with the purchase and later anticipated sale of natural gas and propane are generally effective as economic hedges, they do not currently qualify for hedge accounting treatment

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

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

The fair value of unsettled commodity price risk sensitive derivative instruments held at June 30, 2011 (excluding those Gas Utility and Electric Utility commodity derivative instruments which are refundable to or recoverable from customers) was a liability of $2.2 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 such fair value of $35.3 million at June 30, 2011.

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.

- 58 -

UGI CORPORATION AND SUBSIDIARIES

Our variable-rate debt at June 30, 2011 includes borrowings under AmeriGas OLP’s credit agreement, Antargaz’ term loan and a substantial portion of 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, 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, 2011 combined borrowings outstanding under these variable-rate debt agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled $206.1 million. Flaga expects to refinance its maturing term loans on a long-term basis prior to their maturity dates in August and September 2011.

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, 2011 was a gain of $1.4 million. A hypothetical 10% adverse change in the three-month LIBOR and the three-month euribor would result in a decrease in fair value of $10.9 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 currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Realized gains or losses on net investment hedges remain in accumulated other comprehensive income until such foreign operations are liquidated. At June 30, 2011, the fair value of unsettled net investment hedges was a loss of $0.3 million. With respect to our net investments in our International Propane operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value by approximately $77.0 million, which amount would be reflected in other comprehensive income.

In addition, in order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar denominated LPG product purchases during the months of October through March through the use of forward foreign exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% — 30% of estimated dollar-denominated purchases to occur during the heating-season months of October to March.

The fair value of unsettled foreign currency exchange rate risk sensitive derivative instruments held at June 30, 2011 was a liability of $6.1 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 $16.8 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.

- 59 -

UGI CORPORATION AND SUBSIDIARIES

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. Declines in natural gas, LPG and electricity product costs can require our business units to post collateral with counterparties or make margin deposits to brokerage accounts. At June 30, 2011 and 2010, restricted cash in brokerage accounts totaled $10.2 million and $22.9 million, respectively.

- 60 -

UGI CORPORATION AND SUBSIDIARIES

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

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

(b)	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.

- 61 -

UGI CORPORATION AND SUBSIDIARIES

PART II OTHER INFORMATION

ITEM 1 LEGAL PROCEEDINGS

BP America Production Company v. Amerigas Propane, L.P.
On July 15, 2011, BP America Production Company (“BP”) filed a complaint against AmeriGas Propane, L.P. in the District Court of Denver County, Colorado, alleging, among other things, breach of contract and breach of the covenant of good faith and fair dealing relating to amounts billed for certain goods and services provided to BP since 2005 (the “Services”). The Services relate to the installation of propane-fueled equipment and appliances, and the supply of propane, to approximately 400 residential customers at the request of and for the account of BP. The complaint seeks an unspecified amount of direct, indirect, consequential, special and compensatory damages, including attorneys’ fees, costs and interest and other appropriate relief. It also seeks an accounting to determine the amount of the alleged overcharges related to the Services. We recently commenced an investigation into these allegations.

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, 2010, 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.

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):

Exhibit
No.		Exhibit	Registrant	Filing	Exhibit
	10.1	Credit Agreement, dated as of May 25, 2011 among UGI Utilities, Inc., as borrower, and PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and RBS Citizens, N.A., as joint lead arrangers and joint bookrunners, and PNC Bank, National Association, Citizens Bank of Pennsylvania, Citibank, N.A., Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, The Bank of New York Mellon, and the other financial institutions from time to time parties thereto.	UGI Utilities	Form 8-K (5/25/2011)		10.1
	10.2	Credit Agreement dated as of June 21, 2011 by and among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as a Guarantor, Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and Issuing Lender (“Agent”), Wells Fargo Securities, LLC, as Sole Lead Arranger and Sole Book Manager and Wells Fargo Bank, National Association, Branch Banking and Trust Company, Citibank, N.A., JPMorgan Chase Bank, N.A., PNC Bank, National Association, Citizens Bank of Pennsylvania, The Bank of New York Mellon, Compass Bank, Manufacturers and Traders Trust Company, Sovereign Bank, TD Bank, N.A. and the other financial institutions from time to time party thereto.	AmeriGas Partners	Form 10-Q (6/30/2011)		10.2

- 62 -

UGI CORPORATION AND SUBSIDIARIES

Exhibit
No.			Exhibit	Registrant	Filing	Exhibit
	31.1		Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2		Certification by the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32		Certification by the Chief Executive Officer and the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	101	.INS*	XBRL Instance
	101	.SCH*	XBRL Taxonomy Extension Schema
	101	.CAL*	XBRL Taxonomy Extension Calculation
	101	.DEF*	XBRL Taxonomy Extension Definition
	101	.LAB*	XBRL Taxonomy Extension Labels
	101	.PRE*	XBRL Taxonomy Extension Presentation

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

- 63 -

UGI CORPORATION AND SUBSIDIARIES

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 5, 2011	By:	/s/ John L. Walsh
		John L. Walsh
		President and Chief Operating Officer (Principal Financial Officer)
Date: August 5, 2011	By:	/s/ Davinder Athwal
		Davinder Athwal
		Vice President — Accounting and Financial Control and Chief Risk Officer

- 64 -

EXHIBIT INDEX

	31.1		Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2		Certification by the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32		Certification by the Chief Executive Officer and the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS		*	XBRL.Instance
101.SCH		*	XBRL Taxonomy Extension Schema
101.CAL		*	XBRL Taxonomy Extension Calculation
101.DEF		*	XBRL Taxonomy Extension Definition
101.LAB		*	XBRL Taxonomy Extension Labels
101.PRE		*	XBRL Taxonomy Extension Presentation

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

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 5, 2011

/s/ Lon R. Greenberg  

Lon R. Greenberg 

Chairman and Chief Executive Officer of
UGI Corporation 

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, John L. Walsh, 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 5, 2011

/s/ John L. Walsh  

John L. Walsh 

President and Chief Operating Officer of UGI
Corporation (Principal Financial Officer) 

EX-32

EXHIBIT 32

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

I, Lon R. Greenberg, Chief Executive Officer, and I, John L. Walsh, Principal 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, 2011 (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	PRINCIPAL FINANCIAL OFFICER
/s/ Lon R. Greenberg Lon R. Greenberg	/s/ John L. Walsh John L. Walsh
Date: August 5, 2011	Date: August 5, 2011

XML



Fair Value Measurement (Details Textuals) (USD $) In Millions	Jun. 30, 2011	Jun. 30, 2010
Fair Value Measurement [Abstract]
Carrying value long-term debt	$ 2,078.0	$ 2,029.7
Estimated fair value of long-term debt	$ 2,170.4	$ 2,122.7

XML



Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) In Millions, except Share data	Jun. 30, 2011	Sep. 30, 2010	Jun. 30, 2010
ASSETS
Accounts receivable, allowances for doubtful accounts	$ 45.0	$ 34.6	$ 44.5
Property, plant and equipment, accumulated depreciation and amortization	$ 2,065.9	$ 1,916.5	$ 1,866.2
UGI Corporation stockholders' equity:
UGI Common Stock, without par value
UGI Common Stock, without par value authorized	300,000,000	300,000,000	300,000,000
UGI Common Stock, without par value, issued	115,507,094	115,400,294	115,375,794

XML



Condensed Consolidated Statements of Income (Unaudited) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Revenues
Revenues	$ 1,105.4	$ 961.9	$ 5,052.0	$ 4,701.0
Costs and expenses:
Cost of sales (excluding depreciation shown below)	731.0	615.5	3,317.5	3,009.2
Operating and administrative expenses	304.3	267.6	966.4	892.7
Utility taxes other than income taxes	3.6	4.2	13.4	13.6
Depreciation	50.8	46.1	149.0	140.4
Amortization	7.0	5.6	19.6	16.9
Other income, net	(8.5)	(8.3)	(40.4)	(12.2)
Total costs and expenses	1,088.2	930.7	4,425.5	4,060.6
Operating income	17.2	31.2	626.5	640.4
Loss from equity investees	(0.2)	(1.9)	(0.8)	(1.9)
Loss on extinguishment of debt			(18.8)
Interest expense	(35.0)	(33.6)	(102.6)	(101.9)
(Loss) income before income taxes	(18.0)	(4.3)	504.3	536.6
Income tax benefit (expense)	4.5	0.1	(147.2)	(162.5)
Net (loss) income	(13.5)	(4.2)	357.1	374.1
Less: net income (loss) attributable to noncontrolling interests, principally AmeriGas Partners	6.3	7.6	(101.8)	(115.2)
Net (loss) income attributable to UGI Corporation	$ (7.2)	$ 3.4	$ 255.3	$ 258.9
(Loss) earnings per common share attributable to UGI stockholders:
Basic	$ (0.06)	$ 0.03	$ 2.29	$ 2.37
Diluted	$ (0.06)	$ 0.03	$ 2.26	$ 2.35
Average common shares outstanding (thousands):
Basic	112,020	109,683	111,515	109,331
Diluted	112,020	110,699	113,046	110,188
Dividends declared per common share	$ 0.26	$ 0.25	$ 0.76	$ 0.65

XML



Disclosures About Derivative Instruments and Hedging Activities (Details 2) (USD $) In Millions	3 Months Ended		9 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Cost of Sales [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Gain or (Loss) Recognized in Income	$ 0.2	$ 1.0	$ (0.4)	$ 1.4
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Operating Expenses/Other Income [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Gain or (Loss) Recognized in Income		(0.1)	0.3	0.1
Derivatives Not Designated as Hedging Instruments [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Gain or (Loss) Recognized in Income	0.2	0.9	(0.1)	1.5
Commodity Contracts [Member] | Cash Flow Hedges [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion	(1.4)	(14.6)	25.4	(30.1)
Commodity Contracts [Member] | Cash Flow Hedges [Member] | Cost of Sales [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion	3.9	(7.7)	(19.1)	(14.1)
Foreign currency contracts [Member] | Cash Flow Hedges [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion	(1.9)	5.3	(3.4)	12.2
Foreign currency contracts [Member] | Cash Flow Hedges [Member] | Cost of Sales [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion		0.1	(0.7)	0.7
Interest Rate Contracts [Member] | Cash Flow Hedges [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion	(13.2)	(6.3)	11.6	(7.2)
Interest Rate Contracts [Member] | Cash Flow Hedges [Member] | Interest Expense And Other Income
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion	(2.4)	(3.9)	(9.6)	(24.4)
Cash Flow Hedges [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion	(16.5)	(15.6)	33.6	(25.1)
Derivative instruments gain loss reclassified from other comprehensive income and noncontrolling interest into income effective portion	1.5	(11.5)	(29.4)	(37.8)
Foreign currency contracts [Member] | Net Investment Hedges [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Derivative instruments gain loss recognized in other comprehensive income and noncontrolling interests effective portion	$ (0.5)	$ 6.1	$ (1.1)	$ 11.2

XML



Intangible Assets (Tables)

9 Months Ended

Jun. 30, 2011

Intangible Assets [Abstract]

Component of company's intangible assets

	June 30,			September 30,			June 30,
	2011			2010			2010
Goodwill (not subject to amortization)	$	1,612.0		$	1,562.7		$	1,475.9
Other intangible assets:
Customer relationships, noncompete agreements and other	$	240.6		$	215.4		$	202.9
Trademarks (not subject to amortization)		51.9			46.3			41.5
Gross carrying amount		292.5			261.7			244.4
Accumulated amortization		(133.0	)		(111.6	)		(106.3	)
Net carrying amount	$	159.5		$	150.1		$	138.1

XML



Document and Entity Information	9 Months Ended
	Jun. 30, 2011	Jul. 29, 2011
Document and Entity Information [Abstract]
Entity Registrant Name	UGI CORP /PA/
Entity Central Index Key	0000884614
Document Type	10-Q
Document Period End Date	Jun. 30, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		111,804,420

XML



Equity (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Changes in UGI's equity and the equity of the noncontrolling interests
Beginning Balance			$ 2,061.6	$ 1,816.8
Net income	(13.5)	(4.2)	357.1	374.1
Net gains (losses) on derivative instruments			25.6	(4.1)
Reclassifications of net losses (gains) on derivative instruments (net of taxes)			11.0	16.5
Benefit plans			2.1	2.3
Foreign currency translation adjustments			37.8	(99.1)
Comprehensive (loss) income (including noncontrolling interests)	(14.0)	(62.4)	433.6	289.7
Dividends and distributions			(154.4)	(137.3)
Equity transactions			38.9	28.4
Other			1.2	(3.6)
Ending Balance	2,380.9	1,994.0	2,380.9	1,994.0
Noncontrolling interests [Member]
Changes in UGI's equity and the equity of the noncontrolling interests
Beginning Balance			237.1	225.4
Net income			101.8	115.2
Net gains (losses) on derivative instruments			14.8	6.9
Reclassifications of net losses (gains) on derivative instruments (net of taxes)			(16.0)	(14.4)
Comprehensive (loss) income (including noncontrolling interests)			100.6	107.7
Dividends and distributions			(69.7)	(66.2)
Equity transactions			0.5	0.7
Other			1.2	(3.6)
Ending Balance	269.7	264.0	269.7	264.0
Common Stock [Member]
Changes in UGI's equity and the equity of the noncontrolling interests
Beginning Balance			906.1	875.6
Equity transactions			28.8	20.5
Ending Balance	934.9	896.1	934.9	896.1
Retained earnings [Member]
Changes in UGI's equity and the equity of the noncontrolling interests
Beginning Balance			966.7	804.3
Net income			255.3	258.9
Comprehensive (loss) income (including noncontrolling interests)			255.3	258.9
Dividends and distributions			(84.7)	(71.1)
Ending Balance	1,137.3	992.1	1,137.3	992.1
Accumulated other comprehensive income (loss) [Member]
Changes in UGI's equity and the equity of the noncontrolling interests
Beginning Balance			(10.1)	(38.9)
Net gains (losses) on derivative instruments			10.8	(11.0)
Reclassifications of net losses (gains) on derivative instruments (net of taxes)			27.0	30.9
Benefit plans			2.1	2.3
Foreign currency translation adjustments			37.8	(99.1)
Comprehensive (loss) income (including noncontrolling interests)			77.7	(76.9)
Ending Balance	67.6	(115.8)	67.6	(115.8)
Treasury stock [Member]
Changes in UGI's equity and the equity of the noncontrolling interests
Beginning Balance			(38.2)	(49.6)
Equity transactions			9.6	7.2
Ending Balance	$ (28.6)	$ (42.4)	$ (28.6)	$ (42.4)

XML



Defined Benefit Pension and Other Postretirement Plans (Tables)

9 Months Ended

Jun. 30, 2011

Employee Retirement Plans [Abstract]

Components of net periodic pension expense and other postretirement benefit costs

							Other
	Pension Benefits						Postretirement Benefits
	Three Months Ended						Three Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Service cost	$	2.1		$	2.2		$	0.1		$	0.1
Interest cost		6.1			5.8			0.3			0.3
Expected return on assets		(6.4	)		(6.5	)		(0.1	)		(0.1	)
Amortization of:
Prior service cost (benefit)		0.1			—			(0.2	)		(0.1	)
Actuarial loss		1.7			1.5			0.1			0.1
Net benefit cost		3.6			3.0			0.2			0.3
Change in associated regulatory liabilities		—			—			0.8			0.7
Net expense	$	3.6		$	3.0		$	1.0		$	1.0

							Other
	Pension Benefits						Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Service cost	$	6.6		$	6.5		$	0.4		$	0.3
Interest cost		18.1			17.6			0.8			0.9
Expected return on assets		(19.4	)		(19.4	)		(0.4	)		(0.3	)
Amortization of:
Prior service cost (benefit)		0.2			—			(0.5	)		(0.3	)
Actuarial loss		5.7			4.4			0.3			0.2
Net benefit cost		11.2			9.1			0.6			0.8
Change in associated regulatory liabilities		—			—			2.4			2.2
Net expense	$	11.2		$	9.1		$	3.0		$	3.0

Reconciliation of the projected benefit obligation

	Three Months
	Ended
	December 31,
	2010
Change in benefit obligations:
Benefit obligations — October 1, 2010	$	465.0
Service cost		2.2
Interest cost		5.8
Actuarial gain		(30.6	)
Benefits paid		(4.7	)
Benefit obligations — December 31, 2010	$	437.7
Change in plan assets:
Fair value of plan assets — October 1, 2010	$	287.9
Actual gain on assets		19.3
Employer contributions		1.8
Benefits paid		(4.7	)
Fair value of plan assets — December 31, 2010	$	304.3
Funded status of the merged plan — December 31, 2010	$	(133.4	)
At December 31, 2010:
Liabilities recorded in the balance sheet:
Unfunded liabilities — included in other current liabilities	$	(20.3	)
Unfunded liabilities — included in other noncurrent liabilities		(113.1	)
Net amount recognized	$	(133.4	)
Amounts recorded in regulatory assets and liabilities:
Prior service cost	$	0.3
Net actuarial loss		112.7
Total	$	113.0
Amounts recorded in stockholders’ equity:
Prior service cost	$	0.1
Net actuarial loss		9.8
Total	$	9.9

XML



Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified				9 Months Ended
	Dec. 31, 2010 Antargaz Competition Authority [Member]	Jun. 30, 2011 Environmental matters [Member]	Jun. 30, 2011 SCE&G [Member]	Jun. 30, 2011 KeySpan [Member]	Jun. 30, 2011 Northeast Companies [Member]
Commitments and Contingencies (Textuals) [Abstract]
Litigating claims relating to sites		2
Alleged percentage of liability for MGP site			25.00%
Approximate remediation cost spent by claimant			$ 22.0	$ 2.3
Approximate third party claim paid by claimant			26
Environmental Exit Cost Anticipated by Claimant			14	11	25
Alleged percentage of responsibility for cost by claimant				50.00%
Environmental Exit Cost Based on Third Party Estimate				10
Additional Environment Exit Cost Based On Claimant Estimate				20
Reversal of Competition Authority Matter Accrual	$ 9.4

XML



Utility Regulatory Assets and Liabilities and Regulatory Matters

9 Months Ended

Jun. 30, 2011

Utility Regulatory Assets and Liabilities and Regulatory Matters [Abstract]

Utility Regulatory Assets and Liabilities and Regulatory Matters

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 2010 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,
	2011		2010		2010
Regulatory assets:
Income taxes recoverable	$	92.7	$	82.5	$	95.3
Underfunded pension and postretirement plans		116.0		159.2		10.3
Environmental costs		20.7		22.6		24.3
Deferred fuel and power costs		7.8		36.6		6.3
Other		8.9		5.8		5.5
Total regulatory assets	$	246.1	$	306.7	$	141.7
Regulatory liabilities:
Postretirement benefits	$	11.6	$	10.5	$	10.3
Environmental overcollections		6.2		7.2		8.3
Deferred fuel and power refunds		22.4		8.3		16.6
State tax benefits — distribution system repairs		6.2		6.7		11.0
Total regulatory liabilities	$	46.4	$	32.7	$	46.2

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

Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in a decrease in regulatory assets of $43.1 (see Note 8).

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, 2011, September 30, 2010 and June 30, 2010 were $1.1, $1.4 and $0.6, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. As more fully described in Note 13, during Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value, with an associated adjustment to regulatory assets or liabilities in accordance with GAAP relating to rate-regulated entities and Electric Utility’s DS procurement, implementation and contingency plans. At June 30, 2011 and September 30, 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $10.1 and $19.7, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010 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, 2011, September 30, 2010 and June 30, 2010 were not material.

Other Regulatory Matters

Transfer of CPG Storage Assets. On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011 the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9. Compliance with the provisions of the PUC Order approving the transfer of the storage assets is not expected to have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a one-year firm storage service agreement with UGI Storage Company.

CPG Base Rate Filing. On January 14, 2011, CPG filed a request with the PUC to increase its operating revenues by $16.5 annually. Among other things, the increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment (collectively, “Energy and Efficiency Conservation Program”). CPG requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the effective date for the rate increase to allow for investigation and public hearing. On June 23, 2011, a Joint Petition for Approval of Settlement of All Issues (“Joint Petition”) was filed with the PUC based upon agreements with the active parties regarding the requested base operating revenue increase. Under the terms of the Joint Petition, CPG will be permitted to increase distribution rates by $8.0 in additional base rate revenue as well as $0.9 in revenues per year for use in CPG’s Energy and Efficiency Conservation Program. On July 19, 2011, a recommended decision was issued by the two assigned administrative law judges (“ALJs”) who recommended that the PUC approve the Joint Petition without modification. The recommended decision of the ALJs is subject to PUC approval. It is anticipated that this process will conclude by the end of Fiscal 2011.

XML



Equity (Tables)

9 Months Ended

Jun. 30, 2011

Equity [Abstract]

Changes in UGI's equity and the equity of the noncontrolling interests

				UGI Shareholders
									Accumulated
									Other
	Non-								Comprehensive
	controlling			Common		Retained			Income			Treasury			Total
	Interests			Stock		Earnings			(Loss)			Stock			Equity
Nine Months Ended June 30, 2011:
Balance September 30, 2010	$	237.1		$	906.1	$	966.7		$	(10.1	)	$	(38.2	)	$	2,061.6
Net income		101.8					255.3									357.1
Net gains on derivative instruments		14.8								10.8						25.6
Reclassifications of net (gains) losses on derivative instruments		(16.0	)							27.0						11.0
Benefit plans										2.1						2.1
Foreign currency translation adjustments										37.8						37.8
Comprehensive income		100.6					255.3			77.7						433.6
Dividends and distributions		(69.7	)				(84.7	)								(154.4	)
Equity transactions		0.5			28.8								9.6			38.9
Other		1.2														1.2
Balance June 30, 2011	$	269.7		$	934.9	$	1,137.3		$	67.6		$	(28.6	)	$	2,380.9
Nine Months Ended June 30, 2010:
Balance September 30, 2009	$	225.4		$	875.6	$	804.3		$	(38.9	)	$	(49.6	)	$	1,816.8
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	)
Equity transactions		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

XML



Defined Benefit Pension and Other Postretirement Plans (Details) (USD $) In Millions	3 Months Ended			9 Months Ended		3 Months Ended		9 Months Ended
	Dec. 31, 2010	Jun. 30, 2011 Pension Benefit [Member]	Jun. 30, 2010 Pension Benefit [Member]	Jun. 30, 2011 Pension Benefit [Member]	Jun. 30, 2010 Pension Benefit [Member]	Jun. 30, 2011 Other Postretirement Benefits [Member]	Jun. 30, 2010 Other Postretirement Benefits [Member]	Jun. 30, 2011 Other Postretirement Benefits [Member]	Jun. 30, 2010 Other Postretirement Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs
Service cost	$ 2.2	$ 2.1	$ 2.2	$ 6.6	$ 6.5	$ 0.1	$ 0.1	$ 0.4	$ 0.3
Interest cost	5.8	6.1	5.8	18.1	17.6	0.3	0.3	0.8	0.9
Expected return on assets		(6.4)	(6.5)	(19.4)	(19.4)	(0.1)	(0.1)	(0.4)	(0.3)
Amortization of:
Prior service cost (benefit)		0.1		0.2		(0.2)	(0.1)	(0.5)	(0.3)
Actuarial loss		1.7	1.5	5.7	4.4	0.1	0.1	0.3	0.2
Net benefit cost		3.6	3.0	11.2	9.1	0.2	0.3	0.6	0.8
Change in associated regulatory liabilities						0.8	0.7	2.4	2.2
Net expense		$ 3.6	$ 3.0	$ 11.2	$ 9.1	$ 1.0	$ 1.0	$ 3.0	$ 3.0

XML



Segment Information (Details 1) (USD $) In Millions	3 Months Ended		9 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Reconciliation of Partnership EBITDA
Depreciation and amortization	$ (57.8)	$ (51.7)	$ (168.6)	$ (157.3)
Loss on extinguishment of debt			18.8
Operating income	17.2	31.2	626.5	640.4
AmeriGas Propane [Member]
Reconciliation of Partnership EBITDA
Partnership EBITDA	31.1	27.2	301.9	323.7
Depreciation and amortization	(24.5)	(21.8)	(70.4)	(65.0)
Loss on extinguishment of debt			18.8
Noncontrolling interests	0.1	(0.1)	2.6	2.5
Operating income	$ 6.7	$ 5.3	$ 252.9	$ 261.2

XML



Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)

9 Months Ended

Jun. 30, 2011

Utility Regulatory Assets and Liabilities and Regulatory Matters [Abstract]

Regulatory assets and liabilities associated with Gas Utility and Electric Utility

	June 30,		September 30,		June 30,
	2011		2010		2010
Regulatory assets:
Income taxes recoverable	$	92.7	$	82.5	$	95.3
Underfunded pension and postretirement plans		116.0		159.2		10.3
Environmental costs		20.7		22.6		24.3
Deferred fuel and power costs		7.8		36.6		6.3
Other		8.9		5.8		5.5
Total regulatory assets	$	246.1	$	306.7	$	141.7
Regulatory liabilities:
Postretirement benefits	$	11.6	$	10.5	$	10.3
Environmental overcollections		6.2		7.2		8.3
Deferred fuel and power refunds		22.4		8.3		16.6
State tax benefits — distribution system repairs		6.2		6.7		11.0
Total regulatory liabilities	$	46.4	$	32.7	$	46.2

XML



Fair Value Measurement

9 Months Ended

Jun. 30, 2011

Fair Value Measurement [Abstract]

Fair Value Measurement

12. 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, 2011, September 30, 2010 and June 30, 2010:

	Asset (Liability)
	Quoted Prices
	in Active			Significant
	Markets for			Other
	Identical Assets			Observable			Unobservable
	and Liabilities			Inputs			Inputs
	(Level 1)			(Level 2)			(Level 3)		Total
June 30, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	0.6		$	10.1		$	—	$	10.7
Interest rate contracts	$	—		$	5.0		$	—	$	5.0
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(12.2	)	$	(11.6	)	$	—	$	(23.8	)
Foreign currency contracts	$	—		$	(6.1	)	$	—	$	(6.1	)
Interest rate contracts	$	—		$	(3.6	)	$	—	$	(3.6	)
September 30, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	1.1		$	10.7		$	—	$	11.8
Foreign currency contracts	$	—		$	0.8		$	—	$	0.8
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(49.4	)	$	(20.3	)	$	—	$	(69.7	)
Foreign currency contracts	$	—		$	(2.9	)	$	—	$	(2.9	)
Interest rate contracts	$	—		$	(18.5	)	$	—	$	(18.5	)
June 30, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	0.4		$	3.2		$	—	$	3.6
Foreign currency contracts	$	—		$	16.9		$	—	$	16.9
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(25.4	)	$	(18.1	)	$	—	$	(43.5	)
Interest rate contracts	$	—		$	(16.4	)	$	—	$	(16.4	)

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

Other Financial Instruments

The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt at June 30, 2011 were $2,078.0 and $2,170.4, respectively. 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. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt.

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

XML



Accounting Changes

9 Months Ended

Jun. 30, 2011

Accounting Changes [Abstract]

Accounting Changes

3. Accounting Changes

Adoption of New Accounting Standard

Transfers of Financial Assets. Effective October 1, 2010, the Company adopted new guidance regarding accounting for transfers of financial assets. Among other things, the new guidance eliminates the concept of Qualified Special Purpose Entities (“QSPEs”). It also amends previous derecognition guidance. The adoption of the new accounting guidance changed the Company’s accounting prospectively for sales of undivided interests in accounts receivable to the commercial paper conduit of a major bank under the Energy Services Receivables Facility. Effective October 1, 2010, trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the commercial paper conduit. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet. Also effective October 1, 2010, the Company records interest expense on amounts owed to the commercial paper conduit. Prior to October 1, 2010, losses on sales of accounts receivable to the commercial paper conduit were reflected in other income, net. Additionally, effective October 1, 2010 borrowings and repayments associated with the Energy Services Receivables Facility are reflected in cash flows from financing activities. Previously such transactions were reflected in cash flows from operating activities. For further information, see Note 6.

New Accounting Standards Not Yet Adopted

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

Presentation of Comprehensive Income. In June 2011, the FASB issued ASU 2011-05, “Presentation of Comprehensive Income,” which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) Topic 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. ASU 2011-05 does not change the items that must be reported in other comprehensive income. The change in presentation is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2011 and the guidance is required to be applied retrospectively. Early adoption is permitted.

XML



Intangible Assets (Details) (USD $) In Millions	Jun. 30, 2011	Sep. 30, 2010	Jun. 30, 2010
Intangible Assets [Abstract]
Goodwill (not subject to amortization)	$ 1,612.0	$ 1,562.7	$ 1,475.9
Other intangible assets:
Customer relationships, noncompete agreements and other	240.6	215.4	202.9
Trademark (not subject to amortization)	51.9	46.3	41.5
Gross carrying amount	292.5	261.7	244.4
Accumulated amortization	(133.0)	(111.6)	(106.3)
Net carrying amount	$ 159.5	$ 150.1	$ 138.1

XML



Debt

9 Months Ended

Jun. 30, 2011

Debt [Abstract]

Debt

9. Debt

AmeriGas Partners. On January 20, 2011, AmeriGas Partners issued $470 principal amount of 6.50% Senior Notes due 2021. The proceeds from the issuance of the 6.50% Senior Notes were used in February 2011 to repay AmeriGas Partners’ $415 7.25% Senior Notes due May 15, 2015 pursuant to a January 5, 2011 tender offer and subsequent notice of redemption. The 6.50% Senior Notes due 2021 rank pari passu with AmeriGas Partners’ outstanding senior debt. In addition, in February 2011, AmeriGas Partners redeemed the outstanding $14.6 principal amount of AmeriGas Partners 8.875% Senior Notes due May 2011. The Partnership incurred a loss of $18.8 on these extinguishments of debt which amount is reflected on the Consolidated Statements of Income under the caption “Loss on extinguishment of debt.” The loss reduced net income attributable to UGI Corporation by $5.2 during the nine months ended June 30, 2011. The 6.50% Senior Notes of AmeriGas Partners restrict the ability of the Partnership and AmeriGas OLP to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets.

In addition, on June 21, 2011, AmeriGas OLP entered into an unsecured revolving credit agreement (the “AmeriGas 2011 Credit Agreement”) with a group of banks providing for borrowings up to $325 (including a $100 sublimit for letters of credit). Concurrently with entering into the AmeriGas 2011 Credit Agreement, AmeriGas OLP terminated its then-existing $200 revolving credit agreement dated as of November 6, 2006 and its $75 credit agreement dated as of April 17, 2009. The AmeriGas 2011 Credit Agreement permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a two-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas 2011 Credit Agreement, plus a margin. The margin on base rate borrowings (which ranges from 0.75% to 1.75%), Eurodollar Rate borrowings (which ranges from 1.75% to 2.75%), and the AmeriGas 2011 Credit Agreement facility fee rate (which ranges from 0.30% to 0.50%) are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (“EBITDA”), each as defined in the AmeriGas 2011 Credit Agreement. The AmeriGas 2011 Credit Agreement restricts the incurrence of additional indebtedness and also restricts certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas 2011 Credit Agreement requires that AmeriGas OLP and AmeriGas Partners not exceed ratios of total indebtedness to EBITDA, as defined for each of those entities, and that AmeriGas Partners maintains a minimum ratio of EBITDA to interest expense, as defined.

Antargaz Refinancing. In March 2011, Antargaz entered into a new five-year variable rate term loan agreement with a consortium of banks (“2011 Senior Facilities Agreement”). The proceeds from the new term loan were used on March 16, 2011 to repay Antargaz’ existing Senior Facilities Agreement that was due March 31, 2011.

The new agreement consists of (1) a €380 variable-rate term loan and (2) a €40 revolving credit facility. Scheduled maturities under the term loan are €38 due May 2014, €34.2 due May 2015, and €307.8 due March 2016. Antargaz’ term loan and revolving credit facility bear interest at one-, two-, three- or six-month euribor, plus a margin, as defined by the 2011 Senior Facilities Agreement. The margin on the term loan and revolving credit facility borrowings (which ranges from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the 2011 Senior Facilities Agreement. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of 3.71% through the date of the term loan’s final maturity in March 2016. At June 30, 2011, the effective interest rate on Antargaz’ term loan was 4.66%. The 2011 Senior Facilities Agreement is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivables. In addition, UGI has guaranteed up to €100 of payments under the 2011 Senior Facilities Agreement. The 2011 Senior Facilities Agreement restricts the ability of Antargaz to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires Antargaz to maintain a ratio of net debt to EBITDA on a French generally accepted accounting basis, as defined in the agreement, that shall not exceed 3.50 to 1.00.

UGI Utilities 2011 Credit Agreement. On May 25, 2011, UGI Utilities entered into an unsecured revolving credit agreement (the “UGI Utilities 2011 Credit Agreement”) with a group of banks providing for borrowings up to $300 (including a $100 sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2011 Credit Agreement, UGI Utilities terminated its then-existing $350 revolving credit agreement dated as of August 11, 2006. Under the UGI Utilities 2011 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 2.0% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2011 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. The UGI Utilities 2011 Credit Agreement is currently scheduled to expire in May 2012, but may be extended by UGI Utilities to October 2015 if on or before May 23, 2012, the Company satisfies certain requirements relating to approval by the PUC. The Company is in the process of seeking such regulatory approval.

Flaga Working Capital Facility Extensions. During the three months ended June 30, 2011, Flaga extended the expiration dates of its two multi-currency working capital facilities, which provide for combined borrowings of €24, to September 2011. Also during the three months ended June 30, 2011, Flaga extended the expiration dates of its two euro-denominated working capital facilities, which provide for combined borrowings of €12, to March 2012.

XML



Inventories

9 Months Ended

Jun. 30, 2011

Inventories [Abstract]

Inventories

14. Inventories

Inventories comprise the following:

	June 30,		September 30,		June 30,
	2011		2010		2010
Non-utility LPG and natural gas	$	170.5	$	157.9	$	145.6
Gas Utility natural gas		50.1		111.5		60.3
Materials, supplies and other		51.0		44.6		43.3
Total inventories	$	271.6	$	314.0	$	249.2

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

The carrying values of natural gas storage inventories released under SCAAs with non-affiliates at June 30, 2011, September 30, 2010 and June 30, 2010 comprising 2.0 billion cubic feet (“bcf”), 8.0 bcf and 4.2 bcf of natural gas was $9.6, $41.9 and $23.2, respectively.

XML



Commitments and Contingencies

9 Months Ended

Jun. 30, 2011

Commitments and Contingencies [Abstract]

Commitments and Contingencies

10. 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, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

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

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

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 they are responsible for an equitable share of any clean up costs Frontier would be required to pay to the City. Frontier alleged that through ownership and control of a subsidiary, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. UGI Utilities filed a motion for summary judgment with respect to Frontier’s claims. On October 19, 2010, the magistrate judge recommended the Court grant UGI Utilities’ motion. On November 19, 2010, the Court affirmed the recommended decision of the magistrate judge granting summary judgment in favor of UGI Utilities. On July 1, 2011, Frontier appealed the Court’s decision to the United States Court of Appeals for the First Circuit.

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

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

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

Other Matters

Purported AmeriGas Class Action Lawsuits. On May 27, 2009, the General Partner was named as a defendant in a purported class action lawsuit in the Superior Court of the State of California in which plaintiffs challenged AmeriGas OLP’s weight disclosure with regard to its portable propane grill cylinders. After that initial suit, various AmeriGas entities were named in more than a dozen similar suits that were filed in various courts throughout the United States. All of those cases were consolidated and transferred to the United States District Court for the Western District of Missouri. On May 19, 2010, the Court granted the class’ motion seeking preliminary approval of the parties’ settlement. On October 4, 2010, the Court ruled that the settlement was fair, reasonable and adequate to the class and granted final approval of the settlement.

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

Swiger, et al. v. UGI/AmeriGas, Inc. et al. In 1996, a fire occurred at the residence of Samuel and Brenda Swiger (the “Swigers”) when propane that leaked from an underground line ignited. In July 1998, the Swigers filed a class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of Monongalia County, West Virginia, in which they sought to recover an unspecified amount of compensatory and punitive damages and attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants had installed propane gas lines, resulting from the defendants’ alleged failure to install underground propane lines at depths required by applicable safety standards. On December 14, 2010, AmeriGas OLP and its affiliates entered into a settlement agreement with the class, which was preliminarily approved by the Circuit Court of Monongalia County on January 13, 2011.

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

BP America Production Company v. Amerigas Propane, L.P. On July 15, 2011, BP America Production Company (“BP”) filed a complaint against AmeriGas Propane, L.P. in the District Court of Denver County, Colorado, alleging, among other things, breach of contract and breach of the covenant of good faith and fair dealing relating to amounts billed for certain goods and services provided to BP since 2005 (the “Services”). The Services relate to the installation of propane-fueled equipment and appliances, and the supply of propane, to approximately 400 residential customers at the request of and for the account of BP. The complaint seeks an unspecified amount of direct, indirect, consequential, special and compensatory damages, including attorneys’ fees, costs and interest and other appropriate relief. It also seeks an accounting to determine the amount of the alleged overcharges related to the Services. We recently commenced an investigation into these allegations. Because of the preliminary nature of this investigation, which is ongoing, the amount of loss, if any, cannot be reasonably estimated.

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. The Statement alleged that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through 2004. On December 17, 2010, the Competition Authority issued its decision dismissing all objections against Antargaz. The appeal period has expired without an appeal having been filed. As a result of the decision, during the three-month period ended December 31, 2010 the Company reversed its previously recorded nontaxable accrual for this matter which increased net income by $9.4. This amount is reflected in other income, net, on the Condensed Consolidated Statement of Income.

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

XML



Significant Accounting Policies (Details) In Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Denominator (thousands of shares):
Average common shares outstanding for basic computation	112,020	109,683	111,515	109,331
Incremental shares issuable for stock options and awards	0	1,016	1,531	857
Average common shares outstanding for diluted computation	112,020	110,699	113,046	110,188

XML



Defined Benefit Pension And Other Postretirement Plans

9 Months Ended

Jun. 30, 2011

Employee Retirement Plans [Abstract]

Defined Benefit Pension and Other Postretirement Plans

8. Defined Benefit Pension and Other Postretirement Plans

In the U.S., we currently sponsor one defined benefit pension plan for employees hired prior to January 1, 2009 of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“Pension Plan”). We also provide postretirement health care benefits to certain retirees and 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,
	2011			2010			2011			2010
Service cost	$	2.1		$	2.2		$	0.1		$	0.1
Interest cost		6.1			5.8			0.3			0.3
Expected return on assets		(6.4	)		(6.5	)		(0.1	)		(0.1	)
Amortization of:
Prior service cost (benefit)		0.1			—			(0.2	)		(0.1	)
Actuarial loss		1.7			1.5			0.1			0.1
Net benefit cost		3.6			3.0			0.2			0.3
Change in associated regulatory liabilities		—			—			0.8			0.7
Net expense	$	3.6		$	3.0		$	1.0		$	1.0

							Other
	Pension Benefits						Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Service cost	$	6.6		$	6.5		$	0.4		$	0.3
Interest cost		18.1			17.6			0.8			0.9
Expected return on assets		(19.4	)		(19.4	)		(0.4	)		(0.3	)
Amortization of:
Prior service cost (benefit)		0.2			—			(0.5	)		(0.3	)
Actuarial loss		5.7			4.4			0.3			0.2
Net benefit cost		11.2			9.1			0.6			0.8
Change in associated regulatory liabilities		—			—			2.4			2.2
Net expense	$	11.2		$	9.1		$	3.0		$	3.0

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. 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 $16.0 to the Pension Plan during the next twelve months. During the nine months ended June 30, 2011, the Company made contributions to the Pension Plan of $16.7. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to 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 for postretirement benefits other than pensions. The difference between such amounts calculated under GAAP and the amounts 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, 2011, nor are they expected to be material for all of Fiscal 2011.

We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans. We recorded pre-tax expense associated with these plans of $0.9 and $2.2 for the three and nine months ended June 30, 2011, respectively. 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.

Effective December 31, 2010, UGI Utilities merged its two defined benefit pension plans. The merged plan maintains the separate benefit formulas and specific rights and features of each predecessor plan. As a result of the merger and in accordance with GAAP relating to accounting for retirement benefits, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2010 which decreased other noncurrent liabilities by $46.7; decreased associated regulatory assets by $43.1; and increased pre-tax other comprehensive income by $3.6 (see Notes 2 and 7).

The following table provides a reconciliation of the projected benefit obligation (“PBO”), plan assets and the funded status of the merged Pension Plan as of December 31, 2010:

	Three Months
	Ended
	December 31,
	2010
Change in benefit obligations:
Benefit obligations — October 1, 2010	$	465.0
Service cost		2.2
Interest cost		5.8
Actuarial gain		(30.6	)
Benefits paid		(4.7	)
Benefit obligations — December 31, 2010	$	437.7
Change in plan assets:
Fair value of plan assets — October 1, 2010	$	287.9
Actual gain on assets		19.3
Employer contributions		1.8
Benefits paid		(4.7	)
Fair value of plan assets — December 31, 2010	$	304.3
Funded status of the merged plan — December 31, 2010	$	(133.4	)
At December 31, 2010:
Liabilities recorded in the balance sheet:
Unfunded liabilities — included in other current liabilities	$	(20.3	)
Unfunded liabilities — included in other noncurrent liabilities		(113.1	)
Net amount recognized	$	(133.4	)
Amounts recorded in regulatory assets and liabilities:
Prior service cost	$	0.3
Net actuarial loss		112.7
Total	$	113.0
Amounts recorded in stockholders’ equity:
Prior service cost	$	0.1
Net actuarial loss		9.8
Total	$	9.9

The accumulated benefit obligation (“ABO”) of the merged plan at December 31, 2010 is $391.2. Actuarial assumptions for the merged plan at December 31, 2010 are as follows: discount rate — 5.5%; expected return on plan assets — 8.5%; rate of increase in salary levels — 3.8%.

XML



Disclosures About Derivative Instruments and Hedging Activities (Details 1) (USD $) In Millions	Jun. 30, 2011	Jun. 30, 2010
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	$ 15.7	$ 20.6
Total Derivatives Liability	(33.5)	(60.0)
Commodity Contracts [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments and Other Assets [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	6.0	0.3
Commodity Contracts [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments And Other Noncurrent Liabilities [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(12.6)	(42.8)
Foreign currency contracts [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments and Other Assets [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	0	16.9
Foreign currency contracts [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments Other Noncurrent Liabilities [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(6.1)	0
Interest Rate Contracts [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments and Other Assets [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	5.0	0
Interest Rate Contracts [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments And Other Noncurrent Liabilities [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(3.6)	(16.4)
Designated as Hedging Instrument [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	11.0	17.2
Total Derivatives Liability	(22.3)	(59.2)
Commodity Contracts [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Derivative Financial Instruments [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	4.5	2.8
Commodity Contracts [Member] | Accounted For Under ASC 980 [Member] | Derivative Financial Instruments And Other Noncurrent Liabilities [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(11.2)	(0.8)
Commodity Contracts [Member] | Accounted For Under ASC 980 [Member] | Derivative Financial Instruments [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	$ 0.2	$ 0.6

XML



Nature of Operations

9 Months Ended

Jun. 30, 2011

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations

1. Nature of Operations

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

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

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

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

XML



Intangible Assets

9 Months Ended

Jun. 30, 2011

Intangible Assets [Abstract]

Intangible Assets

4. Intangible Assets

The Company’s intangible assets comprise the following:

	June 30,			September 30,			June 30,
	2011			2010			2010
Goodwill (not subject to amortization)	$	1,612.0		$	1,562.7		$	1,475.9
Other intangible assets:
Customer relationships, noncompete agreements and other	$	240.6		$	215.4		$	202.9
Trademarks (not subject to amortization)		51.9			46.3			41.5
Gross carrying amount		292.5			261.7			244.4
Accumulated amortization		(133.0	)		(111.6	)		(106.3	)
Net carrying amount	$	159.5		$	150.1		$	138.1

The increases in goodwill and other intangible assets during the nine months ended June 30, 2011 principally reflects the effects of acquisitions and currency translation. Amortization expense of intangible assets was $5.4 and $15.1 for the three and nine months ended June 30, 2011, respectively, and $4.9 and $14.8 for the three and nine months ended June 30, 2010, 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 remainder of Fiscal 2011 and the next four fiscal years is as follows: remainder of Fiscal 2011 — $5.0; Fiscal 2012 — $20.7; Fiscal 2013 — $20.1; Fiscal 2014 — $19.2; Fiscal 2015 — $16.2.

XML



Energy Services Accounts Receivable Securitization Facility (Details) (USD $) In Millions	9 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Energy services accounts receivable securitization facility (Textuals) [Abstract]
Outstanding balance of trade receivables sold	$ 0
Energy Services Accounts Receivable Securitization Facility Additional Textuals [Abstract]
Receivables facility	200
Energy Services Funding Corporation [Member]
Energy services accounts receivable securitization facility (Textuals) [Abstract]
Sale of undivided interests in its trade receivables to the commercial paper conduit	68.0	233.6
Outstanding balance of trade receivables	50.9	61.8
Outstanding balance of trade receivables sold	0
Energy Services [Member]
Energy services accounts receivable securitization facility (Textuals) [Abstract]
Sale of trade receivables	$ 923.5	$ 933.3

XML



Nature of Operations (Details)	Jun. 30, 2011
Nature Of Operations (Textuals) [Abstract]
General Partner held a general partner interest in AmeriGas Partners	1.00%
Percentage of our limited partnership interest in AmeriGas Partners	42.80%
Effective ownership interest in AmeriGas OLP	44.40%
Limited partnership Common Units Held in AmeriGas Partners	24,691,209
General public as limited partner interests in AmeriGas Partners	56.20%
Common Units held by the general public as limited partner interests	32,433,087

XML



Disclosures About Derivative Instruments and Hedging Activities (Details)	Jun. 30, 2011 Gallons	Jun. 30, 2010 Gallons
LPG [Member]
Outstanding derivative commodity instruments volumes
Outstanding derivative commodity instruments volumes	145,000,000	150,500,000
Natural Gas [Member]
Outstanding derivative commodity instruments volumes
Outstanding derivative commodity instruments volumes	21,200,000	33,300,000
Electricity (millions of kilowatt-hours)
Outstanding derivative commodity instruments volumes
Outstanding derivative commodity instruments volumes	1,200,800,000	928,000,000

XML



Segment Information

9 Months Ended

Jun. 30, 2011

Segment Information [Abstract]

Segment Information

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, our propane distribution business in China and certain International Propane nonoperating entities (“Flaga & Other”); (4) Gas Utility; (5) Electric Utility; and (6) Midstream & Marketing. 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 2010 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 Midstream & Marketing segments principally based upon their income before income taxes.

Three Months Ended June 30, 2011:

							Reportable Segments
																			International Propane
							AmeriGas			Gas			Electric			Energy						Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services			Antargaz			Other			& Other (b)
Revenues	$	1,105.4		$	(40.0	) (c)	$	470.8		$	148.1		$	24.1		$	217.1		$	161.0		$	102.3		$	22.0
Cost of sales	$	731.0		$	(39.1	) (c)	$	300.8		$	78.8		$	14.6		$	193.1		$	95.3		$	74.6		$	12.9
Segment profit:
Operating income (loss)	$	17.2		$	—		$	6.7		$	17.2		$	2.4		$	8.4		$	(11.4	)	$	(3.6	)	$	(2.5	)
Loss from equity investees		(0.2	)		—			—			—			—			—			(0.2	)		—			—
Interest expense		(35.0	)		—			(15.7	)		(9.9	)		(0.7	)		(0.6	)		(7.1	)		(0.8	)		(0.2	)
(Loss) income before income taxes	$	(18.0	)	$	—		$	(9.0	)	$	7.3		$	1.7		$	7.8		$	(18.7	)	$	(4.4	)	$	(2.7	)
Partnership EBITDA (a)							$	31.1
Noncontrolling interests’ net loss	$	(6.3	)	$	—		$	(6.1	)	$	—		$	—		$	—		$	(0.2	)	$	—		$	—
Depreciation and amortization	$	57.8		$	—		$	24.5		$	11.6		$	1.1		$	1.8		$	13.5		$	4.7		$	0.6
Capital expenditures	$	78.5		$	—		$	18.6		$	20.9		$	1.0		$	18.7		$	12.0		$	6.6		$	0.7
Total assets (at period end)	$	6,673.7		$	(81.0	)	$	1,772.1		$	2,002.0		$	156.5		$	572.2		$	1,678.2		$	407.3		$	166.4
Bank loans (at period end)	$	206.1		$	—		$	176.0		$	—		$	—		$	—		$	—		$	30.1		$	—
Goodwill (at period end)	$	1,612.0		$	—		$	695.8		$	180.1		$	—		$	2.8		$	641.1		$	85.3		$	6.9

Three Months Ended June 30, 2010:

							Reportable Segments
																		International Propane
							AmeriGas			Gas			Electric			Energy					Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other			& Other (b)
Revenues	$	961.9		$	(22.2	) (c)	$	396.6		$	149.1		$	25.3		$	198.6	$	150.8		$	41.0		$	22.7
Cost of sales	$	615.5		$	(20.7	) (c)	$	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 (a)							$	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

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

Three months ended June 30,	2011			2010
Partnership EBITDA	$	31.1		$	27.2
Depreciation and amortization		(24.5	)		(21.8	)
Noncontrolling interest (i)		0.1			(0.1	)
Operating income	$	6.7		$	5.3

(i)	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(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)	Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.

Nine Months Ended June 30, 2011:

							Reportable Segments
																			International Propane
							AmeriGas			Gas			Electric			Energy						Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services			Antargaz			Other			& Other (b)
Revenues	$	5,052.0		$	(172.9	) (c)	$	2,077.8		$	921.7		$	84.7		$	857.0		$	889.7		$	332.4		$	61.6
Cost of sales	$	3,317.5		$	(170.3	) (c)	$	1,300.9		$	562.3		$	53.4		$	738.6		$	554.0		$	243.8		$	34.8
Segment profit:
Operating income (loss)	$	626.5		$	0.2		$	252.9		$	193.2		$	9.0		$	76.7		$	101.0		$	(0.2	)	$	(6.3	)
Loss from equity investees		(0.8	)		—			—			—			—			—			(0.8	)		—			—
Loss on extinguishment of debt		(18.8	)		—			(18.8	)		—			—			—			—			—			—
Interest expense		(102.6	)		—			(47.4	)		(30.2	)		(1.8	)		(2.0	)		(18.5	)		(2.1	)		(0.6	)
Income (loss) before income taxes	$	504.3		$	0.2		$	186.7		$	163.0		$	7.2		$	74.7		$	81.7		$	(2.3	)	$	(6.9	)
Partnership EBITDA (a)							$	301.9
Noncontrolling interests’ net income	$	101.8		$	—		$	101.2		$	—		$	—		$	—		$	0.6		$	—		$	—
Depreciation and amortization	$	168.6		$	—		$	70.4		$	36.1		$	3.1		$	5.4		$	38.4		$	13.7		$	1.5
Capital expenditures	$	246.1		$	—		$	59.2		$	54.5		$	5.1		$	81.5		$	31.8		$	12.6		$	1.4
Total assets (at period end)	$	6,673.7		$	(81.0	)	$	1,772.1		$	2,002.0		$	156.5		$	572.2		$	1,678.2		$	407.3		$	166.4
Bank loans (at period end)	$	206.1		$	—		$	176.0		$	—		$	—		$	—		$	—		$	30.1		$	—
Goodwill (at period end)	$	1,612.0		$	—		$	695.8		$	180.1		$	—		$	2.8		$	641.1		$	85.3		$	6.9

Nine Months Ended June 30, 2010:

							Reportable Segments
																		International Propane
							AmeriGas			Gas			Electric			Energy					Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other			& Other (b)
Revenues	$	4,701.0		$	(146.9	) (c)	$	1,939.3		$	922.3		$	90.9		$	949.5	$	755.3		$	129.8		$	60.8
Cost of sales	$	3,009.2		$	(142.3	) (c)	$	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 (a)							$	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

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

Nine months ended June 30,	2011			2010
Partnership EBITDA	$	301.9	(ii)	$	323.7	(iii)
Depreciation and amortization		(70.4	)		(65.0	)
Loss on extinguishment of debt		18.8			—
Noncontrolling interest (i)		2.6			2.5
Operating income	$	252.9		$	261.2

(i)	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(ii)	Includes $18.8 loss associated with the extinguishment of Partnership debt.
(iii)	Includes $12.2 loss associated with the discontinuance of Partnership interest rate protection agreements.
(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)	Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.

XML



Utility Regulatory Assets and Liabilities and Regulatory Matters (Details Textuals) (USD $) In Millions	3 Months Ended
	Dec. 31, 2010	Jun. 30, 2011	Jun. 23, 2011	Mar. 31, 2011	Jan. 14, 2011	Sep. 30, 2010	Jun. 30, 2010
Utility regulatory assets and liabilities and regulatory matters [Textuals Abstract]
Gas utility unrealized losses on derivative financial instruments contracts		$ 1.1				$ 1.4	$ 0.6
Decrease in regulatory assets on remeasurement of merged plan's assets and benefit obligations	43.1
Fair values of electric utility's forward purchase power agreements		33.5					60.0
Net book value of storage facility assets				10.9
Expected Increase in base operating revenues by CPG Base Rate Filing					16.5
Increase in distribution rates, Base rate revenue			8.0
Amount included in distribution rates for CPG'S Energy and Efficiency Conservation Program			0.9
Electric Utility - Forward Contract [Member]
Utility regulatory assets and liabilities and regulatory matters [Textuals Abstract]
Fair values of electric utility's forward purchase power agreements		$ 10.1				$ 19.7

XML



Fair Value Measurement [Tables]

9 Months Ended

Jun. 30, 2011

Fair Value Measurement [Abstract]

Financial assets and financial liabilities that are measured at fair value on a recurring basis

	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, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	0.6		$	10.1		$	—	$	10.7
Interest rate contracts	$	—		$	5.0		$	—	$	5.0
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(12.2	)	$	(11.6	)	$	—	$	(23.8	)
Foreign currency contracts	$	—		$	(6.1	)	$	—	$	(6.1	)
Interest rate contracts	$	—		$	(3.6	)	$	—	$	(3.6	)
September 30, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	1.1		$	10.7		$	—	$	11.8
Foreign currency contracts	$	—		$	0.8		$	—	$	0.8
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(49.4	)	$	(20.3	)	$	—	$	(69.7	)
Foreign currency contracts	$	—		$	(2.9	)	$	—	$	(2.9	)
Interest rate contracts	$	—		$	(18.5	)	$	—	$	(18.5	)
June 30, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	0.4		$	3.2		$	—	$	3.6
Foreign currency contracts	$	—		$	16.9		$	—	$	16.9
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(25.4	)	$	(18.1	)	$	—	$	(43.5	)
Interest rate contracts	$	—		$	(16.4	)	$	—	$	(16.4	)

XML



Significant Accounting Policies (Details 1) (USD $) In Millions	3 Months Ended		9 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Components of comprehensive income (loss)
Net (loss) income	$ (13.5)	$ (4.2)	$ 357.1	$ 374.1
Other comprehensive (loss) income	(0.5)	(58.2)	76.5	(84.4)
Comprehensive (loss) income (including noncontrolling interests)	(14.0)	(62.4)	433.6	289.7
Less: comprehensive income (loss) attributable to noncontrolling interests	10.8	21.4	(100.6)	(107.7)
Comprehensive (loss) income attributable to UGI Corporation	$ (3.2)	$ (41.0)	$ 333.0	$ 182.0

XML



Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $) In Millions	Jun. 30, 2011	Sep. 30, 2010	Jun. 30, 2010
Regulatory Asset
Regulatory Assets	$ 246.1	$ 306.7	$ 141.7
Regulatory Liability
Regulatory Liabilities	46.4	32.7	46.2
Income taxes recoverable [Member]
Regulatory Asset
Regulatory Assets	92.7	82.5	95.3
Underfunded pension and postretirement plans [Member]
Regulatory Asset
Regulatory Assets	116.0	159.2	10.3
Environmental costs [Member]
Regulatory Asset
Regulatory Assets	20.7	22.6	24.3
Deferred fuel and power costs [Member]
Regulatory Asset
Regulatory Assets	7.8	36.6	6.3
Other [Member]
Regulatory Asset
Regulatory Assets	8.9	5.8	5.5
Postretirement benefits [Member]
Regulatory Liability
Regulatory Liabilities	11.6	10.5	10.3
Environmental overcollections [Member]
Regulatory Liability
Regulatory Liabilities	6.2	7.2	8.3
Deferred fuel and power refunds [Member]
Regulatory Liability
Regulatory Liabilities	22.4	8.3	16.6
State tax benefits - distribution system repairs [Member]
Regulatory Liability
Regulatory Liabilities	$ 6.2	$ 6.7	$ 11.0

XML



Inventories (Tables)

9 Months Ended

Jun. 30, 2011

Inventories [Abstract]

Inventories

	June 30,		September 30,		June 30,
	2011		2010		2010
Non-utility LPG and natural gas	$	170.5	$	157.9	$	145.6
Gas Utility natural gas		50.1		111.5		60.3
Materials, supplies and other		51.0		44.6		43.3
Total inventories	$	271.6	$	314.0	$	249.2

XML



Disclosures About Derivative Instruments and Hedging Activities

9 Months Ended

Jun. 30, 2011

Disclosures About Derivative Instruments and Hedging Activities [Abstract]

Disclosures About Derivative Instruments and Hedging Activities

13. Disclosures About Derivative Instruments and Hedging Activities

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

Commodity Price Risk

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

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At June 30, 2011 and 2010, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 18.6 million dekatherms and 11.3 million dekatherms, respectively. At June 30, 2011, the maximum period over which Gas Utility is hedging natural gas market price risk is 16 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with ASC No. 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 7).

Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At June 30, 2011, the fair values of Electric Utility’s forward purchase power agreements comprising a loss of $10.1 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying June 30, 2011 Condensed Consolidated Balance Sheet. In accordance with ASC 980, Electric Utility has recorded equal and offsetting amounts in regulatory assets on the June 30, 2011 Condensed Consolidated Balance Sheet. At June 30, 2011, volumes under Electric Utility’s forward electricity purchase contracts were 874.4 million kilowatt hours and the maximum period over which these contracts extend is 35 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs associated with certain default service customers, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 7). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At June 30, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 287.3 million kilowatt hours and 739.3 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At June 30, 2011 and 2010, the volumes associated with Midstream & Marketing’s FTRs totaled 1,955.2 million kilowatt hours and 1,415.0 million kilowatt hours, respectively.

In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas and electricity futures contracts. In addition, beginning April 1, 2011, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Because the contracts associated with the anticipated sale of stored natural gas or propane do not qualify for hedge accounting treatment, any gains or losses on the derivative contracts are recognized in earnings prior to gains or losses from the sale of the stored gas. Such derivative gains or losses during the three months ended June 30, 2011 were not material. At June 30, 2011, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 2.3 million dekatherms and 0.9 million gallons, respectively.

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

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

	Volumes
	June 30,
Commodity	2011		2010
LPG (millions of gallons)		145.0		150.5
Natural gas (millions of dekatherms)		21.2		33.3
Electricity (millions of kilowatt-hours)		1,200.8		928.0

At June 30, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 15 months with a weighted average of 7 months; the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 30 months with a weighted average of 9 months; and the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity price risk (excluding Electric Utility) is 21 months with a weighted average of 7 months. At June 30, 2011, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 11 months.

We account for commodity price risk contracts (other than those contracts that are not eligible for hedge accounting and Gas Utility and Electric Utility contracts that are subject to regulatory treatment) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in 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 Condensed Consolidated Statements of Income. At June 30, 2011, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $8.7.

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 entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on a substantial portion of its term loans, in each case through the respective scheduled maturity dates. As of June 30, 2011 and 2010, the total notional amounts of existing or anticipated variable-rate debt subject to interest rate swap agreements were €398.8 and €706.2, respectively.

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At June 30, 2011, the total notional amount of unsettled IRPAs was $173.0. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt forecasted to occur in September 2012 and September 2013.

As previously disclosed, during the three months ended March 31, 2010, the Partnership’s management determined that it was likely that it would not issue $150 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 long-term debt issuance and recorded a $12.2 loss which is reflected in other income, net, on the Condensed Consolidated Statements of Income for the nine months ended 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, 2011, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $1.7 (which excludes the impact of AmeriGas Partners’ debt refinancing described in Note 15).

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At June 30, 2011 and 2010, we were hedging a total of $141.4 and $72.8 of U.S. dollar-denominated LPG purchases, respectively. At June 30, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 32 months with a weighted average of 12 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our International Propane euro-denominated net investments. At June 30, 2011 and 2010, we were hedging a total of €14.5 and €48.3, respectively, of our euro-denominated net investments. As of June 30, 2011, our foreign currency contracts extend through March 2014.

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 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, 2011, the amount of net losses associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $4.0. Gains and losses on net investment hedges remain in AOCI until such foreign net investment is sold or 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 large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and option contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. At June 30, 2011 and 2010, restricted cash in these accounts totaled $10.2 and $22.9, 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, 2011. We generally do not have credit-risk-related contingent features in our derivative contracts.

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2011 and 2010:

	Derivative Assets					Derivative (Liabilities)
		Fair Value					Fair Value
	Balance Sheet	June 30,				Balance Sheet	June 30,
	Location	2011		2010		Location	2011			2010
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	6.0	$	0.3	Derivative financial instruments and Other noncurrent liabilities	$	(12.6	)	$	(42.8	)
Foreign currency contracts
	Derivative financial instruments and Other assets		—		16.9	Derivative financial instruments and Other noncurrent liabilities		(6.1	)		—
Interest rate contracts
	Other assets		5.0		—	Derivative financial instruments and Other noncurrent liabilities		(3.6	)		(16.4	)
Total Derivatives Designated as Hedging Instruments		$	11.0	$	17.2		$	(22.3	)	$	(59.2	)
Derivatives Accounted for under ASC 980:
Commodity contracts	Derivative financial instruments	$	0.2	$	0.6	Derivative financial instruments and Other noncurrent liabilities	$	(11.2	)	$	(0.8	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	$	4.5	$	2.8
Total Derivatives		$	15.7	$	20.6		$	(33.5	)	$	(60.0	)

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three and nine months ended June 30, 2011 and 2010:

Three Months Ended June 30,:

	Gain (Loss)						Gain (Loss)						Location of
	Recognized in						Reclassified from						Gain (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2011			2010			2011			2010			Interests into Income
Cash Flow
Hedges:
Commodity contracts	$	(1.4	)	$	(14.6	)	$	3.9		$	(7.7	)	Cost of sales
Foreign currency contracts		(1.9	)		5.3			—			0.1		Cost of sales
Interest rate contracts		(13.2	)		(6.3	)		(2.4	)		(3.9	)	Interest expense / other income
Total	$	(16.5	)	$	(15.6	)	$	1.5		$	(11.5	)
Net Investment
Hedges:
Foreign currency contracts	$	(0.5	)	$	6.1
	Gain (Loss)
	Recognized in Income												Location of Gain (Loss)
	2011			2010									Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	—		$	(0.1	)							Operating expenses / other income
Commodity contracts		0.2			1.0								Cost of sales
Total	$	0.2		$	0.9

Nine Months Ended June 30,:

	Gain (Loss)						Gain (Loss)						Location of
	Recognized in						Reclassified from						Gain (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2011			2010			2011			2010			Interests into Income
Cash Flow
Hedges:
Commodity contracts	$	25.4		$	(30.1	)	$	(19.1	)	$	(14.1	)	Cost of sales
Foreign currency contracts		(3.4	)		12.2			(0.7	)		0.7		Cost of sales
Interest rate contracts		11.6			(7.2	)		(9.6	)		(24.4	)	Interest expense /other income
Total	$	33.6		$	(25.1	)	$	(29.4	)	$	(37.8	)
Net Investment
Hedges:
Foreign currency contracts	$	(1.1	)	$	11.2
	Gain (Loss)
	Recognized in Income												Location of Gain (Loss)
	2011			2010									Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	0.3		$	0.1								Operating expenses / other income
Commodity contracts		(0.4	)		1.4								Cost of sales
Total	$	(0.1	)	$	1.5

The amounts of derivative gains or losses representing ineffectiveness were not material for the three and nine months ended June 30, 2011 and 2010.

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

XML



Inventories (Details Textual) (USD $) In Millions, unless otherwise specified	Jun. 30, 2011 Billion-cubic-feet	Sep. 30, 2010 Billion-cubic-feet	Jun. 30, 2010 Billion-cubic-feet
Inventories (Textuals) [Abstract]
Volume of gas storage inventories released under SCAAs with non-affiliates (In Cubic Feet)	2,000,000,000	8,000,000,000	4,200,000,000
Carrying value of gas storage inventories released under SCAAs with non-affiliates	$ 9.6	$ 41.9	$ 23.2

XML



Energy Services Accounts Receivable Securitization Facility

9 Months Ended

Jun. 30, 2011

Transfers and Servicing [Abstract]

Energy Services Accounts Receivable Securitization Facility

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 2012, 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. Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC.

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

During the nine months ended June 30, 2011 and 2010, Energy Services transferred trade receivables to ESFC totaling $923.5 and $933.3, respectively. During the nine months ended June 30, 2011 and 2010, ESFC sold an aggregate $68.0 and $233.6, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At June 30, 2011, the balance of ESFC receivables was $50.9 and there was no amount sold to the commercial paper conduit. At June 30, 2010, the outstanding balance of ESFC receivables was $61.8 and there was no amount sold to the commercial paper conduit.

XML



Significant Accounting Policies (Policies)

9 Months Ended

Jun. 30, 2011

Significant Accounting Policies [Abstract]

Restricted Cash

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

Earnings Per Common Share

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

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

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Denominator (thousands of shares):
Average common shares outstanding for basic computation		112,020		109,683		111,515		109,331
Incremental shares issuable for stock options and awards		—		1,016		1,531		857
Average common shares outstanding for diluted computation		112,020		110,699		113,046		110,188

Comprehensive Income (loss) / Presentation of Comprehensive Income

Comprehensive Income (Loss). The following table presents the components of comprehensive income (loss) for the three and nine months ended June 30, 2011 and 2010:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Net (loss) income	$	(13.5	)	$	(4.2	)	$	357.1		$	374.1
Other comprehensive (loss) income		(0.5	)		(58.2	)		76.5			(84.4	)
Comprehensive (loss) income (including noncontrolling interests)		(14.0	)		(62.4	)		433.6			289.7
Less: comprehensive income (loss) attributable to noncontrolling interests		10.8			21.4			(100.6	)		(107.7	)
Comprehensive (loss) income attributable to UGI Corporation	$	(3.2	)	$	(41.0	)	$	333.0		$	182.0

Other comprehensive (loss) income principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, 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.

Reclassifications

Reclassifications. We have reclassified certain prior-year period balances to conform to the current-period presentation.

Use of Estimates

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

Basis of Presentation

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, 2010 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 Annual Report on Form 10-K for the year ended September 30, 2010 (“Company’s 2010 Annual Financial Statements and Notes”). 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.

Transfers of Financial Assets

Adoption of New Accounting Standard

Transfers of Financial Assets. Effective October 1, 2010, the Company adopted new guidance regarding accounting for transfers of financial assets. Among other things, the new guidance eliminates the concept of Qualified Special Purpose Entities (“QSPEs”). It also amends previous derecognition guidance. The adoption of the new accounting guidance changed the Company’s accounting prospectively for sales of undivided interests in accounts receivable to the commercial paper conduit of a major bank under the Energy Services Receivables Facility. Effective October 1, 2010, trade receivables sold to the commercial paper conduit remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the commercial paper conduit. Prior to October 1, 2010, trade accounts receivable sold to the commercial paper conduit were removed from the balance sheet. Also effective October 1, 2010, the Company records interest expense on amounts owed to the commercial paper conduit. Prior to October 1, 2010, losses on sales of accounts receivable to the commercial paper conduit were reflected in other income, net. Additionally, effective October 1, 2010 borrowings and repayments associated with the Energy Services Receivables Facility are reflected in cash flows from financing activities. Previously such transactions were reflected in cash flows from operating activities. For further information, see Note 6.

Fair Value Measurements

New Accounting Standards Not Yet Adopted

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

XML



Segment Information (Details Textuals) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Segment Information (Textuals) [Abstract]
Loss on extinguishment of debt	$ 18.8
AmeriGas Propane [Member]
Segment Information (Textuals) [Abstract]
General Partner's interest in AmeriGas OLP	1.01%
Loss on extinguishment of debt	18.8
Loss associated with the discontinuance of Partnership interest rate protection agreements		$ 12.2

XML



Disclosures About Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Jun. 30, 2011

Disclosures About Derivative Instruments and Hedging Activities [Abstract]

Outstanding derivative commodity instruments volumes

	Volumes
	June 30,
Commodity	2011		2010
LPG (millions of gallons)		145.0		150.5
Natural gas (millions of dekatherms)		21.2		33.3
Electricity (millions of kilowatt-hours)		1,200.8		928.0

Balance sheet location and fair value of derivative assets and liabilities

	Derivative Assets					Derivative (Liabilities)
		Fair Value					Fair Value
	Balance Sheet	June 30,				Balance Sheet	June 30,
	Location	2011		2010		Location	2011			2010
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	6.0	$	0.3	Derivative financial instruments and Other noncurrent liabilities	$	(12.6	)	$	(42.8	)
Foreign currency contracts
	Derivative financial instruments and Other assets		—		16.9	Derivative financial instruments and Other noncurrent liabilities		(6.1	)		—
Interest rate contracts
	Other assets		5.0		—	Derivative financial instruments and Other noncurrent liabilities		(3.6	)		(16.4	)
Total Derivatives Designated as Hedging Instruments		$	11.0	$	17.2		$	(22.3	)	$	(59.2	)
Derivatives Accounted for under ASC 980:
Commodity contracts	Derivative financial instruments	$	0.2	$	0.6	Derivative financial instruments and Other noncurrent liabilities	$	(11.2	)	$	(0.8	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	$	4.5	$	2.8
Total Derivatives		$	15.7	$	20.6		$	(33.5	)	$	(60.0	)

Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest

	Gain (Loss)						Gain (Loss)						Location of
	Recognized in						Reclassified from						Gain (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2011			2010			2011			2010			Interests into Income
Cash Flow
Hedges:
Commodity contracts	$	(1.4	)	$	(14.6	)	$	3.9		$	(7.7	)	Cost of sales
Foreign currency contracts		(1.9	)		5.3			—			0.1		Cost of sales
Interest rate contracts		(13.2	)		(6.3	)		(2.4	)		(3.9	)	Interest expense / other income
Total	$	(16.5	)	$	(15.6	)	$	1.5		$	(11.5	)
Net Investment
Hedges:
Foreign currency contracts	$	(0.5	)	$	6.1
	Gain (Loss)
	Recognized in Income												Location of Gain (Loss)
	2011			2010									Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	—		$	(0.1	)							Operating expenses / other income
Commodity contracts		0.2			1.0								Cost of sales
Total	$	0.2		$	0.9

Nine Months Ended June 30,:

	Gain (Loss)						Gain (Loss)						Location of
	Recognized in						Reclassified from						Gain (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2011			2010			2011			2010			Interests into Income
Cash Flow
Hedges:
Commodity contracts	$	25.4		$	(30.1	)	$	(19.1	)	$	(14.1	)	Cost of sales
Foreign currency contracts		(3.4	)		12.2			(0.7	)		0.7		Cost of sales
Interest rate contracts		11.6			(7.2	)		(9.6	)		(24.4	)	Interest expense /other income
Total	$	33.6		$	(25.1	)	$	(29.4	)	$	(37.8	)
Net Investment
Hedges:
Foreign currency contracts	$	(1.1	)	$	11.2
	Gain (Loss)
	Recognized in Income												Location of Gain (Loss)
	2011			2010									Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	0.3		$	0.1								Operating expenses / other income
Commodity contracts		(0.4	)		1.4								Cost of sales
Total	$	(0.1	)	$	1.5

XML



Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $) In Millions	9 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 357.1	$ 374.1
Reconcile to net cash from operating activities:
Depreciation and amortization	168.6	157.3
Deferred income taxes, net	24.8	46.9
Provision for uncollectible accounts	19.8	26.2
Net change in realized gains and losses deferred as cash flow hedges	13.8	31.4
Loss on extinguishment of debt	18.8
Other, net	18.4	20.7
Net change in:
Accounts receivable and accrued utility revenues	(93.1)	(147.3)
Inventories	56.7	106.9
Utility deferred fuel costs	33.0	(1.0)
Accounts payable	(51.3)	(10.0)
Other current assets	(6.8)	(6.2)
Other current liabilities	(92.6)	(82.3)
Net cash provided by operating activities	467.2	516.7
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(245.3)	(228.8)
Acquisitions of businesses, net of cash acquired	(49.6)	(25.4)
Decrease (increase) in restricted cash	24.6	(15.9)
Other, net	(1.7)	(14.7)
Net cash used by investing activities	(272.0)	(284.8)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(84.7)	(71.1)
Distributions on AmeriGas Partners publicly held Common Units	(69.7)	(66.2)
Issuances of debt	981.5
Repayments of debt	(987.3)	(9.5)
Increase (decrease) in bank loans	5.4	(123.3)
Receivables Facility net repayments	(12.1)
Issuances of UGI Common Stock	24.9	16.6
Other	3.4	1.7
Net cash used by financing activities	(138.6)	(251.8)
EFFECT OF EXCHANGE RATE CHANGES ON CASH	0.5	(18.4)
Cash and cash equivalents increase (decrease)	57.1	(38.3)
Cash and cash equivalents:
End of period	317.8	241.8
Beginning of period	260.7	280.1
Increase (decrease)	$ 57.1	$ (38.3)

XML



Significant Accounting Policies (Tables)

9 Months Ended

Jun. 30, 2011

Significant Accounting Policies [Abstract]

Shares used in computing basic and diluted earnings per share

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Denominator (thousands of shares):
Average common shares outstanding for basic computation		112,020		109,683		111,515		109,331
Incremental shares issuable for stock options and awards		—		1,016		1,531		857
Average common shares outstanding for diluted computation		112,020		110,699		113,046		110,188

Components of comprehensive income (loss)

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Net (loss) income	$	(13.5	)	$	(4.2	)	$	357.1		$	374.1
Other comprehensive (loss) income		(0.5	)		(58.2	)		76.5			(84.4	)
Comprehensive (loss) income (including noncontrolling interests)		(14.0	)		(62.4	)		433.6			289.7
Less: comprehensive income (loss) attributable to noncontrolling interests		10.8			21.4			(100.6	)		(107.7	)
Comprehensive (loss) income attributable to UGI Corporation	$	(3.2	)	$	(41.0	)	$	333.0		$	182.0

XML



Defined Benefit Pension and Other Postretirement Plans (Details 1) (USD $) In Millions	3 Months Ended
	Dec. 31, 2010
Change in benefit obligations:
Benefit obligations - October 1,2010	$ 465.0
Service cost	2.2
Interest cost	5.8
Actuarial gain	(30.6)
Benefits paid	(4.7)
Benefits obligations - December 31, 2010	437.7
Change in plan assets:
Fair value of plan assets - October 1, 2010	287.9
Actual gain on assets	19.3
Employer contributions	1.8
Benefits paid	(4.7)
Fair value of plan assets - December 31, 2010	304.3
Funded status of the merged plan - December 31,2010	(133.4)
Liabilities recorded in the balance sheet:
Unfunded liabilities - included in other current liabilities	(20.3)
Unfunded liabilities - included in other noncurrent liabilities	(113.1)
Net amount recognized	(133.4)
Amounts Recorded In Regulatory Assets And Liabilities Pre Tax Abstract
Prior service cost	0.3
Net actuarial loss	112.7
Total	113.0
Amounts recorded in stockholders' equity:
Prior service cost	0.1
Net actuarial loss	9.8
Total	$ 9.9

XML



Segment Information (Tables)

9 Months Ended

Jun. 30, 2011

Segment Information [Abstract]

Segment Information

Three Months Ended June 30, 2011:

							Reportable Segments
																			International Propane
							AmeriGas			Gas			Electric			Energy						Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services			Antargaz			Other			& Other (b)
Revenues	$	1,105.4		$	(40.0	) (c)	$	470.8		$	148.1		$	24.1		$	217.1		$	161.0		$	102.3		$	22.0
Cost of sales	$	731.0		$	(39.1	) (c)	$	300.8		$	78.8		$	14.6		$	193.1		$	95.3		$	74.6		$	12.9
Segment profit:
Operating income (loss)	$	17.2		$	—		$	6.7		$	17.2		$	2.4		$	8.4		$	(11.4	)	$	(3.6	)	$	(2.5	)
Loss from equity investees		(0.2	)		—			—			—			—			—			(0.2	)		—			—
Interest expense		(35.0	)		—			(15.7	)		(9.9	)		(0.7	)		(0.6	)		(7.1	)		(0.8	)		(0.2	)
(Loss) income before income taxes	$	(18.0	)	$	—		$	(9.0	)	$	7.3		$	1.7		$	7.8		$	(18.7	)	$	(4.4	)	$	(2.7	)
Partnership EBITDA (a)							$	31.1
Noncontrolling interests’ net loss	$	(6.3	)	$	—		$	(6.1	)	$	—		$	—		$	—		$	(0.2	)	$	—		$	—
Depreciation and amortization	$	57.8		$	—		$	24.5		$	11.6		$	1.1		$	1.8		$	13.5		$	4.7		$	0.6
Capital expenditures	$	78.5		$	—		$	18.6		$	20.9		$	1.0		$	18.7		$	12.0		$	6.6		$	0.7
Total assets (at period end)	$	6,673.7		$	(81.0	)	$	1,772.1		$	2,002.0		$	156.5		$	572.2		$	1,678.2		$	407.3		$	166.4
Bank loans (at period end)	$	206.1		$	—		$	176.0		$	—		$	—		$	—		$	—		$	30.1		$	—
Goodwill (at period end)	$	1,612.0		$	—		$	695.8		$	180.1		$	—		$	2.8		$	641.1		$	85.3		$	6.9

Three Months Ended June 30, 2010:

							Reportable Segments
																		International Propane
							AmeriGas			Gas			Electric			Energy					Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other			& Other (b)
Revenues	$	961.9		$	(22.2	) (c)	$	396.6		$	149.1		$	25.3		$	198.6	$	150.8		$	41.0		$	22.7
Cost of sales	$	615.5		$	(20.7	) (c)	$	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 (a)							$	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

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

Three months ended June 30,	2011			2010
Partnership EBITDA	$	31.1		$	27.2
Depreciation and amortization		(24.5	)		(21.8	)
Noncontrolling interest (i)		0.1			(0.1	)
Operating income	$	6.7		$	5.3

(i)	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(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)	Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.

Nine Months Ended June 30, 2011:

							Reportable Segments
																			International Propane
							AmeriGas			Gas			Electric			Energy						Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services			Antargaz			Other			& Other (b)
Revenues	$	5,052.0		$	(172.9	) (c)	$	2,077.8		$	921.7		$	84.7		$	857.0		$	889.7		$	332.4		$	61.6
Cost of sales	$	3,317.5		$	(170.3	) (c)	$	1,300.9		$	562.3		$	53.4		$	738.6		$	554.0		$	243.8		$	34.8
Segment profit:
Operating income (loss)	$	626.5		$	0.2		$	252.9		$	193.2		$	9.0		$	76.7		$	101.0		$	(0.2	)	$	(6.3	)
Loss from equity investees		(0.8	)		—			—			—			—			—			(0.8	)		—			—
Loss on extinguishment of debt		(18.8	)		—			(18.8	)		—			—			—			—			—			—
Interest expense		(102.6	)		—			(47.4	)		(30.2	)		(1.8	)		(2.0	)		(18.5	)		(2.1	)		(0.6	)
Income (loss) before income taxes	$	504.3		$	0.2		$	186.7		$	163.0		$	7.2		$	74.7		$	81.7		$	(2.3	)	$	(6.9	)
Partnership EBITDA (a)							$	301.9
Noncontrolling interests’ net income	$	101.8		$	—		$	101.2		$	—		$	—		$	—		$	0.6		$	—		$	—
Depreciation and amortization	$	168.6		$	—		$	70.4		$	36.1		$	3.1		$	5.4		$	38.4		$	13.7		$	1.5
Capital expenditures	$	246.1		$	—		$	59.2		$	54.5		$	5.1		$	81.5		$	31.8		$	12.6		$	1.4
Total assets (at period end)	$	6,673.7		$	(81.0	)	$	1,772.1		$	2,002.0		$	156.5		$	572.2		$	1,678.2		$	407.3		$	166.4
Bank loans (at period end)	$	206.1		$	—		$	176.0		$	—		$	—		$	—		$	—		$	30.1		$	—
Goodwill (at period end)	$	1,612.0		$	—		$	695.8		$	180.1		$	—		$	2.8		$	641.1		$	85.3		$	6.9

Nine Months Ended June 30, 2010:

							Reportable Segments
																		International Propane
							AmeriGas			Gas			Electric			Energy					Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other			& Other (b)
Revenues	$	4,701.0		$	(146.9	) (c)	$	1,939.3		$	922.3		$	90.9		$	949.5	$	755.3		$	129.8		$	60.8
Cost of sales	$	3,009.2		$	(142.3	) (c)	$	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 (a)							$	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

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

Nine months ended June 30,	2011			2010
Partnership EBITDA	$	301.9	(ii)	$	323.7	(iii)
Depreciation and amortization		(70.4	)		(65.0	)
Loss on extinguishment of debt		18.8			—
Noncontrolling interest (i)		2.6			2.5
Operating income	$	252.9		$	261.2

(i)	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
(ii)	Includes $18.8 loss associated with the extinguishment of Partnership debt.
(iii)	Includes $12.2 loss associated with the discontinuance of Partnership interest rate protection agreements.
(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)	Principally represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.

XML



Significant Accounting Policies

9 Months Ended

Jun. 30, 2011

Significant Accounting Policies [Abstract]

Significant Accounting Policies

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, 2010 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 Annual Report on Form 10-K for the year ended September 30, 2010 (“Company’s 2010 Annual Financial Statements and Notes”). 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.

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

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

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

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Denominator (thousands of shares):
Average common shares outstanding for basic computation		112,020		109,683		111,515		109,331
Incremental shares issuable for stock options and awards		—		1,016		1,531		857
Average common shares outstanding for diluted computation		112,020		110,699		113,046		110,188

Comprehensive Income (Loss). The following table presents the components of comprehensive income (loss) for the three and nine months ended June 30, 2011 and 2010:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Net (loss) income	$	(13.5	)	$	(4.2	)	$	357.1		$	374.1
Other comprehensive (loss) income		(0.5	)		(58.2	)		76.5			(84.4	)
Comprehensive (loss) income (including noncontrolling interests)		(14.0	)		(62.4	)		433.6			289.7
Less: comprehensive income (loss) attributable to noncontrolling interests		10.8			21.4			(100.6	)		(107.7	)
Comprehensive (loss) income attributable to UGI Corporation	$	(3.2	)	$	(41.0	)	$	333.0		$	182.0

Other comprehensive (loss) income principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, 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.

Effective December 31, 2010, UGI Utilities merged the two defined benefit pension plans that it sponsors. In accordance with GAAP relating to accounting for retirement benefits, we were required to remeasure the merged plan’s assets and benefit obligations as of December 31, 2010 and record the funded status in the Condensed Consolidated Balance Sheet. Among other things, the remeasurement resulted in a decrease in regulatory assets (see Note 7) and an after-tax increase in other comprehensive income of $2.1 which is reflected in other comprehensive income in the nine months ended June 30, 2011.

Reclassifications. We have reclassified certain prior-year period balances to conform to the current-period presentation.

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

XML



Equity

9 Months Ended

Jun. 30, 2011

Equity [Abstract]

Equity

11. 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, 2011 and 2010:

				UGI Shareholders
									Accumulated
									Other
	Non-								Comprehensive
	controlling			Common		Retained			Income			Treasury			Total
	Interests			Stock		Earnings			(Loss)			Stock			Equity
Nine Months Ended June 30, 2011:
Balance September 30, 2010	$	237.1		$	906.1	$	966.7		$	(10.1	)	$	(38.2	)	$	2,061.6
Net income		101.8					255.3									357.1
Net gains on derivative instruments		14.8								10.8						25.6
Reclassifications of net (gains) losses on derivative instruments		(16.0	)							27.0						11.0
Benefit plans										2.1						2.1
Foreign currency translation adjustments										37.8						37.8
Comprehensive income		100.6					255.3			77.7						433.6
Dividends and distributions		(69.7	)				(84.7	)								(154.4	)
Equity transactions		0.5			28.8								9.6			38.9
Other		1.2														1.2
Balance June 30, 2011	$	269.7		$	934.9	$	1,137.3		$	67.6		$	(28.6	)	$	2,380.9
Nine Months Ended June 30, 2010:
Balance September 30, 2009	$	225.4		$	875.6	$	804.3		$	(38.9	)	$	(49.6	)	$	1,816.8
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	)
Equity transactions		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

XML



Inventories (Details) (USD $) In Millions	Jun. 30, 2011	Sep. 30, 2010	Jun. 30, 2010
Inventories
Total inventories	$ 271.6	$ 314.0	$ 249.2
Non-utility LPG and natural gas [Member]
Inventories
Total inventories	170.5	157.9	145.6
Gas Utility natural gas [Member]
Inventories
Total inventories	50.1	111.5	60.3
Materials, supplies and other [Member]
Inventories
Total inventories	$ 51.0	$ 44.6	$ 43.3

XML



Significant Accounting Policies (Details Textuals) (USD $) In Millions	9 Months Ended
	Jun. 30, 2011
Significant Accounting Policies (Textuals) [Abstract]
Other comprehensive income including associated after-tax charge	$ 2.1

XML



Subsequent Event - AmeriGas Refinancing

9 Months Ended

Jun. 30, 2011

Subsequent Event - AmeriGas Refinancing [Abstract]

Subsequent Event - AmeriGas Refinancing

15. Subsequent Event — AmeriGas Refinancing

On July 27, 2011, AmeriGas Partners announced an offer to purchase for cash any and all of its $350 aggregate principal amount of outstanding 7 1/8% Senior Notes (“the 2016 Notes”) due May 2016 (the “Tender Offer”), subject to receipt of the proceeds of the issuance of $450 of 6.25% Senior Notes due 2019 (the “6.25% Notes”). The 6.25% Notes are expected to be issued on August 10, 2011. The proceeds from the offering will be used to finance the Tender Offer and for general corporate purposes, including to repay borrowings outstanding under the AmeriGas 2011 Credit Agreement. The Partnership intends to redeem any 2016 Notes that are not tendered in the Tender Offer. The Partnership expects to record a loss of approximately $20.0 associated with these transactions during the fourth quarter of Fiscal 2011 which is expected to reduce net income attributable to UGI Corporation by approximately $6.0.

XML



Condensed Consolidated Balance Sheets (Unaudited) (USD $) In Millions	Jun. 30, 2011	Sep. 30, 2010	Jun. 30, 2010
Current assets
Cash and cash equivalents	$ 317.8	$ 260.7	$ 241.8
Restricted cash	10.2	34.8	22.9
Accounts receivable (less allowances for doubtful accounts of $45.0, $34.6 and $44.5, respectively)	595.7	467.8	503.4
Accrued utility revenues	7.4	14.0	9.7
Inventories	271.6	314.0	249.2
Deferred income taxes	26.8	32.6	26.7
Derivative financial instruments	10.5	11.3	17.5
Prepaid expenses and other current assets	50.2	84.9	40.4
Total current assets	1,290.2	1,220.1	1,111.6
Property, plant and equipment (less accumulated depreciation and amortization of $2,065.9, $1,916.5 and $1,866.2, respectively)	3,228.0	3,053.2	2,875.5
Goodwill	1,612.0	1,562.7	1,475.9
Intangible assets, net	159.5	150.1	138.1
Other assets	384.0	388.2	230.5
Total assets	6,673.7	6,374.3	5,831.6
Current liabilities:
Current maturities of long-term debt	38.5	573.6	572.9
Bank loans	206.1	200.4	35.2
Accounts payable	338.7	372.6	297.9
Derivative financial instruments	21.2	58.0	48.0
Other current liabilities	430.4	470.1	379.5
Total current liabilities	1,034.9	1,674.7	1,333.5
Long-term debt	2,039.5	1,432.2	1,456.8
Deferred income taxes	678.3	601.4	510.9
Deferred investment tax credits	5.0	5.3	5.4
Other noncurrent liabilities	535.1	599.1	531.0
Total liabilities	4,292.8	4,312.7	3,837.6
Commitments and contingencies (note 10)
UGI Corporation stockholders' equity:
UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,507,094, 115,400,294 and 115,375,794 shares, respectively)	934.9	906.1	896.1
Retained earnings	1,137.3	966.7	992.1
Accumulated other comprehensive income (loss)	67.6	(10.1)	(115.8)
Treasury stock, at cost	(28.6)	(38.2)	(42.4)
Total UGI Corporation stockholders' equity	2,111.2	1,824.5	1,730.0
Noncontrolling interests	269.7	237.1	264.0
Total equity	2,380.9	2,061.6	1,994.0
Total liabilities and equity	$ 6,673.7	$ 6,374.3	$ 5,831.6

XML



Intangible Assets (Details Textuals) (USD $) In Millions	3 Months Ended		9 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Component of Company's Intangible Assets (Textuals) [Abstract]
Amortization expense of intangible assets	$ 5.4	$ 4.9	$ 15.1	$ 14.8
Expected aggregate amortization expense of intangible assets for the next five fiscal years:
Fiscal 2011			5.0
Fiscal 2012			20.7
Fiscal 2013			20.1
Fiscal 2014			19.2
Fiscal 2015			$ 16.2

XML



Fair Value Measurement (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Millions	Jun. 30, 2011	Sep. 30, 2010	Jun. 30, 2010
Fair Value Inputs Level-1 [Member] | Commodity Contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	$ 0.6	$ 1.1	$ 0.4
Derivative financial instruments, liabilities	(12.2)	(49.4)	(25.4)
Fair Value Inputs Level-1 [Member] | Foreign currency contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	0	0	0
Derivative financial instruments, liabilities	0	0	0
Fair Value Inputs Level-1 [Member] | Interest Rate Contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	0
Derivative financial instruments, liabilities	0	0	0
Fair Value Inputs Level-2 [Member] | Commodity Contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	10.1	10.7	3.2
Derivative financial instruments, liabilities	(11.6)	(20.3)	(18.1)
Fair Value Inputs Level-2 [Member] | Foreign currency contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	0	0.8	16.9
Derivative financial instruments, liabilities	(6.1)	(2.9)	0
Fair Value Inputs Level-2 [Member] | Interest Rate Contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	5.0
Derivative financial instruments, liabilities	(3.6)	(18.5)	(16.4)
Fair Value, Inputs, Level 3 [Member] | Commodity Contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	0	0	0
Derivative financial instruments, liabilities	0	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign currency contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	0	0	0
Derivative financial instruments, liabilities	0	0	0
Fair Value, Inputs, Level 3 [Member] | Interest Rate Contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	0
Derivative financial instruments, liabilities	0	0	0
Commodity Contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	10.7	11.8	3.6
Derivative financial instruments, liabilities	(23.8)	(69.7)	(43.5)
Foreign currency contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	0	0.8	16.9
Derivative financial instruments, liabilities	(6.1)	(2.9)	0
Interest Rate Contracts [Member]
Assets, Fair Value Disclosure [Abstract]
Derivative financial instruments, assets	5.0
Derivative financial instruments, liabilities	$ (3.6)	$ (18.5)	$ (16.4)

XML



Subsequent Event - AmeriGas Refinancing (Details Textuals) (Refinancing of Debt [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Jun. 30, 2011	Jul. 27, 2011
Subsequent Event [Line Items]
Subsequent event date	Jul. 27, 2011
Expected Loss on extinguishment of debt		$ 20.0
Expected reduction of net income		6.0
7 1/8% Senior Notes Due 2016 [Member]
Subsequent Event [Line Items]
Aggregate prinicipal amount outstanding 7 1/8% senior notes		350.0
Interest rate on notes		7.125%
% Senior Notes Due 2019 [Member]
Subsequent Event [Line Items]
Proceeds of the issuance of senior notes due 2019		$ 450.0
Interest rate on notes		6.25%

XML



Defined Benefit Pension and Other Postretirement Plans (Details Textuals) (USD $) In Millions, unless otherwise specified	3 Months Ended	1 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended		9 Months Ended
	Dec. 31, 2010	Dec. 31, 2010 Pension Benefit [Member]	Dec. 31, 2010 Pension Benefit [Member]	Jun. 30, 2011 Pension Benefit [Member]	Jun. 30, 2011 Non-qualified Supplemental Executive Retirement Plan [Member]	Jun. 30, 2010 Non-qualified Supplemental Executive Retirement Plan [Member]	Jun. 30, 2011 Non-qualified Supplemental Executive Retirement Plan [Member]	Jun. 30, 2010 Non-qualified Supplemental Executive Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contribution to pensions plans in next twelve months				$ 16.0
Pension and other postretirement plans pretax expense					0.9	0.6	2.2	1.8
Contribution to the Pension Plan	1.8			16.7
Decrease in other noncurrent liabilities on remeasurement of merged plan's assets and benefit obligations		46.7	46.7
Decrease in regulatory assets on remeasurement of merged plan's assets and benefit obligations	43.1		43.1
Increase in pre-tax other comprehensive income on remeasurement of merged plan's assets and benefit obligations			3.6
Discount rate for the merged plan		5.50%	5.50%
Accumulated benefit obligation of the merged plan		$ 391.2	$ 391.2
Expected rate of return on plan assets		8.50%
Rate of increase in salary levels		3.80%

XML



Debt (Details) In Millions, unless otherwise specified	9 Months Ended			9 Months Ended		1 Months Ended		9 Months Ended			9 Months Ended				9 Months Ended		1 Months Ended	9 Months Ended
	Jun. 30, 2011 USD ($)	Jun. 30, 2011 AmeriGas 2011 Credit Agreement [Member] USD ($)	Jun. 30, 2011 AmeriGas 2011 Credit Agreement [Member] Letter of Credit [Member] USD ($)	Jun. 30, 2011 AmeriGas 2011 Credit Agreement [Member] Maximum [Member]	Jun. 30, 2011 AmeriGas 2011 Credit Agreement [Member] Minimum [Member]	Jun. 30, 2011 Existing Revolving Credit Agreement [Member] USD ($)	Jun. 30, 2011 Supplemented Credit Agreement Member] USD ($)	Jun. 30, 2011 Antargaz 2011 Senior Facilities [Member] EUR (€)	Jun. 30, 2011 Antargaz 2011 Senior Facilities [Member] Variable-rate Term Loan [Member] EUR (€)	Jun. 30, 2011 Antargaz 2011 Senior Facilities [Member] Revolving Credit Facility [Member] EUR (€)	Jun. 30, 2011 Antargaz 2011 Senior Facilities [Member] Maximum [Member]	Jun. 30, 2011 Antargaz 2011 Senior Facilities [Member] Minimum [Member]	Jun. 30, 2011 UGI Utilities 2011 Credit Agreement [Member]	May 25, 2011 UGI Utilities 2011 Credit Agreement [Member] USD ($)	Jun. 30, 2011 UGI Utilities 2011 Credit Agreement [Member] Maximum [Member]	Jun. 30, 2011 UGI Utilities 2011 Credit Agreement [Member] Minimum [Member]	May 31, 2011 UGI Utilities existing revolving credit agreement [Member] USD ($)	Jun. 30, 2011 Flaga multi-currency working capital facility [Member] EUR (€)	Jun. 30, 2011 Flaga euro-denominated working capital facility [Member] EUR (€)	Jun. 30, 2011 6.50% Senior Notes due 2021 [Member] USD ($)	Jun. 30, 2011 8.875% Senior Notes due May 2011 [Member] USD ($)	Jun. 30, 2011 7.25% Senior Notes [Member] USD ($)	Jun. 30, 2011 AmeriGas Propane [Member] USD ($)
Debt (Textuals) [Abstract]
Proceeds from issuance of senior notes									€ 380											$ 470
Repayment of Senior Notes																					14.6	415.0
Interest rate on notes																				6.50%	8.875%	7.25%
Loss on extinguishment of debt	18.8																						18.8
Borrowing capacity under revolving credit agreement		325								40				300				24	12
Debt compliance ratio								3.50					0.65
Revolving credit agreement sublimit for letters of credit			100											100
Borrowing capacity of credit agreement terminated						200	75										350
Interest rate for credit agreement		base rate plus a margin or at a two-week, one-, two-, three-, or six-month Eurodollar Rate						one-, two-, three- or six-month euribor, plus a margin.					LIBOR and the banks’ prime rate, plus a margin
Base rate for revolving credit agreement		higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate
Margin on credit agreement base rate borrowings				1.75%	0.75%						2.50%	1.75%			2.00%	0.00%
Margin on credit agreement Eurodollar rate borrowings				2.75%	1.75%
Credit agreement facility fee rate				0.50%	0.30%
Maturities under term loan, May 2014									38
Maturities under term loan, May 2015									34.2
Maturities under term loan, March 2016									307.8
Effective underlying euribor rate of interest on term loan through September 2015									2.45%
Effective underlying euribor rate of interest on term loan after September 2015									3.71%
Effective interest rate on term loan									4.66%
Payments guaranteed by UGI								100
Date of expiration extension																		September 2011	March 2012
Reduction in net income attributable to UGI Corporation due to extinguishment loss	$ 5.2

XML



Disclosures About Derivative Instruments and Hedging Activities (Details Textual) In Millions, unless otherwise specified	9 Months Ended					9 Months Ended															9 Months Ended					9 Months Ended		9 Months Ended
	Jun. 30, 2011 USD ($)	Sep. 30, 2010 USD ($)	Jun. 30, 2010 USD ($)	Jun. 30, 2011 Gas Utility [Member] Dekatherm	Jun. 30, 2010 Gas Utility [Member] Dekatherm	Jun. 30, 2010 AmeriGas Propane [Member] USD ($)	Jun. 30, 2011 Electric Utility - Forward Contract [Member] USD ($) Kilowatt-hour	Sep. 30, 2010 Electric Utility - Forward Contract [Member] USD ($)	Jun. 30, 2011 Midstream And Marketing's Natural Gas Member Dekatherm	Jun. 30, 2011 Midstream And Marketing's Propane Storage [Member] Gallons	Jun. 30, 2011 Electric transmission congestion - Electric Utility [Member] Kilowatt-hour	Jun. 30, 2010 Electric transmission congestion - Electric Utility [Member] Kilowatt-hour	Jun. 30, 2011 Electric transmission congestion (excluding Electric Utility) [Member] Kilowatt-hour	Jun. 30, 2010 Electric transmission congestion (excluding Electric Utility) [Member] Kilowatt-hour	Jun. 30, 2011 LPG [Member] Gallons	Jun. 30, 2010 LPG [Member] Gallons	Jun. 30, 2011 Natural Gas [Member] Dekatherm	Jun. 30, 2010 Natural Gas [Member] Dekatherm	Jun. 30, 2011 Electricity (millions of kilowatt-hours) Kilowatt-hour	Jun. 30, 2010 Electricity (millions of kilowatt-hours) Kilowatt-hour	Jun. 30, 2011 Antargaz [Member] EUR (€)	Jun. 30, 2011 Net Investment Hedges [Member] EUR (€)	Jun. 30, 2010 Net Investment Hedges [Member] EUR (€)	Jun. 30, 2011 Interest Rate Swaps [Member] EUR (€)	Jun. 30, 2010 Interest Rate Swaps [Member] EUR (€)	Jun. 30, 2011 Foreign Currency [Member] USD ($)	Jun. 30, 2010 Foreign Currency [Member] USD ($)	Jun. 30, 2011 IRPAs [Member] USD ($)	Mar. 31, 2010 IRPAs [Member] USD ($)
Derivative (Textual) [Abstract]
Notional amount (in units)				18,600,000	11,300,000		874,400,000		2,300,000	900,000	287,300,000	739,300,000	1,955,200,000	1,415,000,000	145,000,000	150,500,000	21,200,000	33,300,000	1,200,800,000	928,000,000
Maximum length of time hedged in price risk cash flow hedges				16 months			35 months						11 months		15 months		30 months		21 months							32 months
Maximum length of time hedged in price risk cash flow hedges																						March 2014
Maximum period of hedging exposure to variability in cash flows associated with price risk, weighted average															7 months		9 months		7 months							12 months
Underlying variable rate debt																					€ 0	€ 14.5	€ 48.3	€ 398.8	€ 706.2	$ 141.4	$ 72.8	$ 173.0
Debt Instrument Maturity Date																					Mar. 01, 2011
Loss as a result of the discontinuance of cash flow hedge accounting						12.2																						12.2
Minimum approximate range of estimated dollar-denominated purchases of LPG																										15.00%
Maximum approximate range of estimated dollar-denominated purchases of LPG																										30.00%
Long term debt not issued																													150
Fair values of electric utility's forward purchase power agreements	33.5		60.0				10.1	19.7
Disclosures About Derivative Instruments and Hedging Activities (Textuals) [Abstract]
Net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months	8.7
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	1.7
Amount of net gains associated with currency rate risk to be reclassified into earnings during the next 12 months	4.0
Restricted Cash in brokerage accounts	$ 10.2	$ 34.8	$ 22.9
Transmission organization that movements of wholesale electricity in number of states	14

XML



Segment Information (Details) (USD $) In Millions	3 Months Ended		9 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Sep. 30, 2010
Segment Informations [Abstract]
Revenues	$ 1,105.4	$ 961.9	$ 5,052.0	$ 4,701.0
Cost of sales	731.0	615.5	3,317.5	3,009.2
Segment profit:
Operating income (loss)	17.2	31.2	626.5	640.4
Loss from equity investees	(0.2)	(1.9)	(0.8)	(1.9)
Loss on extinguishment of debt			(18.8)
Interest expense	(35.0)	(33.6)	(102.6)	(101.9)
(Loss) income before income taxes	(18.0)	(4.3)	504.3	536.6
Noncontrolling interests' net loss	(6.3)	(7.6)	101.8	115.2
Depreciation and amortization	57.8	51.7	168.6	157.3
Capital expenditures	78.5	83.1	246.1	229.4
Total assets (at period end)	6,673.7	5,831.6	6,673.7	5,831.6	6,374.3
Bank loans (at period end)	206.1	35.2	206.1	35.2	200.4
Goodwill (at period end)	1,612.0	1,475.9	1,612.0	1,475.9	1,562.7
Elims [Member]
Segment Informations [Abstract]
Revenues	(40.0)	(22.2)	(172.9)	(146.9)
Cost of sales	(39.1)	(20.7)	(170.3)	(142.3)
Segment profit:
Operating income (loss)		(0.4)	0.2	(0.7)
(Loss) income before income taxes		(0.4)	0.2	(0.7)
Noncontrolling interests' net loss		0.1		0.1
Depreciation and amortization				(0.1)
Total assets (at period end)	(81.0)	(69.3)	(81.0)	(69.3)
Goodwill (at period end)		(3.9)		(3.9)
AmeriGas Propane [Member]
Segment Informations [Abstract]
Revenues	470.8	396.6	2,077.8	1,939.3
Cost of sales	300.8	235.8	1,300.9	1,165.1
Segment profit:
Operating income (loss)	6.7	5.3	252.9	261.2
Loss on extinguishment of debt			(18.8)
Interest expense	(15.7)	(17.0)	(47.4)	(50.2)
(Loss) income before income taxes	(9.0)	(11.7)	186.7	211.0
Partnership EBITDA	31.1	27.2	301.9	323.7
Noncontrolling interests' net loss	(6.1)	(7.5)	101.2	114.5
Depreciation and amortization	24.5	21.8	70.4	65.0
Capital expenditures	18.6	14.4	59.2	59.8
Total assets (at period end)	1,772.1	1,658.4	1,772.1	1,658.4
Bank loans (at period end)	176.0	15.0	176.0	15.0
Goodwill (at period end)	695.8	674.8	695.8	674.8
Gas Utility [Member]
Segment Informations [Abstract]
Revenues	148.1	149.1	921.7	922.3
Cost of sales	78.8	83.0	562.3	584.2
Segment profit:
Operating income (loss)	17.2	13.8	193.2	168.6
Interest expense	(9.9)	(10.0)	(30.2)	(30.5)
(Loss) income before income taxes	7.3	3.8	163.0	138.1
Depreciation and amortization	11.6	12.5	36.1	37.0
Capital expenditures	20.9	16.1	54.5	40.6
Total assets (at period end)	2,002.0	1,829.4	2,002.0	1,829.4
Goodwill (at period end)	180.1	180.1	180.1	180.1
Electric Utility [Member]
Segment Informations [Abstract]
Revenues	24.1	25.3	84.7	90.9
Cost of sales	14.6	15.8	53.4	58.0
Segment profit:
Operating income (loss)	2.4	2.6	9.0	11.1
Interest expense	(0.7)	(0.4)	(1.8)	(1.3)
(Loss) income before income taxes	1.7	2.2	7.2	9.8
Depreciation and amortization	1.1	1.0	3.1	3.0
Capital expenditures	1.0	2.3	5.1	3.9
Total assets (at period end)	156.5	120.4	156.5	120.4
Energy Services [Member]
Segment Informations [Abstract]
Revenues	217.1	198.6	857.0	949.5
Cost of sales	193.1	177.3	738.6	830.9
Segment profit:
Operating income (loss)	8.4	6.9	76.7	75.4
Interest expense	(0.6)		(2.0)
(Loss) income before income taxes	7.8	6.9	74.7	75.4
Depreciation and amortization	1.8	2.0	5.4	6.0
Capital expenditures	18.7	34.3	81.5	84.7
Total assets (at period end)	572.2	463.3	572.2	463.3
Goodwill (at period end)	2.8	11.8	2.8	11.8
International Propane, Antargaz [Member]
Segment Informations [Abstract]
Revenues	161.0	150.8	889.7	755.3
Cost of sales	95.3	81.9	554.0	394.4
Segment profit:
Operating income (loss)	(11.4)	4.3	101.0	123.4
Loss from equity investees	(0.2)	(1.9)	(0.8)	(1.8)
Interest expense	(7.1)	(5.3)	(18.5)	(17.1)
(Loss) income before income taxes	(18.7)	(2.9)	81.7	104.5
Noncontrolling interests' net loss	(0.2)	(0.2)	0.6	0.6
Depreciation and amortization	13.5	11.5	38.4	37.2
Capital expenditures	12.0	12.8	31.8	32.1
Total assets (at period end)	1,678.2	1,446.4	1,678.2	1,446.4
Goodwill (at period end)	641.1	540.6	641.1	540.6
International Propane, Other [Member]
Segment Informations [Abstract]
Revenues	102.3	41.0	332.4	129.8
Cost of sales	74.6	30.0	243.8	86.8
Segment profit:
Operating income (loss)	(3.6)	(1.4)	(0.2)	4.2
Loss from equity investees				(0.1)
Interest expense	(0.8)	(0.7)	(2.1)	(2.3)
(Loss) income before income taxes	(4.4)	(2.1)	(2.3)	1.8
Depreciation and amortization	4.7	2.6	13.7	8.2
Capital expenditures	6.6	2.0	12.6	5.7
Total assets (at period end)	407.3	231.2	407.3	231.2
Bank loans (at period end)	30.1	20.2	30.1	20.2
Goodwill (at period end)	85.3	65.6	85.3	65.6
Corporate And Other [Member]
Segment Informations [Abstract]
Revenues	22.0	22.7	61.6	60.8
Cost of sales	12.9	12.4	34.8	32.1
Segment profit:
Operating income (loss)	(2.5)	0.1	(6.3)	(2.8)
Interest expense	(0.2)	(0.2)	(0.6)	(0.5)
(Loss) income before income taxes	(2.7)	(0.1)	(6.9)	(3.3)
Depreciation and amortization	0.6	0.3	1.5	1.0
Capital expenditures	0.7	1.2	1.4	2.6
Total assets (at period end)	166.4	151.8	166.4	151.8
Goodwill (at period end)	$ 6.9	$ 6.9	$ 6.9	$ 6.9