10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2013

OR

¨ 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	23-2668356
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
460 North Gulph Road, King of Prussia, PA	19406
(Address of principal executive offices)	(Zip Code)

(610) 337-1000

(Registrant’s telephone number, including area code)

______________________________________

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  ý    No  ¨

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 ý    No  ¨

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	ý	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	¨

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

At July 31, 2013, there were 114,098,006 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, 2013, September 30, 2012 and June 30, 2012	1
Condensed Consolidated Statements of Income for the three and nine months ended June 30, 2013 and 2012	2
Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended June 30, 2013 and 2012	3
Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2013 and 2012	4
Condensed Consolidated Statements of Changes in Equity for the nine months ended June 30, 2013 and 2012	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	41
Item 4. Controls and Procedures	44
Part II Other Information
Item 1. Legal Proceedings	45
Item 1A. Risk Factors	45
Item 6. Exhibits	46
Signatures	47

- i -

UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Millions of dollars)

	June 30, 2013			September 30, 2012			June 30, 2012
ASSETS
Current assets:
Cash and cash equivalents	$	401.8		$	319.9		$	436.5
Restricted cash	6.0			3.0			7.6
Accounts receivable (less allowances for doubtful accounts of $48.0, $36.1 and $45.7, respectively)	752.6			632.6			624.9
Accrued utility revenues	11.8			16.9			15.0
Inventories	304.0			356.9			317.3
Deferred income taxes	27.3			56.8			52.3
Utility regulatory assets	3.7			6.5			2.7
Derivative financial instruments	18.7			13.2			21.6
Prepaid expenses and other current assets	36.1			98.7			59.4
Total current assets	1,562.0			1,504.5			1,537.3
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,495.4, $2,286.0 and $2,226.8, respectively)	4,325.0			4,233.1			4,188.9
Goodwill	2,834.0			2,818.3			2,756.0
Intangible assets, net	608.6			658.2			717.7
Other assets	499.2			495.6			452.3
Total assets	$	9,828.8		$	9,709.7		$	9,652.2
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	195.6		$	166.7		$	86.1
Bank loans	135.9			165.1			187.3
Accounts payable	384.5			411.3			346.0
Derivative financial instruments	56.8			100.9			116.5
Other current liabilities	552.9			643.0			577.4
Total current liabilities	1,325.7			1,487.0			1,313.3
Long-term debt	3,298.2			3,347.6			3,475.1
Deferred income taxes	956.9			935.0			832.8
Deferred investment tax credits	4.4			4.6			4.7
Other noncurrent liabilities	613.5			616.7			589.5
Total liabilities	6,198.7			6,390.9			6,215.4
Commitments and contingencies (note 11)
Equity:
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized—300,000,000 shares; issued — 115,759,694, 115,624,594 and 115,623,094 shares, respectively)	1,192.9			1,157.7			1,148.8
Retained earnings	1,361.9			1,166.1			1,211.2
Accumulated other comprehensive loss	(30.7		)	(62.0		)	(77.7		)
Treasury stock, at cost	(26.2		)	(28.7		)	(24.3		)
Total UGI Corporation stockholders’ equity	2,497.9			2,233.1			2,258.0
Noncontrolling interests, principally in AmeriGas Partners	1,132.2			1,085.7			1,178.8
Total equity	3,630.1			3,318.8			3,436.8
Total liabilities and equity	$	9,828.8		$	9,709.7		$	9,652.2

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Millions of dollars, except per share amounts)

	Three Months Ended June 30,						Nine Months Ended June 30,
	2013			2012			2013			2012
Revenues	$	1,372.3		$	1,277.2		$	5,932.6		$	5,393.5
Costs and expenses:
Cost of sales (excluding depreciation shown below)	827.9			810.2			3,547.3			3,438.6
Operating and administrative expenses	404.7			405.8			1,297.4			1,191.5
Utility taxes other than income taxes	3.7			3.9			12.7			12.9
Depreciation	76.5			69.5			220.0			191.0
Amortization	15.4			15.1			46.3			36.7
Other income, net	(9.0		)	(8.1		)	(26.5		)	(27.1		)
	1,319.2			1,296.4			5,097.2			4,843.6
Operating income (loss)	53.1			(19.2		)	835.4			549.9
(Loss) income from equity investees	—			(0.1		)	0.1			(0.2		)
Gain (loss) on extinguishments of debt	—			0.1			—			(13.3		)
Interest expense	(59.2		)	(61.3		)	(179.6		)	(162.6		)
(Loss) income before income taxes	(6.1		)	(80.5		)	655.9			373.8
Income tax (expense) benefit	(9.0		)	4.0			(174.1		)	(113.2		)
Net (loss) income	(15.1		)	(76.5		)	481.8			260.6
Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners	29.8			70.2			(192.6		)	(46.5		)
Net income (loss) attributable to UGI Corporation	$	14.7		$	(6.3	)	$	289.2		$	214.1
Earnings (loss) per common share attributable to UGI Corporation stockholders:
Basic	$	0.13		$	(0.06	)	$	2.54		$	1.90
Diluted	$	0.13		$	(0.06	)	$	2.51		$	1.89
Average common shares outstanding (thousands):
Basic	114,240			112,726			113,693			112,484
Diluted	116,196			112,726			115,275			113,295
Dividends declared per common share	$	0.2825		$	0.27		$	0.8225		$	0.79

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(Millions of dollars)

	Three Months Ended June 30,						Nine Months Ended June 30,
	2013			2012			2013			2012
Net (loss) income	$	(15.1	)	$	(76.5	)	$	481.8		$	260.6
Other comprehensive income (loss):
Net losses on derivative instruments (net of tax of $(1.9), $9.3, $(4.5) and $48.6, respectively)	(11.0		)	(63.2		)	(11.1		)	(143.9		)
Reclassifications of net losses on derivative instruments (net of tax of $(1.6), $(9.5), $(15.1) and $(31.3), respectively)	8.9			24.8			59.7			69.5
Foreign currency adjustments (net of tax of $(2.4), $11.2, $1.8 and $9.7, respectively)	8.8			(35.6		)	1.3			(33.9		)
Benefit plans (net of tax of $(0.2), $(0.0), $(0.7) and $(0.2), respectively)	0.3			0.1			1.1			0.3
Other comprehensive income (loss)	7.0			(73.9		)	51.0			(108.0		)
Comprehensive (loss) income	(8.1		)	(150.4		)	532.8			152.6
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	37.8			107.3			(212.2		)	(0.4		)
Comprehensive income (loss) attributable to UGI Corporation	$	29.7		$	(43.1	)	$	320.6		$	152.2

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Millions of dollars)

	Nine Months Ended June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	481.8		$	260.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	266.3			227.7
Deferred income taxes, net	35.5			9.9
Provision for uncollectible accounts	23.9			21.3
Net change in realized gains and losses deferred as cash flow hedges	5.0			(11.7		)
Loss on extinguishments of debt, net	—			13.3
Other, net	(11.3		)	2.6
Net change in:
Accounts receivable and accrued utility revenues	(141.1		)	71.2
Inventories	54.1			128.1
Utility deferred fuel costs, net of changes in unsettled derivatives	20.5			8.1
Accounts payable	(26.9		)	(132.2		)
Other current assets	52.4			22.8
Other current liabilities	(73.8		)	(55.5		)
Net cash provided by operating activities	686.4			566.2
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(291.6		)	(236.0		)
Acquisitions of businesses, net of cash acquired	(24.3		)	(1,573.7		)
(Increase) decrease in restricted cash	(3.0		)	9.6
Other, net	2.2			0.1
Net cash used by investing activities	(316.7		)	(1,800.0		)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(93.4		)	(88.7		)
Distributions on AmeriGas Partners Common Units	(168.5		)	(126.5		)
Issuances of debt	—			1,550.4
Repayments of debt	(28.5		)	(240.1		)
(Decrease) increase in bank loans	(39.0		)	54.2
Receivables Facility net borrowings (repayments)	9.5			(4.3		)
Issuances of UGI Common Stock	28.5			12.7
Issuance of AmeriGas Partners Common Units	—			276.6
Other	5.4			0.5
Net cash (used) provided by financing activities	(286.0		)	1,434.8
EFFECT OF EXCHANGE RATE CHANGES ON CASH	(1.8		)	(3.0		)
Cash and cash equivalents increase	$	81.9		$	198.0
Cash and cash equivalents:
End of period	$	401.8		$	436.5
Beginning of period	319.9			238.5
Increase	$	81.9		$	198.0

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(Millions of dollars)

	Nine Months Ended June 30,
	2013			2012
Common stock, without par value
Balance, beginning of period	$	1,157.7		$	937.4
Common Stock issued in connection with employee and director plans, net of tax withheld	19.7			7.6
Dividend reinvestment plan	1.4			1.6
Excess tax benefits realized on equity-based compensation	5.7			0.8
Stock-based compensation expense	8.4			7.0
Adjustments to reflect change in ownership of AmeriGas Partners, net of tax	—			194.4
Balance, end of period	$	1,192.9		$	1,148.8
Retained earnings
Balance, beginning of period	$	1,166.1		$	1,085.8
Net income attributable to UGI Corporation	289.2			214.1
Cash dividends on Common Stock	(93.4		)	(88.7		)
Balance, end of period	$	1,361.9		$	1,211.2
Accumulated other comprehensive income (loss)
Balance, beginning of period	$	(62.0	)	$	(17.7	)
Net gains (losses) on derivative instruments, net of tax	6.6			(74.1		)
Reclassification of net losses on derivative instruments, net of tax	22.3			45.8
Benefit plans, net of tax	1.1			0.3
Adjustments to reflect change in ownership of AmeriGas Partners, net of tax	—			1.9
Foreign currency, net of tax	1.3			(33.9		)
Balance, end of period	$	(30.7	)	$	(77.7	)
Treasury stock
Balance, beginning of period	$	(28.7	)	$	(27.8	)
Common Stock issued in connection with employee and director plans, net of tax withheld	20.8			2.9
Dividend reinvestment plan	0.8			0.6
Reacquired common stock - employee and director plans	(19.1		)	—
Balance, end of period	$	(26.2	)	$	(24.3	)
Total UGI Corporation stockholders’ equity	$	2,497.9		$	2,258.0
Noncontrolling interests
Balance, beginning of period	$	1,085.7		$	213.4
Net income attributable to noncontrolling interests, principally in AmeriGas Partners	192.6			46.5
Net losses on derivative instruments	(17.8		)	(69.8		)
Reclassification of net losses on derivative instruments	37.4			23.7
Dividends and distributions	(168.7		)	(126.8		)
AmeriGas Partners Common Unit public offering	—			276.6
AmeriGas Partners Common Units issued for Heritage Acquisition	—			1,132.6
Adjustments to reflect change in ownership of AmeriGas Partners	—			(321.4		)
Other	3.0			4.0
Balance, end of period	$	1,132.2		$	1,178.8
Total equity	$	3,630.1		$	3,436.8

See accompanying notes to condensed consolidated financial statements.

- 5 -

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 (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; (3) own all or a portion of electricity generation facilities; and (4) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering 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 retail propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”). AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”) and prior to its merger with AmeriGas OLP on July 1, 2013 (the “Merger”), AmeriGas OLP’s principal operating subsidiary Heritage Operating, L.P. (“HOLP”). AmeriGas OLP and HOLP, prior to the Merger are collectively referred to herein as 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, 2013, the General Partner held a 1% general partner interest and 25.3% limited partner interest in AmeriGas Partners and an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises 39,492,279 publicly held Common Units and 29,567,362 Common Units held by a subsidiary of Energy Transfer Partners, L.P. (“ETP”) as a result of the January 12, 2012, acquisition of substantially all of ETP's propane operations (“Heritage Propane”). In July 2013, ETP sold 7,500,000 of the Common Units it held in an underwritten public offering. AmeriGas Partners did not receive any proceeds from the sale of the Common Units by ETP.

Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries conducts (1) an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“Antargaz”); (2) an LPG distribution business in central, northern and eastern Europe (“Flaga”); (3) an LPG distribution business in the United Kingdom (“AvantiGas”); and (4) an LPG distribution business in the Nantong region of China. We refer to our foreign LPG operations collectively as “International Propane.”

Enterprises, through UGI Energy Services, Inc. (“Energy Services”) and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage, natural gas gathering 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 electricity generation facilities located in Pennsylvania. These businesses 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 a first-tier subsidiary. 

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.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, 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 report the public’s and ETP’s limited partner interests in the Partnership, and outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests.We eliminate all significant intercompany accounts and transactions when we consolidate. Entities in which we do not have control but have significant influence over operating and financial policies are accounted for by the equity method.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

The 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 that 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, 2012, condensed consolidated balance sheet data was derived from audited financial statements but does 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, 2012 (“Company’s 2012 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 brokerage accounts that are restricted from withdrawal.

Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders 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 June 30,		Nine Months Ended June 30,
	2013	2012	2013	2012
Denominator (thousands of shares):
Average common shares outstanding for basic computation	114,240	112,726	113,693	112,484
Incremental shares issuable for stock options and awards	1,956	—	1,582	811
Average common shares outstanding for diluted computation	116,196	112,726	115,275	113,295

Comprehensive Income. Comprehensive income (loss) comprises net income (loss) and other comprehensive income (loss). Other comprehensive income (loss) 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 and intracompany transaction adjustments.

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

Income Taxes. During the three months ended December 31, 2011, the Company changed the U.S. tax status of a foreign entity. As a result of the change in tax status, we concluded that it was more likely than not that a portion of our foreign tax credits would be utilized and, accordingly, adjusted our foreign tax credit valuation allowance which reduced income tax expense by $4.7 for the nine months ended June 30, 2012.

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.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

3. Accounting Changes

New Accounting Standards Not Yet Adopted

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In February 2013, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance regarding disclosures for items reclassified out of accumulated other comprehensive income (“AOCI”). The new disclosure guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2012. The new disclosures are to be applied prospectively, and early adoption is permitted. We expect to adopt the new guidance in Fiscal 2014. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

Disclosures about Offsetting Assets and Liabilities.In December 2011 (and amended in January 2013), the FASB issued new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 (Fiscal 2014) and interim periods within those annual periods, and is required to be applied retrospectively. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

4. Partnership Acquisition of Heritage Propane

On January 12, 2012, AmeriGas Partners completed the acquisition of Heritage Propane from ETP for total consideration of $2,604.8 comprising $1,472.2 in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of approximately $1,132.6 (the “Heritage Acquisition”). The Heritage Acquisition was consummated pursuant to a Contribution and Redemption Agreement, dated October 15, 2011, as amended (the “Contribution Agreement”), by and among AmeriGas Partners, ETP, Energy Transfer Partners GP, L.P., the general partner of ETP, and Heritage ETC, L.P. For additional information on the Heritage Acquisition, see Note 4 to the Company’s 2012 Annual Financial Statements and Notes.

The following presents unaudited pro forma income statement and earnings per share data as if the Heritage Acquisition had occurred on October 1, 2011:

	Nine Months Ended June 30,
	2013 (As Reported)		2012 Pro Forma
Revenues	$	5,932.6	$	5,885.2
Net income attributable to UGI Corporation	$	289.2	$	211.4
Earnings per common share attributable to UGI Corporation stockholders:
Basic	$	2.54	$	1.88
Diluted	$	2.51	$	1.87

The unaudited pro forma results of operations reflect Heritage Propane’s historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The unaudited pro forma consolidated results of operations are not necessarily indicative of the results that would have occurred had the Heritage Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

5. Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following:

	June 30, 2013			September 30, 2012			June 30, 2012
Goodwill (not subject to amortization)	$	2,834.0		$	2,818.3		$	2,756.0
Intangible assets:
Customer relationships, noncompete agreements and other	$	692.6		$	691.9		$	689.3
Trademarks and tradenames (not subject to amortization)	128.4			137.2			189.6
Gross carrying amount	821.0			829.1			878.9
Accumulated amortization	(212.4		)	(170.9		)	(161.2		)
Intangible assets, net	$	608.6		$	658.2		$	717.7

The decrease in trademarks and tradenames and the increase in goodwill during the nine months ended June 30, 2013, principally reflects a correcting adjustment associated with the Heritage Acquisition. Amortization expense of intangible assets was $13.3 and $40.2 for the three and nine months ended June 30, 2013, respectively, and $12.4 and $31.2 for the three and nine months ended June 30, 2012, respectively. No amortization is included in cost of sales in the Condensed Consolidated Statements of Income. As of June 30, 2013, our expected aggregate amortization expense of intangible assets for the remainder of Fiscal 2013 and for the next four fiscal years is as follows: remainder of Fiscal 2013 — $12.5; Fiscal 2014 — $50.5; Fiscal 2015 — $47.4; Fiscal 2016 — $41.3; Fiscal 2017 — $35.0.

- 9 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

6. Segment Information

Our operations comprise six reportable segments generally based upon products sold, geographic location and regulatory environment. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) Gas Utility; (5) Energy Services; and (6) Electric Generation. We refer to both international segments together as “International Propane” and Energy Services and Electric Generation together as “Midstream & Marketing.” For Fiscal 2012, the Company began reporting its Electric Generation operating segment as a separate reportable segment and our former Electric Utility reportable segment was combined with Corporate & Other. Previously, the Electric Generation operating segment was included in the Energy Services reportable segment. Segment information for the three and nine months ended June 30, 2012 presented below has been adjusted to conform to the current year presentation.

The accounting policies of our reportable segments are the same as those described in Note 2, “Significant Accounting Policies” in the Company’s 2012 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 other reportable segments principally based upon their income before income taxes.

Three Months Ended June 30, 2013:

														Midstream & Marketing					International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	1,372.3		$	(61.5	)	(c)	$	581.7		$	126.7		$	233.0		$	15.7	$	249.2		$	182.5		$	45.0
Cost of sales	$	827.9		$	(60.1	)	(c)	$	305.7		$	52.4		$	213.9		$	7.7	$	148.7		$	134.8		$	24.8
Segment profit:
Operating income (loss)	$	53.1		$	(0.2	)		$	6.6		$	16.1		$	7.4		$	0.8	$	14.5		$	6.5		$	1.4
Income from equity investees	—			—				—			—			—			—		—			—			—
Interest expense	(59.2		)	—				(41.2		)	(9.2		)	(0.6		)	—		(6.2		)	(1.2		)	(0.8		)
(Loss) income before income taxes	$	(6.1	)	$	(0.2	)		$	(34.6	)	$	6.9		$	6.8		$	0.8	$	8.3		$	5.3		$	0.6
Partnership EBITDA (a)								$	59.1
Noncontrolling interests’ net income (loss)	$	(29.8	)	$	—			$	(29.6	)	$	—		$	—		$	—	$	(0.3	)	$	0.1		$	—
Depreciation and amortization	$	91.9		$	(0.1	)		$	52.5		$	13.1		$	2.1		$	2.6	$	14.0		$	6.1		$	1.6
Capital expenditures	$	107.6		$	(0.1	)		$	26.3		$	37.3		$	22.0		$	4.4	$	11.7		$	4.0		$	2.0
Total assets (at period end)	$	9,828.8		$	(95.9	)		$	4,388.1		$	2,164.4		$	437.0		$	267.2	$	1,771.7		$	543.1		$	353.2
Bank loans (at period end)	$	135.9		$	—			$	80.0		$	—		$	45.5		$	—	$	—		$	10.4		$	—
Goodwill (at period end)	$	2,834.0		$	—			$	1,929.2		$	182.1		$	2.8		$	—	$	619.2		$	93.7		$	7.0

- 10 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Three Months Ended June 30, 2012:

														Midstream & Marketing						International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation			Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	1,277.2		$	(33.4	)	(c)	$	571.9		$	122.3		$	157.0		$	10.9		$	211.8		$	193.4		$	43.3
Cost of sales	$	810.2		$	(32.1	)	(c)	$	334.0		$	51.4		$	140.0		$	6.4		$	133.6		$	153.0		$	23.9
Segment profit:
Operating (loss) income	$	(19.2	)	$	—			$	(48.4	)	$	22.5		$	6.8		$	(1.9	)	$	(1.2	)	$	2.4		$	0.6
Income from equity investees	(0.1		)	—				—			—			—			—			(0.1		)	—			—
Gain on extinguishments of debt	0.1			—				0.1			—			—			—			—			—			—
Interest expense	(61.3		)	—				(41.8		)	(9.9		)	(1.2		)	—			(6.3		)	(1.2		)	(0.9		)
(Loss) income before income taxes	$	(80.5	)	$	—			$	(90.1	)	$	12.6		$	5.6		$	(1.9	)	$	(7.6	)	$	1.2		$	(0.3	)
Partnership EBITDA (a)								$	1.8
Noncontrolling interests’ net loss	$	(70.2	)	$	—			$	(70.0	)	$	—		$	—		$	—		$	(0.2	)	$	—		$	—
Depreciation and amortization	$	84.6		$	—			$	49.5		$	12.3		$	0.9		$	2.3		$	13.5		$	4.7		$	1.4
Capital expenditures	$	83.7		$	—			$	25.2		$	29.0		$	7.3		$	6.3		$	12.0		$	2.8		$	1.1
Total assets (at period end)	$	9,652.2		$	(87.4	)		$	4,579.5		$	2,027.0		$	355.0		$	261.3		$	1,664.7		$	513.2		$	338.9
Bank loans (at period end)	$	187.3		$	—			$	68.8		$	—		$	95.0		$	—		$	—		$	23.5		$	—
Goodwill (at period end)	$	2,756.0		$	—			$	1,866.7		$	182.1		$	2.8		$	—		$	605.0		$	92.4		$	7.0

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

Three Months Ended June 30,	2013			2012
Partnership EBITDA	$	59.1		1.8
Depreciation and amortization	(52.5		)	(49.5		)
Gain on extinguishments of debt	—			(0.1		)
Noncontrolling interests (i)	—			(0.6		)
Operating income (loss)	$	6.6		$	(48.4	)

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

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

- 11 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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

Nine Months Ended June 30, 2013:

														Midstream & Marketing					International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	5,932.6		$	(181.1	)	(c)	$	2,634.6		$	743.6		$	764.8		$	47.7	$	1,121.1		$	659.0		$	142.9
Cost of sales	$	3,547.3		$	(176.2	)	(c)	$	1,370.2		$	372.7		$	648.8		$	27.9	$	714.4		$	507.1		$	82.4
Segment profit:
Operating income	$	835.4		$	(1.1	)		$	403.9		$	191.6		$	78.2		$	1.5	$	129.8		$	30.6		$	0.9
Income from equity investees	0.1			—				—			—			—			—		0.1			—			—
Interest expense	(179.6		)	—				(124.2		)	(28.1		)	(2.4		)	—		(19.0		)	(3.8		)	(2.1		)
Income (loss) before income taxes	$	655.9		$	(1.1	)		$	279.7		$	163.5		$	75.8		$	1.5	$	110.9		$	26.8		$	(1.2	)
Partnership EBITDA (a)								$	550.5
Noncontrolling interests’ net income	$	192.6		$	—			$	192.4		$	—		$	—		$	—	$	0.1		$	0.1		$	—
Depreciation and amortization	$	266.3		$	(0.1	)		$	150.5		$	38.4		$	5.6		$	7.5	$	42.3		$	17.4		$	4.7
Capital expenditures	$	292.5		$	(1.1	)		$	80.7		$	90.2		$	54.8		$	15.4	$	37.1		$	10.3		$	5.1
Total assets (at period end)	$	9,828.8		$	(95.9	)		$	4,388.1		$	2,164.4		$	437.0		$	267.2	$	1,771.7		$	543.1		$	353.2
Bank loans (at period end)	$	135.9		$	—			$	80.0		$	—		$	45.5		$	—	$	—		$	10.4		$	—
Goodwill (at period end)	$	2,834.0		$	—			$	1,929.2		$	182.1		$	2.8		$	—	$	619.2		$	93.7		$	7.0

- 12 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Nine Months Ended June 30, 2012:

														Midstream & Marketing						International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation			Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	5,393.5		$	(134.2	)	(c)	$	2,411.3		$	696.8		$	652.5		$	27.1		$	958.7		$	646.5		$	134.8
Cost of sales	$	3,438.6		$	(130.7	)	(c)	$	1,447.8		$	370.6		$	553.1		$	17.6		$	597.9		$	506.3		$	76.0
Segment profit:
Operating income (loss)	$	549.9		$	—			$	206.7		$	168.7		$	67.3		$	(7.9	)	$	96.3		$	16.8		$	2.0
Loss from equity investees	(0.2		)	—				—			—			—			—			(0.2		)	—			—
Loss on extinguishments of debt	(13.3		)	—				(13.3		)	—			—			—			—			—			—
Interest expense	(162.6		)	—				(103.4		)	(30.1		)	(3.6		)	—			(19.7		)	(3.4		)	(2.4		)
Income (loss) before income taxes	$	373.8		$	—			$	90.0		$	138.6		$	63.7		$	(7.9	)	$	76.4		$	13.4		$	(0.4	)
Partnership EBITDA (a)								$	310.0
Noncontrolling interests’ net income	$	46.5		$	—			$	46.2		$	—		$	—		$	—		$	0.3		$	—		$	—
Depreciation and amortization	$	227.7		$	—			$	118.5		$	36.6		$	2.4		$	6.6		$	42.6		$	16.6		$	4.4
Capital expenditures	$	237.7		$	—			$	70.3		$	76.5		$	30.2		$	17.4		$	28.0		$	11.5		$	3.8
Total assets (at period end)	$	9,652.2		$	(87.4	)		$	4,579.5		$	2,027.0		$	355.0		$	261.3		$	1,664.7		$	513.2		$	338.9
Bank loans (at period end)	$	187.3		$	—			$	68.8		$	—		$	95.0		$	—		$	—		$	23.5		$	—
Goodwill (at period end)	$	2,756.0		$	—			$	1,866.7		$	182.1		$	2.8		$	—		$	605.0		$	92.4		$	7.0

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

Nine Months Ended June 30,	2013			2012
Partnership EBITDA	$	550.5		$	310.0
Depreciation and amortization	(150.5		)	(118.5		)
Loss on extinguishments of debt	—			13.3
Noncontrolling interests (i)	3.9			1.9
Operating income	$	403.9		$	206.7

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

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

- 13 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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

- 14 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

7. Energy Services Accounts Receivable Securitization Facility

Energy Services currently has a $100 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper that expires in November 2013. 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. 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.

During the nine months ended June 30, 2013 and 2012, Energy Services transferred trade receivables to ESFC totaling $766.1 and $674.4, respectively. During the nine months ended June 30, 2013 and 2012, ESFC sold an aggregate $224.0 and $266.5, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At June 30, 2013, the outstanding balance of ESFC receivables was $58.2 and there was $9.5 sold to the commercial paper conduit. At June 30, 2012, the outstanding balance of ESFC receivables was $41.0 and there was $10.0 sold to the commercial paper conduit.

8. 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 2012 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, 2013		September 30, 2012		June 30, 2012
Regulatory assets:
Income taxes recoverable	$	104.7	$	103.2	$	99.9
Underfunded pension and postretirement plans	177.8		188.2		144.6
Environmental costs	16.6		16.8		16.6
Deferred fuel and power costs	4.1		11.6		9.8
Removal costs, net	12.1		12.7		11.8
Other	5.6		5.9		8.3
Total regulatory assets	$	320.9	$	338.4	$	291.0
Regulatory liabilities:
Postretirement benefits	$	14.2	$	13.1	$	12.3
Environmental overcollections	2.9		2.9		3.7
Deferred fuel and power refunds	14.2		4.4		10.3
State tax benefits—distribution system repairs	8.0		7.4		7.0
Other	0.7		0.5		0.7
Total regulatory liabilities	$	40.0	$	28.3	$	34.0

Deferred fuel and power—costs and refunds. Gas Utility’s tariffs and Electric Utility’s 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 overcollected costs are classified as a regulatory liability.

- 15 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Gas Utility uses derivative financial instruments to reduce volatility in the cost of natural gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at June 30, 2013, September 30, 2012 and June 30, 2012 were $(1.4), $5.3 and $0.3, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts do not currently qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the Condensed Consolidated Balance Sheets with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At June 30, 2013, September 30, 2012, and June 30, 2012, the fair values of Electric Utility’s electricity supply contracts were net losses of $6.1, $9.2 and $13.1, 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, realized and unrealized gains or losses on FTRs are included in deferred fuel and power—costs or refunds. Unrealized gains or losses on FTRs at June 30, 2013, September 30, 2012, and June 30, 2012, were not material.

Allentown, Pennsylvania Natural Gas Incident. On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff's formal complaint, issued on June 11, 2012, pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage. On February 19, 2013, the PUC entered a final order (the “Final Order”) in which PUC Commissioners adopted the Joint Settlement, with certain modifications. The Final Order requires UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $0.4 to $0.5; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities' consolidated financial position, results of operations or cash flows.

Transfers of Assets. On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11-mile natural gas pipeline, related facilities and right of way located in Delmar Township, Pennsylvania (“TL-96 line”) to Energy Services.   The PUC approved the transfer and, in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services.  The net book value of the TL-96 line is approximately $2.6.

9. 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 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.

- 16 -

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:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,						Three Months Ended June 30,
	2013			2012			2013			2012
Service cost	$	2.8		$	2.1		$	0.2		$	0.1
Interest cost	5.9			6.1			0.2			0.2
Expected return on assets	(6.9		)	(6.4		)	(0.1		)	(0.1		)
Amortization of:
Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.1		)
Actuarial loss	3.7			2.1			0.1			0.1
Net benefit cost	5.6			4.0			0.3			0.2
Change in associated regulatory liabilities	—			—			0.8			0.8
Net expense	$	5.6		$	4.0		$	1.1		$	1.0
	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Service cost	$	8.5		$	6.4		$	0.5		$	0.3
Interest cost	17.6			18.3			0.7			0.8
Expected return on assets	(20.7		)	(19.2		)	(0.4		)	(0.4		)
Amortization of:
Prior service cost (benefit)	0.2			0.2			(0.2		)	(0.3		)
Actuarial loss	11.2			6.3			0.3			0.3
Net benefit cost	16.8			12.0			0.9			0.7
Change in associated regulatory liabilities	—			—			2.4			2.3
Net expense	$	16.8		$	12.0		$	3.3		$	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 Plan benefits equal to at least the minimum contribution set forth in applicable employee benefit laws. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $2.5 to the Pension Plan during the remainder of Fiscal 2013. During the nine months ended June 30, 2013 and 2012, the Company made cash contributions to the Pension Plan of $13.4 and $25.4, respectively. 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. 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, 2013 and 2012, nor are they expected to be material for all of Fiscal 2013.

We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans (“Supplemental Defined Benefit Plans”). We recorded pre-tax expense associated with these plans of $0.8 and $0.6 for the three months ended June 30, 2013 and 2012, respectively. We recorded pre-tax expense associated with these plans of $2.4 and $2.1 for the nine months ended June 30, 2013 and 2012, respectively. During the nine months ended June 30, 2013, the Company made payments with respect to the Supplemental Defined Benefit Plans totaling $20.6, including $20.0 used to fund trusts established by the Company for Supplemental Defined Benefit Plan participants who chose to defer payment upon retirement.

- 17 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

10. Debt

On December 18, 2012, Energy Services amended and restated its unsecured credit agreement with a group of banks (“Energy Services Credit Agreement”) to, among other things, increase its borrowing capacity and extend its expiration. The Energy Services Credit Agreement provides for borrowings up to $240 (including a $50 sublimit for letters of credit) and expires in June 2016. The Energy Services Credit Agreement also provides an option to increase the borrowing capacity by up to an additional $30, to a total of $270, upon approval from one or more of the banks.

Under the Energy Services Credit Agreement, Energy Services may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement, does not exceed 2.25 to 1.00. In addition, the Energy Services Credit Agreement requires Energy Services to not exceed a ratio of Consolidated Total Indebtedness, as defined, to Consolidated EBITDA, as defined; a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense, as defined; a maximum ratio of Consolidated Total Indebtedness to Consolidated Total Capitalization, as defined, at any time when Consolidated Total Indebtedness is greater than or equal to $250; and a minimum Consolidated Net Worth, as defined, of $200.

11. Commitments and Contingencies

Environmental Matters

UGI Utilities

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At June 30, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14.4 and $15.8, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of 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 (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At June 30, 2013, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

From time to time, UGI Utilities is notified of 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 generally investigate the extent of environmental contamination or perform environmental remediation. 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

- 18 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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.

Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities predecessor is identified as an owner and operator of the site. The City of Omaha and MUD have requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska, and issued an information request to UGI Utilities. UGI Utilities responded to the EPA’s information request on January 17, 2012. There have been no recent developments in this matter.

AmeriGas Propane

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 communicated the results of its research to DEC in January 2009. There have been no recent developments in this matter. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

Claremont, New Hampshire and Chestertown, Maryland. In connection with the Heritage Acquisition on January 12, 2012, a predecessor of Titan Propane LLC (“Titan LLC”), a former subsidiary acquired in the Heritage Acquisition, is purportedly the beneficial holder of title with respect to two former MGPs discussed below. The Contribution Agreement provides for indemnification from ETP for certain expenses associated with remediation of these sites. By letter dated September 30, 2010, the EPA notified Titan LLC that it may be a potentially responsible party (“PRP”) for cleanup costs associated with contamination at a former MGP in Claremont, New Hampshire. In June 2010, the Maryland Attorney General (“MAG”) identified Titan LLC as a PRP in connection with contamination at a former MGP in Chestertown, Maryland and requested that Titan LLC participate in characterization and remediation activities. Titan LLC has supplied the EPA and MAG with corporate and bankruptcy information for its predecessors to support its claim that it is not liable for any remediation costs at the sites. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

Other Matters

AmeriGas Cylinder Investigation. 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 as a result of the Partnership's decision in 2008 to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds. At that time, the District Attorneys issued an administrative subpoena seeking documents and information relating to those 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 sought additional information and documents regarding AmeriGas OLP's cylinder exchange program and we responded to that subpoena. In connection with this matter, the District Attorneys have alleged potential violations of California's antitrust laws, California's slack-fill law, and California’s principal false advertising statute. We believe we have strong defenses to these allegations.

Federal Trade Commission Investigation of Propane Grill Cylinder Filling Practices. On or about November 4, 2011, the General Partner received notice that the Federal Trade Commission (“FTC”) is conducting an antitrust and consumer protection investigation into certain practices of the Partnership that relate to the filling of portable propane cylinders. On February 2, 2012, the Partnership received a Civil Investigative Demand from the FTC that requests documents and information concerning, among other things, (i) the Partnership’s decision, in 2008, to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds and (ii) cross-filling, related service arrangements and communications regarding the foregoing with competitors. The

- 19 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Partnership believes that it will have good defenses to any claims that may result from this investigation. We are not able to assess the financial impact this investigation or any related claims may have on the Partnership.

Purported Class Action Lawsuit. In 2005, Samuel and Brenda Swiger (the “Swigers”) filed what purports to be a class action lawsuit 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 this 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 Court has not certified the class. 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 OLP 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. Effective June 20, 2013, we entered into a settlement agreement with BP and the lawsuit has been dismissed. The effect of the settlement agreement will not have a material impact on our results of operations or financial condition.

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.

- 20 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

12. Fair Value Measurements

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of June 30, 2013, September 30, 2012 and June 30, 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	2.2		$	7.4		$	—	$	9.6
Foreign currency contracts	$	—		$	1.0		$	—	$	1.0
Interest rate contracts	$	—		$	8.1		$	—	$	8.1
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(8.0	)	$	(24.1	)	$	—	$	(32.1	)
Foreign currency contracts	$	—		$	(1.7	)	$	—	$	(1.7	)
Interest rate contracts	$	—		$	(46.9	)	$	—	$	(46.9	)
September 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	8.6		$	4.5		$	—	$	13.1
Foreign currency contracts	$	—		$	1.8		$	—	$	1.8
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(7.8	)	$	(53.2	)	$	—	$	(61.0	)
Interest rate contracts	$	—		$	(71.9	)	$	—	$	(71.9	)
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5.1		$	12.3		$	—	$	17.4
Foreign currency contracts	$	—		$	7.1		$	—	$	7.1
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(18.0	)	$	(102.0	)	$	—	$	(120.0	)
Interest rate contracts	$	—		$	(67.0	)	$	—	$	(67.0	)

The fair values of our Level 1 exchange-traded commodity futures and option contracts and non exchange-traded commodity futures and forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The remainder of our derivative financial instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives

- 21 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 which are 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 our Level 2 interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. There were no transfers between Level 1 and Level 2 during the periods presented.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. At June 30, 2013, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,493.8 and $3,621.0, respectively. At June 30, 2012, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,561.2 and $3,730.7, 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 (Level 2).

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 that extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative financial instruments, see Note 13.

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 reduce short-term commodity price volatility and to provide market price risk support to some of its wholesale customers which are generally not designated as hedges for accounting purposes.

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, including the cost of financial instruments used to hedge purchased gas costs. 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, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.7 million dekatherms and 13.2 million dekatherms, respectively. At June 30, 2013, 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 GAAP related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 8).

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At June 30, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $6.1 and $13.1, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At June 30, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts was 327.4 million kilowatt hours and 654.7 million kilowatt hours, respectively. At June 30, 2013, the maximum period over which these contracts extend is 11 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly 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. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 8). At June 30, 2013 and 2012, the volumes associated with Electric Utility FTRs totaled 260.6 million kilowatt hours and 261.0 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At June 30, 2013 and 2012, the volumes associated with Midstream & Marketing’s FTRs totaled 1,609.2 million kilowatt hours and 1,285.5 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 futures contracts, IntercontinentalExchange (“ICE”) natural gas basis swap contracts, and electricity futures contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. In addition, 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. At June 30, 2013, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 2.7 million dekatherms and 1.8 million gallons, respectively. At June 30, 2012, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 4.1 million dekatherms and 2.2 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, 2013 and 2012, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:

	Volumes
	June 30,
Commodity	2013	2012
LPG (millions of gallons)	236.7	231.9
Natural gas (millions of dekatherms)	19.4	21.2
Electricity forward purchase contracts (millions of kilowatt-hours)	927.2	1688.4
Electricity forward sales contracts (millions of kilowatt-hours)	451.0	131.8

At June 30, 2013, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 19 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 41 months with a weighted average of 10 months; and the maximum period over which we are hedging our exposure to the variability in

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

cash flows associated with electricity price risk (excluding Electric Utility) is 27 months for electricity forward purchase contracts, with a weighted average of 9 months, and 14 months for electricity forward sales contracts, with a weighted average of 3 months. At June 30, 2013, 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 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, 2013, 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 $15.6.

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 its term loans, in each case through the respective scheduled maturity dates. As of June 30, 2013 and 2012, the total notional amount of existing variable-rate debt subject to interest rate swap agreements was €440.5 and €441.9, 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, 2013 and 2012, the total notional amount of unsettled IRPAs was $173. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt forecasted to occur in September 2013.

UGI Utilities reclassified pre-tax losses of $0.7 from AOCI into income during the nine months ended June 30, 2012, as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in other income, net, on the Condensed Consolidated Statements of Income.

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, 2013, 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 $2.2.

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 forecasted to occur during the heating-season months of October through March. At June 30, 2013 and 2012, we were hedging a total of $170.3 and $75.0 of U.S. dollar-denominated LPG purchases, respectively. At June 30, 2013, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 33 months with a weighted average of 14 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At June 30, 2013, we had no euro-denominated net investment hedges. At June 30, 2012, we were hedging a total of €14.5 of our euro-denominated net investments. From time to time, the Company may enter into foreign currency exchange transactions to economically hedge the local-currency purchase price of anticipated foreign business acquisitions. These transactions do not qualify for hedge accounting treatment and any changes in fair value are recorded in other income, net. At June 30, 2013, the fair values of these foreign currency contracts were not material.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At June 30, 2013, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $1.0. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise 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 contracts generally require cash deposits in margin accounts. At June 30, 2013 and 2012, restricted cash in brokerage accounts totaled $6.0 and $7.6, 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, 2013. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At June 30, 2013, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2013 and 2012:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value June 30,				Balance Sheet	Fair Value June 30,
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	7.5	$	4.2	Derivative financial instruments and Other noncurrent liabilities	$	(24.4	)	$	(95.5	)
Foreign currency contracts	Derivative financial instruments and Other assets	1.0		7.1		Other noncurrent liabilities	(0.4		)	—
Interest rate contracts	Derivative financial instruments	8.1		—		Derivative financial instruments and Other noncurrent liabilities	(46.9		)	(67.0		)
Total Derivatives Designated as Hedging Instruments		$	16.6	$	11.3		$	(71.7	)	$	(162.5	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	$	0.1	$	0.6	Derivative financial instruments and Other noncurrent liabilities	$	(7.6	)	$	(13.4	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	$	2.0	$	12.6	Derivative financial instruments	$	(0.1	)	$	(11.1	)
Foreign currency contracts	Derivative financial instruments	—		—		Derivative financial instruments	(1.3		)	—
Total Derivatives		$	18.7	$	24.5		$	(80.7	)	$	(187.0	)

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three months ended June 30, 2013 and 2012:

Three Months Ended June 30,	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2013			2012			2013			2012			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(22.8	)	$	(59.3	)	$	(6.9	)	$	(31.0	)	Cost of sales
Foreign currency contracts	(0.3		)	3.1			—			—			Cost of sales
Interest rate contracts	14.0			(16.6		)	(3.6		)	(3.3		)	Interest expense / other income, net
Total	$	(9.1	)	$	(72.8	)	$	(10.5	)	$	(34.3	)
Net Investment Hedges:
Foreign currency contracts	$	—		$	0.9
	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2013			2012
Commodity contracts	$	2.0		$	(15.9	)							Cost of sales
Commodity contracts	(0.1		)	(0.1		)							Operating expenses / other income, net
Foreign currency contracts	(0.9		)	—									Other income, net
Total	$	1.0		$	(16.0	)

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 nine months ended June 30, 2013 and 2012:

Nine Months Ended June 30,	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2013			2012			2013			2012			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(28.1	)	$	(166.2	)	$	(64.1	)	$	(94.4	)	Cost of sales
Foreign currency contracts	(1.4		)	2.8			(0.1		)	2.0			Cost of sales
Interest rate contracts	23.0			(29.0		)	(10.6		)	(8.4		)	Interest expense / other income, net
Total	$	(6.5	)	$	(192.4	)	$	(74.8	)	$	(100.8	)
Net Investment Hedges:
Foreign currency contracts	$	—		$	0.9
	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2013			2012
Commodity contracts	$	2.4		$	(12.6	)							Cost of sales
Commodity contracts	—			0.1									Operating expenses / other income, net
Foreign currency contracts	(1.1		)	0.5									Other income, net
Total	$	1.3		$	(12.0	)

The amounts of derivative gains or losses representing ineffectiveness were not material for the three and nine month periods ended June 30, 2013 and 2012.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

We 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 and contracts that 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, 2013		September 30, 2012		June 30, 2012
Non-utility LPG and natural gas	$	194.6	$	240.7	$	220.1
Gas Utility natural gas	43.1		57.7		27.8
Materials, supplies and other	66.3		58.5		69.4
Total inventories	$	304.0	$	356.9	$	317.3

At June 30, 2013, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”), one of which expires in October 2013 and two of which expire in October 2015. Pursuant to 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.

As of June 30, 2013, UGI Utilities’ principal SCAAs are with Energy Services. The carrying values of natural gas storage inventories released under SCAAs with non-affiliates at September 30, 2012 and June 30, 2012, comprising 3.8 billion cubic feet (“bcf”) and 1.9 bcf of natural gas, were $11.4 and $5.3, respectively.

15. Error in Accounting For Certain Customer Credits

During the three months ended March 31, 2013, the Partnership identified an error in accounting for certain customer credits. The Partnership determined that the recording of propane revenues did not appropriately consider the effects of certain customer credits which were recorded when issued in a subsequent period. As a result, beginning January 1, 2013, the Partnership changed its accounting for customer credits to record an estimate of such credits at the time propane revenues are recorded. Such estimate considers the Partnership’s history of providing credits, propane revenue activity and other factors. The Company has evaluated the impact of the error on prior periods and has determined that the effect is not material to any prior period financial statements. The Company has also evaluated and concluded that the impact of recording the cumulative effect of the correction of the error as of January 1, 2013, is not material to the financial statements for the three and six months ended March 31, 2013, nor is it expected to be material to the financial statements for Fiscal 2013. The correction of the error in accounting for customer credits had the effect of increasing revenues and accounts receivable by $3.6, and increasing net income attributable to UGI Corporation by $0.6, for the three months ended June 30, 2013, and decreasing revenues and accounts receivable by $5.1, and decreasing net income attributable to UGI Corporation by $0.9, for the nine months ended June 30, 2013. If the Company had corrected the error in its method of accounting and recorded the estimate of credits as of September 30, 2012, the cumulative effect of the change as of that date would have decreased net income attributable to UGI Corporation by approximately $0.7.

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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, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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 that 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, consumer protection 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 and retain current 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 and the impact of regulatory enforcement activity related thereto, ranging from financial penalties, required reporting or operational measures up to suspension of applicable certificates of public convenience; (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; (18) the timing and success of our acquisitions, commercial initiatives and investments to grow our businesses; and (19) our ability to successfully integrate acquired businesses and achieve anticipated synergies.

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, 2012, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on our business, financial condition or future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

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ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended June 30, 2013 (“2013 three-month period”) with the three months ended June 30, 2012 (“2012 three-month period”) and the nine months ended June 30, 2013 (“2013 nine-month period”) with the nine months ended June 30, 2012 (“2012 nine-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 6 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 heating season months of October through March. As a result, our earnings are generally higher in our first and second fiscal quarters.

We recorded net income attributable to UGI Corporation of $14.7 million for the 2013 three-month period compared to net loss attributable to UGI Corporation of $(6.3) million for the prior-year three-month period. Operating results in the 2013 three-month period include higher net income from our European LPG businesses and a significantly lower seasonal net loss from AmeriGas Propane. Each of our International Propane business units’ results during the 2013 three-month period improved from the prior-year three-month period with the most significant year-over-year increase at Antargaz. The improved results at Antargaz reflect higher volumes from colder spring weather and the benefit of higher average unit margins. At AmeriGas Propane, average temperatures during the 2013 three-month period were approximately normal but were significantly colder than the prior year. The lower seasonal loss from AmeriGas Propane includes the colder weather’s impact on retail propane volumes sold, higher average retail unit margins and lower operating and administrative expenses reflecting in large part the benefits from the integration of Heritage Propane. Midstream & Marketing’s results in the 2013 three-month period principally reflect higher income from its Electric Generation business segment and greater income from Energy Service’s storage, capacity management and peaking activities offset in part by lower retail power total margin. During the 2013 three-month period, Gas Utility total margin was slightly higher than the prior year on colder weather and customer additions, but the increase in margin was more than offset by higher Gas Utility operating and administrative expenses.

We recorded net income attributable to UGI Corporation of $289.2 million for the 2013 nine-month period compared to $214.1 million for the prior-year nine-month period. Operating results in the prior-year nine-month period were negatively affected by heating-degree day temperatures that were substantially warmer than normal across all of our business units. Operating results in the 2013 nine-month period were higher at each of our businesses due to the colder weather and, with respect to AmeriGas Propane, the full-period effects of the operations of Heritage Propane acquired January 12, 2012. Notwithstanding average temperatures that were approximately 4.1% warmer than normal, net income attributable to UGI from AmeriGas Propane increased $26.8 million principally reflecting year-over-year weather that was nearly 16.8% colder than the prior year and the full-period benefit of Heritage Propane acquired January 12, 2012. The return to more normal weather in the 2013 nine-month period from the record-setting warm weather experienced in the prior-year resulted in greater AmeriGas Propane retail volumes sold and higher total retail propane margin. Gas Utility results improved significantly from the prior year reflecting the effects of the colder 2013 nine-month period weather and, to a much lesser extent, customer growth due principally to customer conversions from oil. Midstream & Marketing’s Energy Services business segment results in the 2013 nine-month period also benefited from the effects of colder weather on natural gas marketing activities and midstream asset opportunities, while Midstream & Marketing’s Electric Generation business segment results benefited from higher volumes and increased electricity spot market prices. The improved Electric Generation volumes during the 2013 nine-month period reflect the full availability of our Hunlock Creek electricity generating station and greater production from the Conemaugh electricity generating station in which we own a 5.97% interest.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. The differences in exchange rates during the periods did not have a material impact on International Propane net income.

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UGI CORPORATION AND SUBSIDIARIES

2013 three-month period compared to the 2012 three-month period

Net income (loss) attributable to UGI Corporation by Business Unit:
	Three Months Ended June 30,
	2013					2012					Variance - Favorable (Unfavorable)
(Millions of dollars)	Amount			% of Total		Amount			% of Total		Amount			% Change
AmeriGas Propane	$	(2.9	)	(19.7	)%	$	(12.3	)	195.2	%	$	9.4		76.4	%
International Propane	8.4			57.1	%	(8.1		)	128.6	%	16.5			N.M.
Gas Utility	4.1			27.9	%	7.0			(111.1	)%	(2.9		)	(41.4	)%
Midstream & Marketing	4.6			31.3	%	2.5			(39.7	)%	2.1			84.0	%
Corporate & Other	0.5			3.4	%	4.6			(73.0	)%	(4.1		)	N.M.
Net income (loss) attributable to UGI Corporation	$	14.7		100.0	%	$	(6.3	)	100.0	%	$	21.0		N.M

N.M. — Variance is not meaningful.

AmeriGas Propane:

For the three months ended June 30,	2013			2012			Increase
(Millions of dollars)
Revenues	$	581.7		$	571.9		$	9.8	1.7	%
Total margin (a)	$	276.0		$	237.9		$	38.1	16.0	%
Partnership EBITDA (b)	$	59.1		$	1.8		$	57.3	N.M.
Operating income (loss)(b)	$	6.6		$	(48.4	)	$	55.0	N.M.
Retail gallons sold (millions)	224.7			204.0			20.7		10.1	%
Degree days—% colder (warmer) than normal (c)	0.5		%	(23.8		)%	—		—

N.M. - Variance is not meaningful.

(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 6 to condensed consolidated financial statements). Partnership EBITDA for the three months ended June 30, 2013 and 2012, includes transition expenses of $9.9 million and $15.0 million, respectively, associated with Heritage Propane.

(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.

AmeriGas Propane’s retail gallons sold in the 2013 three-month period increased more than 10% from the 2012 three-month period reflecting average temperatures based upon heating degree days that were approximately normal but significantly colder than the prior-year three-month period. Based upon heating degree-day data, temperatures in the Partnership’s service territories during the 2013 three-month period averaged approximately 0.5% colder than normal while temperatures in the prior-year period averaged approximately 23.8% warmer than normal.

Retail propane revenues increased $9.4 million during the 2013 three-month period reflecting the higher retail volumes sold ($49.9 million) offset in large part by the effects of a decline in average retail selling prices ($40.5 million) which were the result of lower propane product costs. Wholesale propane revenues increased $1.5 million for the 2013 three-month period on slightly higher wholesale sales. Average daily wholesale propane commodity prices during the 2013 three-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 7% lower than such prices during the prior-year three-month period. Total revenues from fee income and other ancillary sales and services in the 2013 three-month period were slightly lower than in

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the 2012 three-month period. Total cost of sales decreased $28.3 million principally reflecting the effects on retail propane cost of sales of the lower average propane product costs ($60.1 million) partially offset by effects of the greater retail volumes sold ($30.0 million).

Total margin increased $38.1 million in the 2013 three-month period principally reflecting higher retail propane total margin ($39.4 million). The increase in retail propane total margin reflects the increase in retail volumes sold and modestly higher average retail propane unit margins.

Partnership EBITDA in the 2013 three-month period increased $57.3 million principally reflecting the higher total margin ($38.1 million) and lower operating and administrative expenses ($18.5 million) reflecting, among other things, synergies from the integration of Heritage Propane, lower self-insured liability and casualty expenses ($7.2 million) and lower Heritage Propane integration transition expenses. Operating and administrative expenses in the 2013 three-month period include $9.9 million of transition expenses associated with the integration of Heritage Propane while operating and administrative expenses in the prior-year period include Heritage Propane acquisition and transition expenses of $15.0 million. Operating income increased $55.0 million in the 2013 three-month period principally reflecting the higher total margin ($38.1 million) and the lower operating and administrative expenses ($18.5 million) partially offset by increased depreciation and amortization expense ($3.0 million).

International Propane:

For the three months ended June 30,	2013			2012			Increase
(Millions of dollars)
Revenues	$	431.7		$	405.2		$	26.5	6.5	%
Total margin (a)	$	148.2		$	118.6		$	29.6	25.0	%
Operating income	$	21.0		$	1.2		$	19.8	N.M
Income (loss) before income taxes	$	13.6		$	(6.4	)	$	20.0	N.M
Retail gallons sold (b)	126.6			119.0			7.6		6.4	%
Antargaz degree days—% colder (warmer) than normal (c)	19.7		%	(3.5		)%	—		—
Flaga degree days—% (warmer) than normal (c)	(7.2		)%	(20.4		)%	—		—

N.M -Variance is not meaningful.

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

(b) Excludes retail gallons from operations in China.

(c) Deviation from average heating degree days for the 30-year period 1981-2010 at locations in our Antargaz and Flaga service territories.

Based upon heating degree day data, temperatures in our International Propane LPG operations were colder than normal at Antargaz and AvantiGas, and modestly warmer than normal at our Flaga business unit. Notwithstanding the variances to normal weather, our European LPG businesses experienced spring weather that was significantly colder than the prior-year three-month period. The colder spring weather increased retail LPG volumes sold by 6.4%. During the 2013 three-month period, the average wholesale commodity price for propane in northwest Europe was approximately 6% lower than in the prior-year period while the average wholesale commodity price for butane was approximately 8% lower than the prior-year period.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. The functional currency of a significant portion of our International Propane results is the euro. During the 2013 and 2012 three-month periods, the average un-weighted translation rate was approximately $1.30 and $1.29 per euro, respectively. The difference in euro to U.S. dollar translation rates did not have a material impact on net income attributable to UGI.

International Propane revenues were $26.5 million greater than the prior-year period as the effects on revenues from the greater retail LPG volumes sold, greater wholesale volumes sold and, to a much lesser extent, increased revenues from natural gas marketing activities at Antargaz were partially offset by the effects of lower average LPG wholesale commodity prices principally at Flaga. Cost of sales decreased to $283.5 million in the 2013 three-month period from $286.6 million in the prior-year period, as the effects of the lower LPG wholesale commodity prices principally at Flaga were largely offset by the effects of the increase in retail and wholesale gallons sold and higher cost of sales associated with natural gas marketing activities at Antargaz.

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Total International Propane margin increased $29.6 million during the 2013 three-month period principally reflecting the effects of higher average retail LPG unit margins principally at Antargaz and, to a lesser extent, the effects of the greater retail volumes sold.

International Propane operating income and income before income taxes were $19.8 million and $20.0 million higher than the prior-year period, respectively, principally reflecting the higher total margin ($29.6 million) partially offset by increased operating and administrative costs, principally at Antargaz ($6.2 million), and slightly higher International Propane depreciation expense. Antargaz operating and administrative costs in the 2013 three-month period include greater incentive compensation and benefits costs and greater delivery expenses. International Propane operating expenses in the prior-year three-month period include $1.4 million of transition expenses associated with LPG businesses acquired from Shell in October 2012.

Gas Utility:

For the three months ended June 30,	2013			2012			Increase (Decrease)
(Millions of dollars)
Revenues	$	126.7		$	122.3		$	4.4		3.6	%
Total margin (a)	$	74.3		$	70.9		$	3.4		4.8	%
Operating income	$	16.1		$	22.5		$	(6.4	)	(28.4	)%
Income before income taxes	$	6.9		$	12.6		$	(5.7	)	(45.2	)%
System throughput—billions of cubic feet (“bcf”) —
Core market	8.8			8.3			0.5			6.0	%
Total	35.9			36.2			(0.3		)	(0.8	)%
Degree days—% (warmer) than normal (b)	(7.1		)%	(19.0		)%	—			—

(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 NOAA for airports located within Gas Utility’s service territory.

Temperatures in the Gas Utility service territory in the 2013 three-month period based upon heating degree days were 7.1% warmer than normal but 14.4% colder than the prior-year three-month period. Total distribution system throughput decreased slightly, notwithstanding increases in core market and large firm delivery service throughput, principally reflecting lower throughput to certain low-margin, interruptible delivery service customers. 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 system throughput to core-market customers was above last year principally reflecting the effects of the colder weather and, to a much lesser extent, customer growth, due principally to conversions from oil prompted by sustained lower natural gas prices and high oil prices.

Gas Utility revenues increased $4.4 million during the 2013 three-month period principally reflecting higher revenues from core market customers ($1.9 million), greater revenues from large firm delivery service customers on the higher throughput, and slightly higher revenues from off-system sales ($1.5 million). The increase in core market revenues principally reflects the effects of the higher core market volumes partially offset by the effects of lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices ($7.0 million). 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 $52.4 million in the 2013 three-month period compared with $51.4 million in the prior-year period principally reflecting the effects of the greater retail core-market volumes sold ($6.3 million) and the higher off-system sales ($1.5 million) partially offset by the effects of the lower average PGC rates.

Gas Utility total margin increased $3.4 million in the 2013 three-month period principally reflecting higher core market total margin ($1.3 million) and greater large firm delivery service total margin ($1.7 million). The higher core market and large firm delivery service total margin reflects the effects of the greater throughput to these customers.

The decreases in Gas Utility operating income and income before income taxes during the 2013 three-month period, notwithstanding the increase in total margin, principally reflects higher operating and administrative expenses ($9.4 million) including, among other things, higher uncollectible accounts expense ($2.4 million), higher pension and benefits expenses ($1.8 million) and higher injuries and damages and distribution system expenses ($1.4 million).

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Midstream & Marketing:

For the three months ended June 30,	2013		2012		Increase
(Millions of dollars)
Revenues (a)	$	247.8	$	166.7	$	81.1	48.7	%
Total margin (b)	$	27.1	$	21.5	$	5.6	26.0	%
Operating income	$	8.2	$	4.9	$	3.3	67.3	%
Income before income taxes	$	7.6	$	3.7	$	3.9	105.4	%

(a) Amounts are net of intercompany revenues between Midstream & Marketing’s Energy Services and Electric Generation segments.

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

Midstream & Marketing total revenues increased $81.1 million in the 2013 three-month period principally reflecting higher natural gas revenues ($76.8 million) principally from greater natural gas volumes and, to a much lesser extent, greater Electric Generation revenues ($4.7 million). The increase in natural gas revenues principally reflects higher wholesale volumes sold and higher average selling prices for natural gas, while the increase in Electric Generation revenues reflects higher average electricity prices and higher electricity output at the Hunlock Creek electricity generating station.

Midstream & Marketing total margin increased $5.6 million in the 2013 three-month period principally reflecting higher Electric Generation total margin ($3.4 million) and increased peaking, capacity management and storage total margin ($4.7 million) partially offset by lower retail power total margin. The greater total margin from Electric Generation principally reflects the impact of higher electricity prices on electricity unit margins and, to a lesser extent, greater electricity production principally from our Hunlock Creek natural gas-fired electricity generating station. In the prior-year three-month period, the Hunlock Creek electricity generating station was operating at less than full capacity.

Midstream & Marketing operating income in the 2013 three-month period was $3.3 million higher than the prior-year period reflecting the previously mentioned increase in total margin ($5.6 million) partially offset by higher operating and depreciation expenses. The higher expenses include greater Energy Services operating and depreciation expenses associated with peaking assets and greater Electric Generation operating and depreciation expenses ($0.7 million) including higher maintenance expenses associated with planned outages at the Conemaugh generating station in which we own a 5.97% interest. The increase in Midstream & Marketing’s income before income taxes reflects the greater operating income ($3.3 million) and lower interest expense on borrowings under the Energy Services Credit Agreement.

Interest Expense and Income Taxes. Our consolidated interest expense was $2.1 million lower in the 2013 three-month period principally reflecting slightly lower AmeriGas Propane, UGI Utilities and Energy Services interest expense the result of lower average debt outstanding. Our consolidated effective tax rate (as calculated as a percentage of pretax income (loss) excluding noncontrolling interests not subject to income taxes) for the three months ended June 30, 2013, was comparable to such rate for the prior-year three-month period.

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2013 nine-month period compared to the 2012 nine-month period

Net income (loss) attributable to UGI Corporation by Business Unit:
	Nine Months Ended June 30,
	2013					2012					Variance - Favorable (Unfavorable)
(Millions of dollars)	Amount			% of Total		Amount			% of Total		Amount			% Change
AmeriGas Propane (a)	$	52.8		18.3	%	$	26.0		12.1	%	$	26.8		103.1	%
International Propane (b)	97.3			33.6	%	72.9			34.0	%	24.4			33.5	%
Gas Utility	96.2			33.3	%	84.4			39.4	%	11.8			14.0	%
Midstream & Marketing	46.6			16.1	%	34.2			16.0	%	12.4			36.3	%
Corporate & Other	(3.7		)	(1.3	)%	(3.4		)	(1.5	)%	(0.3		)	N.M.
Net income attributable to UGI Corporation	$	289.2		100.0	%	$	214.1		100.0	%	$	75.1		35.1	%

N.M. — Variance is not meaningful.

(a) Net income from AmeriGas Propane in the 2012 nine-month period includes after-tax loss of $2.2 million associated with extinguishments of debt.

(b) Net income from International Propane in the 2012 nine-month period includes the benefit of $4.7 million related to the realization of previously unrecognized foreign tax credits.

AmeriGas Propane:

For the nine months ended June 30,	2013			2012			Increase
(Millions of dollars)
Revenues	$	2,634.6		$	2,411.3		$	223.3	9.3	%
Total margin (a)	$	1,264.4		$	963.5		$	300.9	31.2	%
Partnership EBITDA (b)	$	550.5		$	310.0		$	240.5	77.6	%
Operating income (b)	$	403.9		$	206.7		$	197.2	95.4	%
Retail gallons sold (millions)	1,039.8			814.3			225.5		27.7	%
Degree days—% (warmer) than normal (c)	(4.1		)%	(18.3		)%	—		—

(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 6 to condensed consolidated financial statements). Partnership EBITDA for the nine months ended June 30, 2013, includes transition expenses of $20.7 million associated with Heritage Propane. Partnership EBITDA for the nine months ended June 30, 2012, includes acquisition and transition expenses of $26.9 million associated with Heritage Propane and a pre-tax loss of $13.3 million associated with extinguishments of debt.

(c) Deviation from average heating degree-days for the 30-year period 1971-2000 based upon national weather statistics provided by NOAA for 335 airports in the United States, excluding Alaska.

Results for the 2013 nine-month period reflect the full-period operations of Heritage Propane acquired in January 2012. Based upon heating degree-day data, temperatures in the Partnership’s service territories during the 2013 nine-month period averaged approximately 4.1% warmer than normal but 16.8% colder than the 2012 nine-month period. AmeriGas Propane retail gallons sold were 225.5 million gallons (27.7%) greater than in the prior-year period principally reflecting the full-period impact of the Heritage Propane operations and the colder 2013 nine-month period weather.

Retail propane revenues increased $220.7 million during the 2013 nine-month period reflecting the higher retail volumes sold ($583.4 million) partially offset by a decline in average retail selling prices ($362.7 million) which were the result of lower propane product costs. Wholesale propane revenues declined $34.5 million principally reflecting lower average wholesale propane selling prices ($32.3 million) and lower wholesale volumes sold ($2.2 million). Average daily wholesale propane commodity prices during the 2013 nine-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 28% lower

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than such prices during the prior-year nine-month period. Total revenues from fee income and other ancillary sales and services in the 2013 nine-month period were $37.0 million higher than in the 2012 nine-month period principally reflecting the full-period effects of Heritage Propane. Total propane cost of sales decreased $88.1 million during the 2013 nine-month period principally reflecting the effects of the lower propane commodity prices on retail propane cost of sales ($403.8 million) and lower wholesale propane cost of sales ($37.2 million) substantially offset by the effects of the greater retail volumes sold ($352.9 million). Cost of sales associated with ancillary sales and services increased $10.5 million principally reflecting the full-period effects of Heritage Propane.

Total margin increased $300.9 million in the 2013 nine-month period principally reflecting higher total propane margin ($274.3 million) and greater total margin from ancillary sales and services ($26.6 million). These increases principally reflect the incremental full-period effects of Heritage Propane, the colder 2013 nine-month period weather and, with respect to total propane margin, slightly higher 2013 nine-month period average unit margins reflecting the lower propane product costs.

Partnership EBITDA in the 2013 nine-month period increased $240.5 million principally reflecting the higher total margin ($300.9 million) and the absence of the $13.3 million loss on extinguishments of debt recorded in the prior-year period partially offset by higher Partnership operating and administrative expenses ($78.2 million) primarily attributable to the full-period effects of Heritage Propane operations. Operating and administrative expenses in the 2013 nine-month period include $20.7 million of transition expenses associated with the integration of Heritage Propane while operating and administrative expenses in the prior-year period include Heritage Propane acquisition and transition-related expenses of $26.9 million. Partnership operating income increased $197.2 million in the 2013 nine-month period principally reflecting the higher total margin ($300.9 million) partially offset by the previously mentioned greater operating and administrative expenses ($78.2 million) and increased depreciation and amortization expense ($32.0 million) reflecting in large part the full-period effects of Heritage Propane.

International Propane:

For the nine months ended June 30,	2013			2012			Increase
(Millions of dollars)
Revenues	$	1,780.1		$	1,605.2		$	174.9	10.9	%
Total margin (a)	$	558.6		$	501.0		$	57.6	11.5	%
Operating income	$	160.4		$	113.1		$	47.3	41.8	%
Income before income taxes	$	137.7		$	89.8		$	47.9	53.3	%
Retail gallons sold (b)	474.9			466.2			8.7		1.9	%
Antargaz degree days—% colder (warmer) than normal (c)	5.2		%	(7.2		)%	—		—
Flaga degree days—% colder (warmer) than normal (c)	0.4		%	(5.6		)%	—		—

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

(b) Excludes retail gallons from operations in China.

(c) Deviation from average heating degree days for the 30-year period 1981-2010 at locations in our Antargaz and Flaga service territories.

Based upon heating degree day data, temperatures in our European LPG operations were colder than normal and the prior year. Although wholesale commodity prices for propane and butane based upon index prices in northwest Europe for the 2013 nine-month period averaged approximately the same as in the 2012 nine-month period, such LPG prices in northwest Europe generally declined during the 2013 peak heating season while LPG prices generally increased during the prior-year peak heating season. Retail LPG gallons sold were slightly higher than the prior-year period principally reflecting the effects of significantly colder weather across all of our European operations partially offset by the effects of a decline in economic activity mainly on commercial and industrial customers in certain of our European markets.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. The functional currency of a significant portion of our International Propane results is the euro. During the 2013 and 2012 nine-month periods, the average un-weighted translation rate was approximately $1.31 and $1.32 per euro, respectively. The difference in rates did not have a material impact on net income attributable to UGI.

International Propane revenues increased $174.9 million principally reflecting the effects on LPG revenues of greater low-margin wholesale sales, the increase in LPG retail volumes sold and greater average retail prices. The increase in revenues also reflects higher revenues from natural gas marketing activities in France. Cost of sales increased to $1,221.5 million in the 2013 nine-month period from $1,104.2 million in the prior-year period principally reflecting the effects of the greater retail and wholesale LPG

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volumes sold. The higher International Propane cost of sales also reflects increased cost of sales associated with natural gas marketing activities in France.

Total International Propane margin increased $57.6 million during the 2013 nine-month period principally reflecting higher retail LPG unit margins and volumes at Antargaz and, to a much lesser extent, greater total LPG margin at AvantiGas and Flaga.

International Propane operating income and income before income taxes increased $47.3 million and $47.9 million, respectively, principally reflecting the higher total margin ($57.6 million) partially offset by modestly higher operating and administrative expenses. Operating and administrative expenses in the 2013 nine-month period include higher delivery, selling, and incentive compensation and benefits costs at Antargaz partially offset by slightly lower operating and administrative costs at Flaga and AvantiGas. The prior-year nine-month period operating and administrative expenses include acquisition and transition costs of approximately $5.9 million associated with the LPG businesses acquired from Shell in October 2011. Net income from International Propane operations in the 2013 nine-month period as a percentage of earnings before taxes was lower than the prior-year period as the estimated annual income tax rate in the prior year reflects, in part, the effects of a greater proportion of International Propane tax benefits relative to pre-tax income and the realization of $4.7 million of previously unrecognized foreign tax credits.

Gas Utility:

For the nine months ended June 30,	2013			2012			Increase
(Millions of dollars)
Revenues	$	743.6		$	696.8		$	46.8	6.7	%
Total margin (a)	$	370.9		$	326.2		$	44.7	13.7	%
Operating income	$	191.6		$	168.7		$	22.9	13.6	%
Income before income taxes	$	163.5		$	138.6		$	24.9	18.0	%
System throughput—billions of cubic feet (“bcf”) —
Core market	65.4			54.7			10.7		19.6	%
Total	158.5			146.0			12.5		8.6	%
Degree days—% (warmer) than normal (b)	(1.2		)%	(16.6		)%	—		—

(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 NOAA for airports located within Gas Utility’s service territory.

Temperatures in the Gas Utility service territory in the 2013 nine-month period based upon heating degree days were 1.2% warmer than normal but 14.9% colder than the prior-year period. Total distribution system throughput increased principally reflecting significantly higher throughput to core market customers and, to a lesser extent, greater net volumes associated with lower margin firm and interruptible delivery service customers. Gas Utility system throughput to core-market customers was above last year principally reflecting the effects of the significantly colder weather and, to a much lesser extent, customer growth, principally conversions from oil prompted by sustained lower natural gas prices and high oil prices.

Gas Utility revenues increased $46.8 million during the 2013 nine-month period principally reflecting higher revenues from core market customers ($44.2 million) and higher large firm delivery service revenues ($7.7 million) partially offset by lower off-system sales revenues ($6.1 million). The increase in core market revenues principally reflects the effects of the higher core market volumes on PGC revenues ($52.0 million) and greater core market delivery service revenues partially offset by the effects of lower average PGC rates on retail core-market revenues ($46.7 million). Gas Utility’s cost of gas was $372.7 million in the 2013 nine-month period compared with $370.6 million in the prior-year period principally reflecting the effects on cost of sales of the greater retail core-market volumes ($52.0 million) substantially offset by the effects of lower average PGC rates ($46.7 million) and the lower off-system sales.

Gas Utility total margin increased $44.7 million in the 2013 nine-month period principally reflecting higher core market margin ($34.5 million) and higher large firm delivery service total margin ($8.1 million). The higher core market total margin reflects the effects of the greater core market volumes.

The increase in Gas Utility operating income during the 2013 nine-month period principally reflects the increase in total margin ($44.7 million) partially offset by higher operating and administrative expenses ($17.0 million) including, among other things, higher pension and benefits expenses ($3.0 million), higher uncollectible accounts expenses ($2.8 million) on higher core market volumes, and greater injuries and damages and distribution system expenses ($4.0 million). The greater income before income

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taxes in the 2013 nine-month period reflects the higher operating income ($22.9 million) and slightly lower interest expense on lower long-term debt outstanding.

Midstream & Marketing:

For the nine months ended June 30,	2013		2012		Increase
(Millions of dollars)
Revenues (a)	$	809.9	$	674.5	$	135.4	20.1	%
Total margin (b)	$	135.8	$	108.9	$	26.9	24.7	%
Operating income	$	79.7	$	59.4	$	20.3	34.2	%
Income before income taxes	$	77.3	$	55.8	$	21.5	38.5	%

(a) Amounts are net of intercompany revenues between Midstream & Marketing’s Energy Services and Electric Generation segments.

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

Midstream & Marketing total revenues increased $135.4 million in the 2013 nine-month period principally reflecting, among other things, higher natural gas revenues ($101.2 million) from higher wholesale volumes sold and higher average selling prices for natural gas, and higher Electric Generation total revenues ($20.5 million) principally the result of higher electricity volumes and prices.

Midstream & Marketing total margin in the 2013 nine-month period was $26.9 million higher than the prior-year period reflecting higher natural gas marketing total margin ($12.9 million), higher Electric Generation total margin ($10.2 million) and greater peaking and capacity management total margin ($8.9 million) due to the colder weather and greater natural gas price volatility. Total margin from natural gas marketing activities in the 2013 nine-month period principally reflects the benefits of higher average unit margins. Natural gas marketing average unit margins in the 2013 nine-month period benefited from higher-margin incremental sales resulting from the colder weather while average unit margins in the prior-year period were negatively impacted by significantly warmer than normal weather. The greater total margin from Electric Generation principally reflects the impact of higher electricity production from our Hunlock Creek natural gas-fired electricity generating station and greater volumes sold from the Conemaugh generating station. As previously mentioned, in the prior-year period the Hunlock Creek generating station was running at less than full capacity due to an accident at one unit and flood damage at another unit sustained late in Fiscal 2011. Unit margins from Electric Generation were higher in the 2013 nine-month period reflecting higher electricity spot market prices.

Midstream & Marketing operating income in the 2013 nine-month period was $20.3 million higher than the prior-year period reflecting the previously mentioned increase in total margin ($26.9 million) partially offset by higher operating and depreciation expenses. The higher operating and depreciation expenses include greater Energy Services depreciation and operating expenses ($5.5 million) due in large part to expenses associated with peaking LNG liquefaction and storage facilities. The increase in Midstream & Marketing income before income taxes reflects the greater operating income ($20.3 million) and lower interest expense on Energy Services’ Credit Agreement and Receivables Facility borrowings.

Interest Expense and Income Taxes. Our consolidated interest expense was $17.0 million higher in the 2013 nine-month period primarily reflecting higher AmeriGas Propane interest expense ($20.8 million), principally full-period interest on debt issued to fund the cash portion of the January 12, 2012, Heritage Acquisition. Income taxes as a percentage of pretax earnings was lower in the 2013 nine-month period reflecting the effects of a higher percentage of income associated with noncontrolling interests, principally AmeriGas Partners, not subject to tax and the realization of previously unrecognized state deferred tax benefits while taxes in the prior-year nine-month period were reduced by $4.7 million as a result of the realization of previously unrecognized foreign tax credits.

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. We believe that each of our business units has sufficient liquidity in the forms of cash and cash equivalents on hand, cash expected to be generated from operations, and credit facilities and receivables purchase facility borrowings, and the ability to obtain long-term financing to meet anticipated contractual and projected cash commitments.

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Issuances of debt and equity securities in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.

Our cash and cash equivalents totaled $401.8 million at June 30, 2013, compared with $319.9 million at September 30, 2012. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at June 30, 2013 and September 30, 2012, UGI had $100.0 million and $107.9 million, respectively, of cash and cash equivalents.

The Company’s debt outstanding at June 30, 2013, totaled $3,629.7 million (including current maturities of long-term debt of $195.6 million and bank loan borrowings of $135.9 million) compared to debt outstanding at September 30, 2012, of $3,679.4 million (including current maturities of long-term debt of $166.7 million and bank loan borrowings of $165.1 million). Total debt outstanding at June 30, 2013, consists of (1) $2,383.2 million of Partnership debt; (2) $588.0 million (€452.1 million) of International Propane debt; (3) $600.0 million of UGI Utilities’ debt; (4) $46.6 million of Midstream & Marketing debt; and (5) $11.9 million of other debt.

AmeriGas Partners’ total debt at June 30, 2013, includes $2,250.8 million of AmeriGas Partners’ Senior Notes, $80.0 million of AmeriGas OLP bank loan borrowings and $52.4 million of other long-term debt.

International Propane’s total debt at June 30, 2013, includes $494.4 million (€380 million) outstanding under Antargaz’ Senior Facilities term loan and a combined $78.7 million (€60.5 million) outstanding under Flaga’s three term loans. Total International Propane debt outstanding at June 30, 2013, also includes combined borrowings of $10.4 million outstanding under all of Flaga’s working capital facilities and $4.5 million (€3.5 million) of other long-term debt.

UGI Utilities’ total debt at June 30, 2013, includes $383 million of Senior Notes and $217 million of Medium-Term Notes. At June 30, 2013, UGI Utilities had no bank loan borrowings.

AmeriGas Partners. AmeriGas OLP has a $525 million unsecured credit agreement (“AmeriGas Credit Agreement”). At June 30, 2013, there were $80.0 million of borrowings outstanding under the AmeriGas Credit Agreement which are classified as bank loans on the Condensed Consolidated Balance Sheet. Issued and outstanding letters of credit under the AmeriGas Credit Agreement, which reduce the amount available for borrowings, totaled $54.1 million at June 30, 2013. Average daily and peak bank loan borrowings outstanding under the AmeriGas Credit Agreement during the 2013 nine-month period were $106.6 million and $200.5 million, respectively. The average daily and peak bank loan borrowings outstanding during the 2012 nine-month period were $111.5 million and $239.5 million, respectively. At June 30, 2013, the Partnership’s available borrowing capacity under the AmeriGas Credit Agreement was $390.9 million.

International Propane. Antargaz has a Senior Facilities Agreement with a consortium of banks (“Senior Facilities Agreement”) consisting of a €380 million variable-rate term loan and 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. Borrowings under the term loan bear interest at one-, two-, three- or nine-month euribor, plus a margin. 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, 2013, the effective interest rate on Antargaz’ term loan was 4.66%. Antargaz had no amounts outstanding under its revolving credit facility at June 30, 2013.

Flaga has two principal working capital facilities (the “Flaga Credit Agreements”) comprising (1) a €46 million multi-currency working capital facility which includes an uncommitted €6 million overdraft facility (the “Flaga Multi-Currency Working Capital Facility”) and (2) a euro-denominated working capital facility that provides for borrowings and issuances of guarantees totaling €12 million (the “Euro Facility”). The Flaga Multi-Currency Working Capital Facility expires in September 2014 and the Euro Facility expires in September 2013. Flaga expects to extend the Euro Facility prior to its expiration. At June 30, 2013, there were €3.4 million ($4.4 million) of borrowings outstanding under the Flaga Credit Agreements.

Issued and outstanding guarantees, which reduce available borrowings under the Flaga Credit Agreements, totaled €18.8 million ($24.4 million) at June 30, 2013. The average daily and peak bank loan borrowings outstanding under the Flaga Credit Agreements during the 2013 nine-month period were €5.1 million and €11.9 million, respectively. The average daily and peak bank loan borrowings outstanding under the Flaga Credit Agreements during the 2012 nine-month period were €13.4 million and €14.5 million, respectively.

UGI Utilities. UGI Utilities may borrow up to a total of $300 million under its credit agreement (“UGI Utilities Credit Agreement”). The UGI Utilities Credit Agreement expires in October 2015. At June 30, 2013, there were no amounts outstanding under the UGI Utilities Credit Agreement. During the 2013 and 2012nine-month periods, average daily bank loan borrowings were $27.3 million and $21.3 million, respectively, and peak bank loan borrowings totaled $79.0 million and $70.6 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January.

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UGI Utilities has an aggregate $133 million of Senior Notes and Medium-Term Notes maturing late in Fiscal 2013 which UGI Utilities intends to refinance on a long-term basis.

Midstream & Marketing. In December 2012, Energy Services amended and restated its unsecured credit agreement with a group of banks (“Energy Services Credit Agreement”) to increase its borrowing capacity and extend its expiration (see Note 10 to condensed consolidated financial statements). The Energy Services Credit Agreement, which expires in June 2016, provides for borrowings of up to $240 million (including a $50 million sublimit for letters of credit). There were $36 million of borrowings outstanding under this facility at June 30, 2013. During the 2013 and 2012 nine-month periods, peak borrowings under the Energy Services Credit Agreement were $85 million.

Energy Services also has a $100 million receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper. In April 2013, Energy Services amended its Receivables Facility to extend its expiration until November 2013 and reduce the facility to $100 million from $200 million previously. The Receivables Facility may terminate prior to its expiration due to the termination of commitments of the Receivables Facility’s back-up purchasers. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts and capital expenditures. Energy Services intends to extend its Receivables Facility prior to its scheduled expiration and amend the receivables purchase limits to better align such limits with Energy Services seasonal borrowing needs.

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, 2013 and 2012, Energy Services transferred trade receivables totaling $766.1 million and $674.4 million, respectively, to ESFC. During the nine months ended June 30, 2013 and 2012, ESFC sold an aggregate $224.0 million and $266.5 million, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At June 30, 2013, the balance of ESFC receivables was $58.2 million and there was $9.5 million sold to the commercial paper conduit. At June 30, 2012, the outstanding balance of ESFC receivables was $41.0 million and there was $10.0 million sold to the commercial paper conduit. During the nine months ended June 30, 2013 and 2012, peak amounts sold under the Receivables Facility were $46.5 million and $51.5 million, respectively, and average daily amounts sold were $8.6 million and $21.9 million, respectively.

Dividends and Distributions. On July 30, 2013, UGI's Board of Directors approved a quarterly dividend of $0.2825 per common share payable October 1, 2013, to shareholders of record September 16, 2013. On April 30, 2013, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.2825 per Common Share or $1.13 on an annual basis. The dividend reflects an approximate 4.6% increase from the previous quarterly rate of $0.27. The new quarterly dividend rate was effective with the dividend payable on July 1, 2013, to shareholders of record on June 14, 2013.

On July 29, 2013, the General Partner's Board of Directors approved a quarterly distribution of $0.84 per Common Unit payable August 19, 2013 to unitholders of record August 9, 2013. On April 29, 2013, the General Partner’s Board of Directors approved an increase in the quarterly dividend rate on AmeriGas Partners Common Units to $0.84 per Common Unit equal to an annual rate of $3.36 per Common Unit. The distribution reflects a 5% increase from the previous quarterly rate of $0.80. The new quarterly rate was effective with the distribution payable on May 17, 2013, to unitholders of record on May 10, 2013.

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 flow provided by operating activities was $686.4 million in the 2013 nine-month period compared to $566.2 million in the 2012 nine-month period. Cash flow from operating activities before changes in operating working capital was $801.2 million in the 2013 nine-month period compared to $523.7 million in the prior-year nine-month period. The increase in cash flow from operating activities before changes in operating working capital largely reflects the effects of the higher operating results in the 2013 nine-month period. Cash required to fund changes in operating working capital totaled $114.8 million in the 2013 nine-month period compared to cash provided by changes in operating working capital of $42.5 million in the prior-year nine-month period. The cash required to fund changes in operating working capital in the 2013 nine-month period reflects, among other things, greater cash needed to fund operating working capital associated with the increased nine-month period sales while cash provided by changes in operating working capital in the prior-year period benefited from the timing of the acquisition of Heritage Propane on cash receipts from Heritage Propane customers. This greater use of cash in the current-year period was

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UGI CORPORATION AND SUBSIDIARIES

partially offset by, among other things, the timing and amount of cash payments associated with accounts payable including the impact of lower LPG product costs.

Investing Activities. Cash flow used by investing activities was $316.7 million in the 2013 nine-month period compared with $1,800.0 million in the prior-year period. Investing activity cash flow is principally affected by expenditures for property, plant and equipment; cash paid for acquisitions of businesses; changes in restricted cash balances; and proceeds from sales of assets. Cash paid for acquisitions in the 2013 nine-month period largely reflects Midstream and Marketing's acquisition of a non-operating working interest in natural gas acreage in the Marcellus Shale region of Pennsylvania.  Cash paid for acquisitions in the prior-year nine-month period principally reflects the January 2012 Heritage Acquisition and the October 2011 acquisition of certain of Shell’s European LPG businesses.

Financing Activities. Cash flow used by financing activities was $286.0 million in the 2013 nine-month period compared with cash flow provided by financing activities of $1,434.8 million in the prior-year period. Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; net bank loan borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units; and issuances of UGI and AmeriGas Partners equity instruments.

Distributions on AmeriGas Partners’ publicly held Common Units in the 2013 nine-month period increased over the prior-year period reflecting the greater number of Common Units outstanding subsequent to the Heritage Acquisition and higher quarterly per-unit distribution rates. In order to finance the cash portion of the Heritage Acquisition, on January 12, 2012, AmeriGas Partners issued $550 million principal amount of 6.75% Notes due 2020 and $1.0 billion principal amount of 7.00% Notes due 2022. During March 2012, AmeriGas Partners sold 7 million Common Units in an underwritten public offering and used a portion of the net proceeds to repay $200 million of outstanding 6.50% Senior Notes due May 2021, to reduce bank loan borrowings and for general corporate purposes.

Utility Matters

On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff's formal complaint, issued on June 11, 2012, pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage. On February 19, 2013, the PUC entered a final order (the “Final Order”) in which PUC Commissioners adopted the Joint Settlement, with certain modifications. The Final Order requires UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $0.4 million to $0.5 million; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities' consolidated financial position, results of operations or cash flows.

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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. Our International Propane operations have 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, to reduce market risk associated with a portion of their 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, including the cost of financial instruments used to hedge purchased gas costs. 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 NYMEX to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility's PGC recovery mechanism. At June 30, 2013, the fair values of Gas Utility’s natural gas futures and option contracts were net losses of $1.4 million.

Electric Utility's DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of financial transmission rights (“FTRs”) and forward electricity purchase contracts, associated with our Electric Utility operations. At June 30, 2013, the fair values of Electric Utility’s electricity supply contracts were net losses of $6.1 million. At June 30, 2013, the fair values of Electric Utility’s FTRs were not material.

In addition, 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, 2013, 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, 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, ICE and over-the-counter natural gas and electricity futures and natural gas basis swap contracts or enters into fixed-price supply arrangements. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to hedge a portion of its anticipated sales of electricity from its electricity generation facilities. 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 propane sales agreements. In order to manage the market price risk relating to substantially all of its fixed-price propane sales agreements, Midstream & Marketing enters into price swap and option contracts.

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UGI CORPORATION AND SUBSIDIARIES

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 UGID's results.

The fair value of unsettled commodity price risk sensitive derivative instruments held at June 30, 2013 (excluding those Gas Utility and Electric Utility commodity derivative instruments which are refundable to or recoverable from customers) was a loss of $14.8 million. A hypothetical 10% adverse change in the market price of LPG, gasoline, natural gas, electricity and electricity transmission congestion charges would increase such loss by approximately $35.2 million at June 30, 2013.

Interest Rate Risk

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

Our variable-rate debt at June 30, 2013, includes our bank loan borrowings and Antargaz’ and Flaga’s variable-rate term loans. These debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz and Flaga have effectively fixed the underlying euribor interest rates on their term loans through their scheduled maturity dates through the use of interest rate swaps. At June 30, 2013, combined borrowings outstanding under these variable-rate debt agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled $135.9 million.

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, 2013 (including pay-fixed, receive-variable interest rate swaps) was a loss of $38.8 million. A hypothetical 10% adverse change in the three-month euribor would increase such loss by approximately $10.3 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. From time to time we use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). At June 30, 2013, there were no unsettled net investment hedges outstanding. 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 at June 30, 2013, by approximately $89.8 million, which amount would be reflected in other comprehensive income.

In addition, in order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar denominated LPG product purchases during the months of October through March through the use of forward foreign exchange contracts. The amount of dollar-denominated purchases of LPG 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.

From time to time, the Company may enter into foreign currency exchange transactions to economically hedge the local-currency purchase price of anticipated foreign business acquisitions. These transactions do not qualify for hedge accounting treatment and any changes in fair value are recorded in other income, net.

The fair value of unsettled foreign currency exchange rate risk sensitive derivative instruments held at June 30, 2013, was a loss of $0.8 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 approximately $19.7 million.

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

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise large energy companies and major U.S. and international financial

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UGI CORPORATION AND SUBSIDIARIES

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 our derivative instrument 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 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, 2013 and 2012, restricted cash in brokerage accounts totaled $6.0 million and $7.6 million, respectively.

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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 Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this Report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were effective at the reasonable assurance level.

(b) Change in Internal Control over Financial Reporting

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

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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 OLP 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. Effective June 20, 2013, we entered into a settlement agreement with BP and the lawsuit has been dismissed.

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, 2012, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

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UGI CORPORATION AND SUBSIDIARIES

ITEM 6.    EXHIBITS

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

Incorporation by Reference

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.1	UGI Corporation Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.
10.2	UGI Corporation Executive Employee Severance Plan, as amended and restated as of November 16, 2012.
10.3	AmeriGas Propane, Inc. Senior Executive Employee Severance Plan, as amended and restated as of November 15, 2012.	AmeriGas Partners, L.P.	Form 10-Q (6/30/2013)	10.1
10.4	AmeriGas Propane, Inc. Executive Employee Severance Plan, as amended and restated as of November 15, 2012.	AmeriGas Partners, L.P.	Form 10-Q (6/30/2013)	10.2
10.5	UGI Utilities, Inc. Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.	UGI Utilities, Inc.	Form 10-Q (6/30/2013)	10.1
10.6	Letter Agreement, dated as of June 10, 2013, amending SST Service Agreement No. 79133 dated March 29, 2012 between Columbia Gas Transmission, LLC and UGI Utilities, Inc.	UGI Utilities, Inc.	Form 10-Q (6/30/2013)	10.3
10.7	FTS Service Agreement No. 46284 dated July 23, 2013 between Columbia Gas Transmission, LLC and UGI Utilities, Inc.	UGI Utilities, Inc.	Form 8-K (7/23/2013)	10.1
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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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 2, 2013	By:	/s/ Kirk R. Oliver
			Kirk R. Oliver
			Chief Financial Officer
Date:	August 2, 2013	By:	/s/ Davinder S. Athwal
			Davinder S. Athwal
			Vice President - Accounting and
			Financial Control and Chief Risk Officer

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UGI CORPORATION AND SUBSIDIARIES

EXHIBIT INDEX

10.1	UGI Corporation Senior Executive Employee Severance Plan, as amended and restated as of November 16, 2012.
10.2	UGI Corporation Executive Employee Severance Plan, as amended and restated as of November 16, 2012.
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended June 30, 2013, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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EX-10.1

EXHIBIT 10.1

UGI CORPORATION

SENIOR EXECUTIVE EMPLOYEE

SEVERANCE PLANAs amended as of November 16, 2012

UGI CORPORATION

SENIOR EXECUTIVE EMPLOYEE

SEVERANCE PLAN

TABLE OF CONTENTS

Page

ARTICLE I PURPOSE AND TERM OF PLAN	1
ARTICLE II DEFINITIONS	2
ARTICLE III PARTICIPATION AND ELIGIBILITY FOR BENEFITS	6
ARTICLE IV BENEFITS	8
ARTICLE V METHOD AND DURATION OF BENEFIT PAYMENTS	11
ARTICLE VI ADMINISTRATION	12
ARTICLE VII AMENDMENT AND TERMINATION	14
ARTICLE VIII DUTIES OF THE COMPANY	15
ARTICLE IX CLAIMS PROCEDURES	16
ARTICLE X MISCELLANEOUS	18

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ARTICLE IPURPOSE AND TERM OF PLAN

Section 1.01Purpose of the Plan. This Senior Executive Employee Severance Plan is applicable to Executive Employees (as defined below) of UGI Corporation and its Affiliates (as defined below). The Plan is intended to help alleviate financial hardships that may be experienced by Executive Employees whose employment is involuntary terminated. The Plan is intended to be a “severance pay plan” for purposes of ERISA (as defined below). The benefits paid by the Plan are not deferred compensation, and no employee shall have a vested right to such benefits. The Plan has been drafted to give the Company (as defined below) broad discretion in designating individuals who are eligible for benefits and the amount of such benefits. All actions taken by the Company shall be in its role as the plan sponsor and not as a fiduciary.

Section 1.02Term of the Plan. The Plan has been amended and restated as of November 16, 2012. The Plan will continue until such time as the Company, acting in its sole discretion, elects to modify, supersede or terminate it in accordance with the further provisions hereof.

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ARTICLE II

DEFINITIONS

Section 2.01“Administrative Committee” shall mean the administrative committee designated pursuant to Article VI of the Plan to administer the Plan in accordance with its terms, or its delegate.

Section 2.02“Affiliate” shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended.

Section 2.03“Annual Compensation” shall mean the Participant’s annual base salary and applicable target annual bonus amount (if any) in effect on the Participant’s Employment Termination Date.

Section 2.04“Benefit” or “Benefits” shall mean any or all of the benefits that a Participant is entitled to receive pursuant to Article IV of the Plan.

Section 2.05“Board of Directors” shall mean the Board of Directors of the Company, or any successor thereto.

Section 2.06“Change in Control” shall mean a change of control of the Company as defined in the Company’s 2013 Omnibus Incentive Compensation Plan, as amended from time to time, or a successor plan.

Section 2.07“Change in Control Agreement” shall mean a written Change in Control Agreement between an employee and the Company or an Affiliate.

Section 2.08“Chief Executive Officer” shall mean the individual serving as the Chief Executive Officer of the Company as of the date of reference.

Section 2.09“Chief Operating Officer” shall mean the individual serving as the Chief Operating Officer of the Company as of the date of reference.

Section 2.10“COBRA Cost” shall mean the applicable premium under section 4980B(f)(4) of the Code for continued medical and dental COBRA coverage under the benefit plans of the Company or an Affiliate.

Section 2.11“COBRA Coverage” shall mean continued medical and dental coverage under benefit plans of the Company or an Affiliate, as determined under section 4980B of the Code.

Section 2.12“Code” shall mean the Internal Revenue Code of 1986, as amended.

2

Section 2.13“Company” shall mean UGI Corporation, a Pennsylvania corporation, and any corporation succeeding to the business of UGI Corporation by merger, consolidation, liquidation, purchase of assets or stock or similar transaction.

Section 2.14“Compensation Committee” shall mean the Compensation and Management Development Committee of the Board of Directors.

Section 2.15“Employment Commencement Date” shall mean the most recent date on which a Participant became an employee of the Company or an Affiliate of the Company or, if the Company determines that service before an acquisition shall be taken into account, the most recent date on which a Participant became an employee of an entity whose business or assets have been acquired by the Company or an Affiliate.

Section 2.16“Employment Termination Date” shall mean the date on which the Participant separates from service with the Company and its Affiliates within the meaning of section 409A of the Code.

Section 2.17“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended.

Section 2.18“Executive Annual Bonus Plan” shall mean the UGI Corporation Executive Annual Bonus Plan as in effect from time to time.

Section 2.19“Executive Employee” shall mean any of the following employees who are employed in the United States:

(a)An executive level employee of the Company who participates in the Executive Annual Bonus Plan and who has a Change in Control Agreement in effect with the Company or an Affiliate; or

(b)An executive level employee of the Company or an Affiliate who is employed in the United States and who is designated in writing by the Compensation Committee as eligible to participate in this Plan.

In no event shall any of the following persons be considered an employee for purposes of the Plan: (i) employees who are employed outside the United States, (ii) independent contractors, (iii) persons performing services pursuant to an arrangement with a third party leasing organization, (iv) any person whom the Company determines, in its sole discretion, is not a common law employee, whether or not any such person is later determined to have been a common law employee of the Company or an Affiliate, or (v) employees who are eligible to participate in another severance plan maintained by the Company or an Affiliate.

Section 2.20“Executive Equity Plan” shall mean any long-term equity incentive plan of the Company or any of its Affiliates, including without limitation the UGI Corporation 2004 Omnibus Equity Compensation Plan, the UGI Corporation 2013 Omnibus Incentive

3

Compensation Plan, the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan, and the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan.

Section 2.21“Just Cause” shall mean dismissal of an Executive Employee due to (i) misappropriation of funds, (ii) substance abuse or habitual insobriety that adversely affects the Executive Employee’s ability to perform his or her job, (iii) conviction of a crime involving moral turpitude, or (iv) gross negligence in the performance of duties. Disputes with respect to whether Just Cause exists shall be resolved in accordance with Article IX.

Section 2.22“Key Employee” shall mean an employee who, at any time during the 12-month period ending on the identification date, is a “specified employee” under section 409A of the Code, as determined by the Compensation Committee or its delegate. The determination of Key Employees, including the number and identity of persons considered specified employees and the identification date, shall be made by the Compensation Committee or its delegate in accordance with the provisions of section 409A of the Code and the regulations issued thereunder.

Section 2.23“Month of Service” shall mean each calendar month (with each partial month counted as a full month) of continuous service with the Company and its Affiliates beginning on the Participant’s Employment Commencement Date and ending on the Participant’s Employment Termination Date. Months of Service with an entity whose business or assets have been acquired by the Company or an Affiliate shall be counted only if so determined by the Company.

Section 2.24“Monthly Compensation” shall mean the Participant’s Annual Compensation divided by 12.

Section 2.25“Paid Notice” shall mean the cash amount payable to a Participant in lieu of notice as determined pursuant to Section 4.01(a).

Section 2.26“Participant” shall mean any Executive Employee who receives Benefits under the Plan.

Section 2.27“Plan” shall mean the UGI Corporation Senior Executive Employee Severance Plan, as set forth herein, and as the same may from time to time be amended.

Section 2.28“Plan Year” shall mean each fiscal year of the Company during which this Plan is in effect.

Section 2.29“Postponement Period” shall mean, for a Key Employee, the period of six months after separation from service (or such other period as may be required by section 409A of the Code), during which deferred compensation may not be paid to the Key Employee under section 409A of the Code.

Section 2.30“Release” shall mean a release and discharge of the Company, all of its Affiliates, and all affiliated persons and entities from any and all claims, demands and causes of

4

action, other than as to amounts or benefits due to the Participant under any qualified employee retirement plan of the Company or an Affiliate, which shall be in such form as may be proscribed by the Company, acting as Plan sponsor and not as a fiduciary, from time to time and with such modifications as the Company deems appropriate for the Participant’s particular situation.

Section 2.31“Restricted Awards” shall mean restricted stock, stock units, performance units, restricted units, dividend equivalents, distribution equivalents and other equity-based awards, other than stock options, that are granted to a Participant under an Executive Equity Plan.

Section 2.32“Salary Continuation Period” shall mean (i) the number of months of Paid Notice plus (ii) one business day for each month that is included in the Participant’s Months of Service, up to a maximum of one year. Each calendar week is considered to consist of five business days for this purpose.

Section 2.33“Separation Pay” shall mean the cash amount payable to a Participant as determined pursuant to Section 4.01(b).

5

ARTICLE III

PARTICIPATIONAND ELIGIBILITY FOR BENEFITS

Section 3.01General Eligibility Requirement. In its sole discretion, acting in its role as Plan sponsor and not as a fiduciary, the Company may grant a Benefit under this Plan to any Executive Employee whose employment is terminated by the Company or an Affiliate other than for Just Cause, death, or continuous illness, injury or incapacity for a period of six consecutive months. Notwithstanding anything herein to the contrary, an Executive Employee will not be considered to have incurred a termination by the Company or an Affiliate for purposes of this Plan if his or her employment is discontinued due to voluntary resignation or the expiration of a leave of absence, as determined by the Company, acting in its role as Plan sponsor and not as a fiduciary. In addition, the Executive Employee must meet the requirements of Section 3.03 in order to receive a Benefit under this Plan.

Section 3.02Substantially Comparable Employment. Notwithstanding anything herein to the contrary, no Benefits shall be due hereunder to an Executive Employee in connection with the disposition of a business, division or affiliated company by the Company or an Affiliate if substantially comparable terms of employment, as determined by the Company, have been offered to the Executive Employee by the transferee; provided, however, that the Company, acting in its role as Plan sponsor and not as a fiduciary, may determine that the Company or an Affiliate will provide some or all of the Benefits to an Executive Employee whose employment with the Company and its Affiliates is terminated as described in Section 3.01. For purposes of this Plan, “substantially comparable terms of employment” shall mean an executive level position with (i) no reduction in the Executive Employee’s annual base salary as of the date of the transaction, and (ii) no material change in the geographic location at which the Executive Employee must perform services (which, for purposes of this Plan, means a location that is not more than 50 miles from the Executive Employee’s principal place of business immediately before the transaction).

Section 3.03Conditions to Entitlement to Benefits.

(a)As further conditions to entitlement to Benefits under the Plan, all Participants must, prior to the payment of any Benefits due hereunder, (i) sign and not rescind or contest the enforceability of a Release; (ii) ratify any patent assignment, confidentiality, non-solicitation, non-competition and other post-employment activities agreement in effect between the Participant and the Company or an Affiliate; (iii) return to the Company and its Affiliates any and all property of the Company and its Affiliates held by the Participant, including, but not limited to, all reports, manuals, memoranda, computer disks, tapes and data made available to the Participant during the performance of the Participant’s duties, including all copies; (iv) hold confidential any and all information concerning the Company and its Affiliates, whether with respect to its business, subscribers, providers, customers, operations, finances, employees, contractors, or otherwise; and (v) cooperate fully with the Company and its Affiliates to complete the transition of matters with which the Participant is familiar or responsible to other employees

6

and make himself or herself available to answer questions or assist in matters which may require attention after the Participant’s Employment Termination Date. Notwithstanding the foregoing, accrued vacation described in Section 4.01(d) shall be paid without regard to the Participant’s execution of a Release, to the extent required by applicable state law.

(b)If the Administrative Committee determines, in its sole discretion, that the Participant has violated one or more of the foregoing conditions to entitlement to Benefits, the Administrative Committee may determine that the Participant will not receive the Benefits or the Company may discontinue the payment of Benefits under the Plan. Any remedy under this Section 3.03 shall be in addition to, and not in place of, any other remedy the Company and its Affiliates may have, at law or otherwise.

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ARTICLE IV

BENEFITS

Section 4.01Amount of Immediate Cash Benefit. The Company, acting in its role as Plan sponsor and not as a fiduciary, shall determine which Executive Employees shall be awarded a Benefit hereunder and the amount of any such Benefit. The Company may take into account any factors it determines to be relevant in deciding which Executive Employees shall be awarded Benefits and the amount of such Benefits, and need not apply its determinations in a uniform manner to terminated Executive Employees similarly situated. All such decisions shall be final, binding and conclusive with respect to the Executive Employee. Unless the Company determines otherwise, subject in all events to Section 3.03, the amount to be paid to a Participant eligible to receive Benefits under Section 3.01 hereof upon the Participant’s separation from service shall be paid in a lump sum as provided in Section 5.01 hereof and shall equal the sum of the amounts described in subsections (a) through (d), less the amount described in subsection (e), except that any payment under paragraph (c) below will be excluded from the lump sum payment and paid separately as provided below:

(a)Paid Notice as follows:

(i)In the case of the Chief Executive Officer, an amount of Paid Notice equal to 18 months of the Chief Executive Officer’s Monthly Compensation.

(ii)In the case of the Chief Operating Officer, an amount of Paid Notice equal to 12 months of the Chief Operating Officer’s Monthly Compensation.

(iii)In the case of all other Participants, an amount of Paid Notice equal to six months of the Participant’s Monthly Compensation, unless otherwise designated in writing by the Company.

(b)An amount of Separation Pay equal to one day’s pay (calculated by dividing the Participant’s Annual Compensation by 260) for each Month of Service; provided, however, that such amount shall not exceed 100% of the Participant’s Annual Compensation.

(c)The Administrative Committee may determine in its sole discretion that an annual bonus will be paid for the year of termination. The Administrative Committee may take into account factors such as Company and Affiliate performance, individual performance and the portion of the year elapsed prior to the Employment Termination Date. The annual bonus shall not exceed a pro rata portion of the Participant’s target annual bonus for the year of termination. The bonus, if any, shall be paid within 60 days after the Employment Termination Date, unless the Executive Annual Bonus Plan in effect for the year specifically provides otherwise with respect to termination of employment. If a bonus is payable to the Participant under the Executive Annual Bonus Plan for the year of termination, no bonus will be payable under this Plan.

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(d)An amount equal to the Participant’s earned and accrued vacation entitlement, including banked vacation time, and personal holidays through the Participant’s Employment Termination Date.

(e)If the Participant’s employment with the Company and its Affiliates terminates before a Change in Control, the cash amount computed in subsections (a) through (c) above shall be reduced by the amount of cash and the fair market value of any stock, partnership units or other property that is payable to the Participant under Restricted Awards after the Participant’s termination of employment, as determined by the Company, provided that the Restricted Awards are not considered deferred compensation under section 409A of the Code. In order to implement this reduction, if the Company cannot determine the amount payable under Restricted Awards at the Participant’s Employment Termination Date, any amounts payable under such Restricted Awards shall be reduced by the amount of the Benefit paid under subsections (a) through (c) above, provided the Restricted Awards are not considered deferred compensation under section 409A of the Code. In no event shall a Participant be required to return to the Company or an Affiliate any amounts previously paid under this Plan.

(f)The reduction described in subsection (e) shall not apply if the Participant’s employment with the Company and its Affiliates terminates at or after a Change in Control. In addition, the reduction described in subsection (e) shall not apply to any Restricted Awards for which all requirements for payment have been met before the Participant’s Employment Termination Date (for example, if the restriction period for a Restricted Award ends on December 31, 2013, the Restricted Award is payable on February 1, 2014 and the Participant’s employment is terminated on January 15, 2014, the Restricted Award shall not be reduced by the Benefits under this Plan).

Section 4.02Executive Benefits.

(c)If a Participant receives Benefits under Section 4.01, the Company shall pay to the Participant a single lump sum payment, as provided in Section 5.01 and subject to Section 3.03, equal to the COBRA Cost that the Participant would incur if the Participant continued medical and dental coverage under the Company’s benefit plans through the end of the Salary Continuation Period, based on the benefits in effect for the Participant (and where applicable, his or her spouse and dependents) at the Participant’s Employment Termination Date, less the amount that the Participant would be required to contribute for medical and dental coverage if such Participant were an active employee. The cash payment shall include an additional payment equal to 75% of the lump sum payment described in the preceding sentence.

(d)A Participant who receives Benefits under Section 4.01 may elect continuation coverage under the Company’s applicable medical and dental plans during the Salary Continuation Period by paying the COBRA Cost of such coverage, provided such continued coverage would not result in adverse tax consequences to the Participant, Company or an Affiliate and provided such continued coverage is permitted under the applicable medical and dental plans. If the Participant elects such coverage,the Participant shall be responsible for paying the COBRA Cost of such coverage during the Salary Continuation Period in order to be eligible for the coverage. Notwithstanding anything herein to the contrary, any such continued

9

coverage shall be discontinued if, and at the time, the Participant obtains other employment and becomes eligible to participate in the plan of, or is provided similar coverage by, a new employer. Any applicable conversion rights shall be provided to the Participant at the time coverage ceases.COBRA Coverage shall run concurrently with the Salary Continuation Period, and nothing in this Section shall limit the Employee’s right to elect COBRA Coverage for the full period permitted by law.

(e)If a Participant who receives Benefits under Section 4.01 is entitled to receive tax preparation services immediately before his or her termination of employment, the Participant shall be entitled to receive tax preparation services for the final calendar year of his or her employment under the terms of the Company’s tax preparation reimbursement policy. The Company shall reimburse the Participant for the services within 60 days following the Company’s receipt of proof of payment for the services, but in no event later than December 31 of the calendar year following the calendar year in which the expense is incurred, provided that the Company receives proof of payment for the services at least 60 days before such December 31.

(f)The Company shall provide to each Participant who receives benefits under Section 4.01 outplacement services for up to 12 months following his or her Employment Termination Date through a vendor selected by the Company.

Section 4.03Retirement Plans. This Plan shall not govern and shall in no way affect the Participant’s interest in, or entitlement to benefits under, any of the qualified retirement plans of the Company or an Affiliate and any payments received under any such plan shall not affect a Participant’s right to any Benefit hereunder.

Section 4.04Effect on Other Benefits.

(a)After a Participant’s termination of employment, the Participant shall not accrue benefits under any benefit plan of the Company or an Affiliate, and a terminated Participant shall not accrue vacation days, paid holidays, paid sick days or other benefits for any part of the Salary Continuation Period.

(b)Notwithstanding anything in this Plan to the contrary, no benefits shall be paid under this Plan if the Participant receives severance benefits under a Change in Control Agreement or any other severance agreement or arrangement with the Company or an Affiliate.

(c)Notwithstanding anything herein to the contrary, the Benefits payable under this Plan to any Participant may be reduced by any and all payments required to be made by the Company or an Affiliate under federal, state and local law, including the Worker Adjustment and Retraining Notification Act, 29 U.S.C. Section 2101 et. seq. or under any employment agreement or special severance arrangement, as determined by the Company, acting as Plan sponsor and not as a fiduciary.

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ARTICLE V

METHOD AND DURATION OF BENEFIT PAYMENTS

Section 5.01Method of Payment. The cash Benefit to which a Participant is entitled, pursuant to Article IV, shall be paid in a lump sum payment. Payment shall be made within 60 days following the Participant’s Employment Termination Date, subject to the fulfillment of all conditions for payment of the Benefit set forth in Section 4.01 and compliance with all requirements of Section 3.03. Payment shall be made by mail to the last address provided by the Participant to the Company or an Affiliate. All payments under the Plan are subject to applicable federal, state and local taxes.

Section 5.02Section 409A.

(a)Notwithstanding any provision of the Plan to the contrary, if required by section 409A of the Code and if a Participant is a Key Employee, no Benefits shall be paid to the Participant during the Postponement Period. If a Participant is a Key Employee and payment of Benefits is required to be delayed for the Postponement Period under section 409A, the accumulated amounts withheld on account of section 409A of the Code shall be paid in a lump sum payment within 30 days after the end of the Postponement Period. If the Participant dies during the Postponement Period prior to the payment of Benefits, the amounts withheld on account of section 409A of the Code shall be paid to the Participant’s estate within 60 days after the Participant’s death.

(b)This Agreement is intended to meet the requirements of the “short-term deferral” exception, the “separation pay” exception and other exceptions under section 409A of the Code. Notwithstanding anything in this Plan to the contrary, if required by section 409A, payments may only be made under this Plan upon an event and in a manner permitted by section 409A, to the extent applicable. As used in the Plan, the term “termination of employment” shall mean the Participant’s separation from service with the Company and its Affiliates within the meaning of section 409A and the regulations promulgated thereunder. For purposes of section 409A, the right to a series of payments under the Plan shall be treated as a right to a series of separate payments. All reimbursements and in-kind benefits provided under the Plan shall be made or provided in accordance with the requirements of section 409A of the Code. In no event may a Participant designate the year of payment for any amounts payable under the Plan. Notwithstanding any provision of the Plan to the contrary, if the payments and benefits provided for under the Plan are subject to section 409A, in no event shall the timing of a Participant’s execution of the Release, directly or indirectly, result in the Participant designating the calendar year of payment, and if a payment that is subject to execution of the Release could be made in more than one taxable year, payment shall be made in the later taxable year.

Section 5.03Payments After Death. If a Participant dies after separation from service and before the Participant has received any Benefit that the Participant is entitled to receive under Article IV, any unpaid Benefit that the Participant would otherwise have received shall be payable to the Participant’s estate.

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ARTICLE VI

ADMINISTRATION

Section 6.01Appointment. The Administrative Committee shall consist of one or more persons appointed by the Compensation Committee. Administrative Committee members may be, but need not be, employees of the Company.

Section 6.02Tenure. Administrative Committee members shall serve at the pleasure of the Compensation Committee. Administrative Committee members may resign at any time on ten days’ written notice, and Administrative Committee members may be discharged, with or without cause, at any time by the Compensation Committee.

Section 6.03Authority and Duties. It shall be the duty of the Administrative Committee, on the basis of information supplied to it by the Company, to determine the eligibility of each Participant for Benefits under the Plan, to determine the amount of Benefits to which each such Participant may be entitled, and to determine the manner, time of payment and other requirements of payment of Benefits consistent with the provisions hereof. The Company shall make such payments as are certified to it by the Administrative Committee to be due to Participants. The Administrative Committee shall have the full power and discretionary authority to construe, interpret and administer the Plan, to correct deficiencies therein, and to supply omissions. All decisions, actions, and interpretations of the Administrative Committee shall be final, binding, and conclusive upon the parties. The Administrative Committee may delegate ministerial and other responsibilities to one or more employees of the Company or its Affiliates.

Section 6.04Action by the Administrative Committee. A majority of the members of the Administrative Committee shall constitute a quorum for the transaction of business at a meeting of the Administrative Committee. Any action of the Administrative Committee may be taken upon the affirmative vote of a majority of the members of the Administrative Committee at a meeting, or at the direction of the Chairperson, without a meeting, by mail, telephone, or electronic communication; provided that all of the members of the Administrative Committee are informed of their right to vote on the matter before the Administrative Committee and of the outcome of the vote thereon.

Section 6.05Officers of the Administrative Committee. The Administrative Committee shall designate one of its members to serve as Chairperson thereof. The Administrative Committee shall also designate a person to serve as Secretary of the Administrative Committee, which person may be, but need not be, a member of the Administrative Committee.

Section 6.06Compensation of the Administrative Committee. Members of the Administrative Committee shall receive no compensation for their services as such. However, all reasonable expenses of the Administrative Committee shall be paid or reimbursed by the Company upon proper documentation. The Company shall indemnify members of the

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Administrative Committee against personal liability for actions taken in good faith in the discharge of their respective duties as members of the Administrative Committee.

Section 6.07Records, Reporting, and Disclosure. The Administrative Committee shall keep all individual and group records relating to Participants and former Participants and all other records necessary for the proper operation of the Plan. Such records shall be made available to the Company and its Affiliates and to each Participant for examination during business hours except that a Participant shall examine only such records as pertain exclusively to the examining Participant and to the Plan. The Administrative Committee shall prepare and shall file as required by law or regulation all reports, forms, documents and other items required by ERISA, the Code, and every other relevant statute, each as amended, and all regulations thereunder (except that the Company or an Affiliate, as payor of the Benefits, shall prepare and distribute to the proper recipients all forms relating to withholding of income or wage taxes, Social Security taxes, and other amounts which may be similarly reportable).

Section 6.08Actions of the Administrative Committee. All determinations made by the Administrative Committee under the Plan shall be made solely at the discretion of the Administrative Committee. The exercise of discretion by the Administrative Committee need not be uniformly applied to similarly situated Participants and shall be final and binding on each Participant or beneficiary to whom the determination is directed.

Section 6.09Benefits of the Chief Executive Officer. Notwithstanding the foregoing, the Compensation Committee shall serve as the Administrative Committee under the Plan with respect to the Chief Executive Officer of the Company. The Compensation Committee shall make all determinations with respect to the Chief Executive Officer as to any matter that directly pertains to, or affects, the Chief Executive Officer.

Section 6.10Bonding. The Administrative Committee shall arrange any bonding that may be required by law, but no amount in excess of the amount required by law (if any) shall be required by the Plan.

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AMENDMENT AND TERMINATION

Section 7.01Amendment, Suspension and Termination. The Company, by action of its Board of Directors or the Compensation Committee, retains the right, at any time and from time to time, to amend, suspend or terminate the Plan in whole or in part, for any reason, and without either the consent of or the prior notification to any Participant. No such amendment shall give the Company or an Affiliate the right to recover any amount paid to a Participant prior to the date of such amendment or to cause the cessation and discontinuance of payments of Benefits to any person or persons under the Plan already receiving Benefits.

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ARTICLE VIII

DUTIES OF THE COMPANY

Section 8.01Records. The Company shall supply to the Administrative Committee all records and information necessary to the performance of the Administrative Committee’s duties.

Section 8.02Payment. The Company shall make payments from its general assets to Participants in accordance with the terms of the Plan, as directed by the Administrative Committee.

Section 8.03Discretion, Delegation.

(a)Any decisions, actions or interpretations to be made under the Plan by the Company shall be made in its sole discretion, not in any fiduciary capacity and need not be uniformly applied to similarly situated individuals, and such decisions, actions or interpretations shall be final, binding and conclusive upon all parties.

(b)The Company may take actions under the Plan by action of its Board of Directors or the Compensation Committee, or by action of any officer or committee to whom any of the Company’s authority with respect to the Plan shall have been delegated. The Compensation Committee shall be authorized to take all Company actions under the Plan with respect to the Chief Executive Officer.

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ARTICLE IX

CLAIMS PROCEDURES

Section 9.01Application for Benefits. Participants who believe they are eligible for benefits under this Plan may apply for such benefits by completing and filing with the Administrative Committee an application for benefits on a form supplied by the Administrative Committee. Before the date on which benefit payments commence, each such application must be supported by such information as the Administrative Committee deems relevant and appropriate.

Section 9.02Claim. A terminated employee may contest his or her eligibility for the amount of benefit awarded by completing and filing with the Administrative Committee a written request for review in the manner specified by the Administrative Committee. Each such application must be supported by such information as the Administrative Committee deems relevant and appropriate. The Administrative Committee will review the claim and provide notice to the terminated employee, in writing, within 90 days after the claim is filed unless special circumstances require an extension of time for processing the claim. In no event shall the extension exceed a period of 90 days from the end of the initial period. In the event that any claim for benefits is denied in whole or in part, the terminated employee whose claim has been so denied shall be notified of such denial in writing by the Administrative Committee. The notice advising of the denial shall be written in a manner calculated to be understood by the terminated employee and shall set forth: (i) specific references to the pertinent Plan provisions on which the denial is based; (ii) a description of any additional material or information necessary for the claimant to perfect the claim and an explanation as to why such information is necessary; and (iii) an explanation of the Plan's claim procedure and the time limits applicable to such procedures, including a statement of the claimant’s right to bring a civil action under section 502(a) of ERISA following an adverse benefit determination on appeal.

Section 9.03Appeals of Denied Claims for Benefits. All appeals shall be made by the following procedure:

(a)The terminated employee whose claim has been denied shall file with the Administrative Committee a notice of appeal of the denial. Such notice shall be filed within 60 days of notification by the Administrative Committee of the claim denial, shall be made in writing, and shall set forth all of the facts upon which the appeal is based. Appeals not timely filed shall be barred.

(b)The claimant or his duly authorized representative may:

(i)request a review upon written notice to the Administrative Committee;

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(ii)examine the Plan and obtain, upon request and without charge, copies of all information relevant to the claimant’s appeal; and

(iii)submit issues and comments in writing.

(c)The Named Appeals Fiduciary (as described in Section 9.04) shall issue a decision no later than 60 days after receipt of a request for review unless special circumstances, such as the need to hold a hearing, require a longer period of time, in which case a decision shall be rendered as soon as possible, but not later than 120 days after receipt of the terminated employee’s notice of appeal.

(d)The Named Appeals Fiduciary shall consider the merits of the claimant’s written presentations, the merits of any facts or evidence in support of the denial of benefits, and such other facts and circumstances as the Named Appeals Fiduciary shall deem relevant.

(e)The Named Appeals Fiduciary shall render a determination upon the appealed claim which determination shall be accompanied by a written statement setting forth:

(i)specific reasons for the decision, written in a manner calculated to be understood by the claimant;

(ii)specific references to the pertinent Plan provisions on which the decision is based;

(iii)the claimant’s right to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claim for benefits; and

(iv)the claimant’s right to bring a civil action under section 502(a) of ERISA.

Section 9.04Appointment of the Named Appeals Fiduciary. The Named Appeals Fiduciary shall be the person or persons named as such by the Compensation Committee, or, if no such person or persons be named, then the person or persons named by the Administrative Committee as the Named Appeals Fiduciary. Named Appeals Fiduciaries may at any time be removed by the Compensation Committee, and any Named Appeals Fiduciary named by the Administrative Committee may be removed by the Administrative Committee. All such removals may be with or without cause and shall be effective on the date stated in the notice of removal. The Named Appeals Fiduciary shall be a “Named Fiduciary” within the meaning of ERISA, and unless appointed to other fiduciary responsibilities, shall have no authority, responsibility or liability with respect to any matter other than the proper discharge of the functions of the Named Appeals Fiduciary as set forth herein.

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ARTICLE X

MISCELLANEOUS

Section 10.01Nonalienation of Benefits. None of the payments, benefits or rights of any Participant shall be subject to any claim of any creditor, and, in particular, to the fullest extent permitted by law, all such payments, benefits and rights shall be free from attachment, garnishment, trustee’s process, or any other legal or equitable process available to any creditor of such Participant. No Participant shall have the right to alienate, anticipate, commute, pledge, encumber or assign any of the benefits or payments which the Participant may expect to receive, contingently or otherwise, under this Plan.

Section 10.02No Contract of Employment. Neither the establishment of the Plan, nor any modification thereof, nor the creation of any fund, trust or account, nor the payment of any benefits shall be construed as giving any Participant, or any person whosoever, the right to be retained in the service of the Company or an Affiliate, and all Participants shall remain subject to discharge to the same extent as if the Plan had never been adopted.

Section 10.03Severability of Provisions. If any provision of this Plan shall be held invalid or unenforceable by a court of competent jurisdiction, such invalidity or unenforceability shall not affect any other provisions hereof, and this Plan shall be construed and enforced as if such provisions had not been included.

Section 10.04Successors, Heirs, Assigns, and Personal Representatives. This Plan shall be binding upon the heirs, executors, administrators, successors and assigns of the parties, including each Participant, present and future. If a Change in Control occurs, unless the Compensation Committee directs otherwise before the Change in Control, the Company shall require any successor or successors (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, or a division or Affiliate thereof, (i) to acknowledge expressly that this Plan is binding upon and enforceable against such successor in accordance with the terms hereof, (ii) to become jointly and severally obligated with the Company to perform the obligations under this Plan, and (iii) to agree not to amend or terminate the Plan for a period of one year after the Change in Control without the consent of the affected Participant.

Section 10.05Unfunded Plan. The Plan shall not be funded. The Company may, but shall not be required to, set aside or designate an amount necessary to provide the Benefits specified herein (including the establishment of trusts). In any event, no Participant shall have any right to, or interest in, any assets of the Company or an Affiliate which may be applied by the Company or an Affiliate to the payment of Benefits.

Section 10.06Payments to Incompetent Persons. Any Benefit payable to or for the benefit of an incompetent person or other person incapable of receipting therefor shall be deemed paid when paid to such person’s guardian or to the party providing or reasonably appearing to

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provide for the care of such person, and such payment shall fully discharge the Company, its Affiliates, the Administrative Committee, the Compensation Committee and all other parties with respect thereto.

Section 10.07Controlling Law. This Plan shall be construed and enforced according to the laws of the Commonwealth of Pennsylvania, to the extent not preempted by Federal law, without giving effect to any Pennsylvania choice of law provisions.

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EX-10.2

EXHIBIT 10.2

UGI CORPORATION

EXECUTIVE EMPLOYEE SEVERANCE PLAN

As amended as of November 16, 2012

UGI CORPORATION

EXECUTIVE EMPLOYEE

SEVERANCE

TABLE OF CONTENTS

Page

ARTICLE I	PURPOSE AND TERM OF PLAN	1
ARTICLE II	DEFINITIONS	2
ARTICLE III	PARTICIPATION AND ELIGIBLITY FOR BENEFITS	6
ARTICLE IV	BENEFITS	8
ARTICLE V	METHOD AND DURATION OF BENEFIT PAYMENTS	11
ARTICLE VI	ADMINISTRATION	12
ARTICLE VII	AMENDMENT AND TERMINATION	14
ARTICLE VIII	DUTIES OF THE COMPANY	15
ARTICLE IX	CLAIMS AND PROCEDURES	16
ARTICLE X	MISCELLANEOUS	18

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ARTICLE I

PURPOSE AND TERM OF PLAN

Section 1.01Purpose of the Plan. This Executive Employee Severance Plan is applicable to Executive Employees (as defined below) of UGI Corporation and its Affiliates (as defined below). The Plan is intended to help alleviate financial hardships that may be experienced by Executive Employees whose employment is involuntary terminated. The Plan is intended to be a “severance pay plan” for purposes of ERISA (as defined below). The benefits paid by the Plan are not deferred compensation, and no employee shall have a vested right to such benefits. The Plan has been drafted to give the Company (as defined below) broad discretion in designating individuals who are eligible for benefits and the amount of such benefits. All actions taken by the Company shall be in its role as the plan sponsor and not as a fiduciary.

Section 1.02Term of the Plan. The Plan has been amended and restated as of November 16, 2012. The Plan will continue until such time as the Company, acting in its sole discretion, elects to modify, supersede or terminate it in accordance with the further provisions hereof.

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DEFINITIONS

Section 2.01“Administrative Committee” shall mean the administrative committee designated pursuant to Article VI of the Plan to administer the Plan in accordance with its terms, or its delegate.

Section 2.02“Affiliate” shall have the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended.

Section 2.03“Annual Compensation” shall mean the Participant’s annual base salary and applicable target annual bonus amount (if any) in effect on the Participant’s Employment Termination Date.

Section 2.04“Benefit” or “Benefits” shall mean any or all of the benefits that a Participant is entitled to receive pursuant to Article IV of the Plan.

Section 2.05“Board of Directors” shall mean the Board of Directors of the Company, or any successor thereto.

Section 2.06“Change in Control” shall mean a change of control of the Company as defined in the Company’s 2013 Omnibus Incentive Compensation Plan, as amended from time to time, or a successor plan.

Section 2.07“Change in Control Agreement” shall mean a written Change in Control Agreement between an employee and the Company or an Affiliate.

Section 2.08“COBRA Cost” shall mean the applicable premium under section 4980B(f)(4) of the Code for continued medical and dental COBRA coverage under the benefit plans of the Company or an Affiliate.

Section 2.09“COBRA Coverage” shall mean continued medical and dental coverage under the benefit plans of the Company or an Affiliate, as determined under section 4980B of the Code.

Section 2.10“Code” shall mean the Internal Revenue Code of 1986, as amended.

Section 2.11“Company” shall mean UGI Corporation, a Pennsylvania corporation, and any corporation succeeding to the business of UGI Corporation by merger, consolidation, liquidation, purchase of assets or stock or similar transaction.

Section 2.12“Compensation Committee” shall mean the Compensation and Management Development Committee of the Board of Directors.

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Section 2.13“Employment Commencement Date” shall mean the most recent date on which a Participant became an employee of the Company or an Affiliate of the Company or, if the Company determines that service before an acquisition shall be taken into account, the most recent date on which a Participant became an employee of an entity whose business or assets have been acquired by the Company or an Affiliate.

Section 2.14“Employment Termination Date” shall mean the date on which the Participant separates from service with the Company and its Affiliates within the meaning of section 409A of the Code.

Section 2.15“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended.

Section 2.16“Executive Annual Bonus Plan” shall mean the UGI Corporation Executive Annual Bonus Plan as in effect from time to time.

Section 2.17“Executive Employee” shall mean any of the following employees who are employed in the United States:

(a)An executive level employee of the Company who participates in the Executive Annual Bonus Plan and who does not have a Change in Control Agreement in effect with the Company or an Affiliate; or

(b)An executive level employee of the Company or an Affiliate who is employed in the United States and who is designated in writing by the Compensation Committee as eligible to participate in this Plan.

In no event shall any of the following persons be considered an employee for purposes of the Plan: (i) employees who are employed outside the United States, (ii) independent contractors, (iii) persons performing services pursuant to an arrangement with a third party leasing organization, (iv) any person whom the Company determines, in its sole discretion, is not a common law employee, whether or not any such person is later determined to have been a common law employee of the Company or an Affiliate, or (v) employees who are eligible to participate in another severance plan maintained by the Company or an Affiliate.

Section 2.18“Executive Equity Plan” shall mean any long-term equity incentive plan of the Company or any of its Affiliates, including without limitation the UGI Corporation 2004 Omnibus Equity Compensation Plan, the UGI Corporation 2013 Omnibus Incentive Compensation Plan, the AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan, and the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan.

Section 2.19“Just Cause” shall mean dismissal of an Executive Employee due to (i) misappropriation of funds, (ii) substance abuse or habitual insobriety that adversely affects the Executive Employee’s ability to perform his or her job, (iii) conviction of a crime involving moral turpitude, or (iv) gross negligence in the performance of duties. Disputes with respect to whether Just Cause exists shall be resolved in accordance with Article IX.

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Section 2.20“Key Employee” shall mean an employee who, at any time during the 12-month period ending on the identification date, is a “specified employee” under section 409A of the Code, as determined by the Compensation Committee or its delegate. The determination of Key Employees, including the number and identity of persons considered specified employees and the identification date, shall be made by the Compensation Committee or its delegate in accordance with the provisions of section 409A of the Code and the regulations issued thereunder.

Section 2.21“Monthly Compensation” shall mean the Participant’s Annual Compensation divided by 12.

Section 2.22“Paid Notice” shall mean the cash amount payable to a Participant in lieu of notice as determined pursuant to Section 4.01(a).

Section 2.23“Participant” shall mean any Executive Employee who receives Benefits under the Plan.

Section 2.24“Plan” shall mean the UGI Corporation Executive Employee Severance Plan, as set forth herein, and as the same may from time to time be amended.

Section 2.25“Plan Year” shall mean each fiscal year of the Company during which this Plan is in effect.

Section 2.26“Postponement Period” shall mean, for a Key Employee, the period of six months after separation from service (or such other period as may be required by section 409A of the Code), during which deferred compensation may not be paid to the Key Employee under section 409A of the Code.

Section 2.27“Release” shall mean a release and discharge of the Company, all of its Affiliates, and all affiliated persons and entities from any and all claims, demands and causes of action, other than as to amounts or benefits due to the Participant under any qualified employee retirement plan of the Company or an Affiliate, which shall be in such form as may be proscribed by the Company, acting as Plan sponsor and not as a fiduciary, from time to time and with such modifications as the Company deems appropriate for the Participant’s particular situation.

Section 2.28“Restricted Awards” shall mean restricted stock, stock units, performance units, restricted units, dividend equivalents, distribution equivalents and other equity-based awards, other than stock options, that are granted to a Participant under an Executive Equity Plan.

Section 2.29“Salary Continuation Period” shall mean (i) the number of months of Paid Notice plus (ii) the period for which a Participant receives Separation Pay under Section 4.01(b).

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Section 2.30“Separation Pay” shall mean the cash amount payable to a Participant as determined pursuant to Section 4.01(b).

Section 2.31“Weekly Compensation” shall mean the Participant’s Annual Compensation divided by 52.

Section 2.32“Year of Service” shall mean each 12 month period (or part thereof) of continuous service with the Company and its Affiliates beginning on the Participant’s Employment Commencement Date and ending on each anniversary thereof. Years of Service with an entity whose business or assets have been acquired by the Company or an Affiliate shall be counted only if so determined by the Company.

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ARTICLE III

PARTICIPATIONAND ELIGIBILITY FOR BENEFITS

Section 3.01General Eligibility Requirement. In its sole discretion, acting in its role as Plan sponsor and not as a fiduciary, the Company may grant a Benefit under this Plan to any Executive Employee whose employment is terminated by the Company or an Affiliate other than for Just Cause, death, or continuous illness, injury or incapacity for a period of six consecutive months. Notwithstanding anything herein to the contrary, an Executive Employee will not be considered to have incurred a termination by the Company or an Affiliate for purposes of this Plan if his or her employment is discontinued due to voluntary resignation or the expiration of a leave of absence, as determined by the Company, acting in its role as Plan sponsor and not as a fiduciary. In addition, the Executive Employee must meet the requirements of Section 3.03 in order to receive a Benefit under this Plan.

Section 3.02Substantially Comparable Employment. Notwithstanding anything herein to the contrary, no Benefits shall be due hereunder to an Executive Employee in connection with the disposition of a business, division or affiliated company by the Company or an Affiliate if substantially comparable terms of employment, as determined by the Company, have been offered to the Executive Employee by the transferee; provided, however, that the Company, acting in its role as Plan sponsor and not as a fiduciary, may determine that the Company or an Affiliate will provide some or all of the Benefits to an Executive Employee whose employment with the Company and its Affiliates is terminated as described in Section 3.01. For purposes of this Plan, “substantially comparable terms of employment” shall mean an executive level position with (i) no reduction in the Executive Employee’s annual base salary as of the date of the transaction, and (ii) no material change in the geographic location at which the Executive Employee must perform services (which, for purposes of this Plan, means a location that is not more than 50 miles from the Executive Employee’s principal place of business immediately before the transaction).

Section 3.03Conditions to Entitlement to Benefits.

(a)As further conditions to entitlement to Benefits under the Plan, all Participants must, prior to the payment of any Benefits due hereunder, (i) sign and not rescind or contest the enforceability of a Release; (ii) ratify any patent assignment, confidentiality, non-solicitation, non-competition and other post-employment activities agreement in effect between the Participant and the Company or an Affiliate; (iii) return to the Company and its Affiliates any and all property of the Company and its Affiliates held by the Participant, including, but not limited to, all reports, manuals, memoranda, computer disks, tapes and data made available to the Participant during the performance of the Participant’s duties, including all copies; (iv) hold confidential any and all information concerning the Company and its Affiliates, whether with respect to its business, subscribers, providers, customers, operations, finances, employees, contractors, or otherwise; and (v) cooperate fully with the Company and its Affiliates to complete the transition of matters with which the Participant is familiar or responsible to other employees

6

and make himself or herself available to answer questions or assist in matters which may require attention after the Participant’s Employment Termination Date. Notwithstanding the foregoing, accrued vacation described in Section 4.01(d) shall be paid without regard to the Participant’s execution of a Release, to the extent required by applicable state law.

(b)If the Administrative Committee determines, in its sole discretion, that the Participant has violated one or more of the foregoing conditions to entitlement to Benefits, the Administrative Committee may determine that the Participant will not receive the Benefits or the Company may discontinue the payment of Benefits under the Plan. Any remedy under this Section 3.03 shall be in addition to, and not in place of, any other remedy the Company and its Affiliates may have, at law or otherwise.

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ARTICLE IV

BENEFITS

Section 4.01Amount of Immediate Cash Benefit. The Company, acting in its role as Plan sponsor and not as a fiduciary, shall determine which Executive Employees shall be awarded a Benefit hereunder and the amount of any such Benefit. The Company may take into account any factors it determines to be relevant in deciding which Executive Employees shall be awarded Benefits and the amount of such Benefits, and need not apply its determinations in a uniform manner to terminated Executive Employees similarly situated. All such decisions shall be final, binding and conclusive with respect to the Executive Employee. Unless the Company determines otherwise, subject in all events to Section 3.03, the amount to be paid to a Participant eligible to receive Benefits under Section 3.01 hereof upon the Participant’s separation from service shall be paid in a lump sum as provided in Section 5.01 hereof and shall equal the sum of the amounts described in subsections (a) through (d), less the amount described in subsection (e), except that any payment under paragraph (c) below will be excluded from the lump sum payment and paid separately as provided below:

(a)An amount of Paid Notice equal to three months of the Participant’s Monthly Compensation.

(b)An amount of Separation Pay equal to two weeks of the Participant’s Weekly Compensation for each Year of Service; provided, however, that such amount shall not be less than three months of the Participant’s Monthly Compensation and shall not exceed 12 months of the Participant’s Monthly Compensation.

(c)The Administrative Committee may determine in its sole discretion that an annual bonus will be paid for the year of termination. The Administrative Committee may take into account factors such as Company and Affiliate performance, individual performance and the portion of the year elapsed prior to the Employment Termination Date. The annual bonus shall not exceed a pro rata portion of the Participant’s target annual bonus for the year of termination. The bonus, if any, shall be paid within 60 days after the Employment Termination Date, unless the Executive Annual Bonus Plan in effect for the year specifically provides otherwise with respect to termination of employment. If a bonus is payable to the Participant under the Executive Annual Bonus Plan for the year of termination, no bonus will be payable under this Plan.

(d)An amount equal to the Participant’s earned and accrued vacation entitlement, including banked vacation time, and personal holidays through the Participant’s Employment Termination Date.

(e)If the Participant’s employment with the Company and its Affiliates terminates before a Change in Control, the cash amount computed in subsections (a) through (c) above shall be reduced by the amount of cash and the fair market value of any stock, partnership units or other property that is payable to the Participant under Restricted Awards after

8

the Participant’s termination of employment, as determined by the Company, provided that the Restricted Awards are not considered deferred compensation under section 409A of the Code. In order to implement this reduction, if the Company cannot determine the amount payable under Restricted Awards at the Participant’s Employment Termination Date, any amounts payable under such Restricted Awards shall be reduced by the amount of the Benefit paid under subsections (a) through (c) above, provided the Restricted Awards are not considered deferred compensation under section 409A of the Code. In no event shall a Participant be required to return to the Company or an Affiliate any amounts previously paid under this Plan.

(f)The reduction described in subsection (e) shall not apply if the Participant’s employment with the Company and its Affiliates terminates at or after a Change in Control. In addition, the reduction described in subsection (e) shall not apply to any Restricted Awards for which all requirements for payment have been met before the Participant’s Employment Termination Date (for example, if the restriction period for a Restricted Award ends on December 31, 2013, the Restricted Award is payable on February 1, 2014 and the Participant’s employment is terminated on January 15, 2014, the Restricted Award shall not be reduced by the Benefits under this Plan).

Section 4.02Executive Benefits.

(c)If a Participant receives Benefits under Section 4.01, the Company shall pay to the Participant a single lump sum payment, as provided in Section 5.01 and subject to Section 3.03, equal to the COBRA Cost that the Participant would incur if the Participant continued medical and dental coverage under the Company’s benefit plans through the end of the Salary Continuation Period, based on the benefits in effect for the Participant (and where applicable, his or her spouse and dependents) at the Participant’s Employment Termination Date, less the amount that the Participant would be required to contribute for medical and dental coverage if such Participant were an active employee.

(d)A Participant who receives Benefits under Section 4.01 may elect COBRA Coverage according to the terms of the Company’s applicable medical and dental plans. If the Participant elects COBRA Coverage,the Participant shall be responsible for paying the COBRA Cost of such coverage in order to be eligible for the coverage. Any applicable conversion rights shall be provided to the Participant at the time coverage ceases.

(e)Each Participant who receives Benefits under Section 4.01 shall be entitled to receive outplacement services for up to six months following his or her Employment Termination Date through a vendor selected by the Company.

Section 4.03Retirement Plans. This Plan shall not govern and shall in no way affect the Participant’s interest in, or entitlement to benefits under, any of the qualified retirement plans of the Company or an Affiliate and any payments received under any such plan shall not affect a Participant’s right to any Benefit hereunder.

Section 4.04Effect on Other Benefits.

9

(a)After a Participant’s termination of employment, the Participant shall not accrue benefits under any benefit plan of the Company or an Affiliate, and a terminated Participant shall not accrue vacation days, paid holidays, paid sick days or other benefits for any part of the Salary Continuation Period.

(b)Notwithstanding anything in this Plan to the contrary, no benefits shall be paid under this Plan if the Participant receives severance benefits under any other severance agreement or arrangement with the Company or an Affiliate.

(c)Notwithstanding anything herein to the contrary, the Benefits payable under this Plan to any Participant may be reduced by any and all payments required to be made by the Company or an Affiliate under federal, state and local law, including the Worker Adjustment and Retraining Notification Act, 29 U.S.C. Section 2101 et. seq. or under any employment agreement or special severance arrangement, as determined by the Company, acting as Plan sponsor and not as a fiduciary.

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ARTICLE V

METHOD AND DURATION OF BENEFIT PAYMENTS

Section 5.01Method of Payment. The cash Benefit to which a Participant is entitled, pursuant to Article IV, shall be paid in a lump sum payment. Payment shall be made within 60 days following the Participant’s Employment Termination Date, subject to the fulfillment of all conditions for payment of the Benefit set forth in Section 4.01 and compliance with all requirements of Section 3.03. Payment shall be made by mail to the last address provided by the Participant to the Company or an Affiliate. All payments under the Plan are subject to applicable federal, state and local taxes.

Section 5.02Section 409A.

(a)Notwithstanding any provision of the Plan to the contrary, if required by section 409A of the Code and if a Participant is a Key Employee, no Benefits shall be paid to the Participant during the Postponement Period. If a Participant is a Key Employee and payment of Benefits is required to be delayed for the Postponement Period under section 409A, the accumulated amounts withheld on account of section 409A of the Code shall be paid in a lump sum payment within 30 days after the end of the Postponement Period. If the Participant dies during the Postponement Period prior to the payment of Benefits, the amounts withheld on account of section 409A of the Code shall be paid to the Participant’s estate within 60 days after the Participant’s death.

(b)This Agreement is intended to meet the requirements of the “short-term deferral” exception, the “separation pay” exception and other exceptions under section 409A of the Code. Notwithstanding anything in this Plan to the contrary, if required by section 409A, payments may only be made under this Plan upon an event and in a manner permitted by section 409A, to the extent applicable. As used in the Plan, the term “termination of employment” shall mean the Participant’s separation from service with the Company and its Affiliates within the meaning of section 409A and the regulations promulgated thereunder. For purposes of section 409A, the right to a series of payments under the Plan shall be treated as a right to a series of separate payments. All reimbursements and in-kind benefits provided under the Plan shall be made or provided in accordance with the requirements of section 409A of the Code. In no event may a Participant designate the year of payment for any amounts payable under the Plan. Notwithstanding any provision of the Plan to the contrary, if the payments and benefits provided for under the Plan are subject to section 409A, in no event shall the timing of a Participant’s execution of the Release, directly or indirectly, result in the Participant designating the calendar year of payment, and if a payment that is subject to execution of the Release could be made in more than one taxable year, payment shall be made in the later taxable year.

Section 5.03Payments After Death. If a Participant dies after separation from service and before the Participant has received any Benefit that the Participant is entitled to receive under Article IV, any unpaid Benefit that the Participant would otherwise have received shall be payable to the Participant’s estate.

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ARTICLE VI

ADMINISTRATION

Section 6.01Appointment. The Administrative Committee shall consist of one or more persons appointed by the Compensation Committee. Administrative Committee members may be, but need not be, employees of the Company.

Section 6.02Tenure. Administrative Committee members shall serve at the pleasure of the Compensation Committee. Administrative Committee members may resign at any time on ten days’ written notice, and Administrative Committee members may be discharged, with or without cause, at any time by the Compensation Committee.

Section 6.03Authority and Duties. It shall be the duty of the Administrative Committee, on the basis of information supplied to it by the Company, to determine the eligibility of each Participant for Benefits under the Plan, to determine the amount of Benefits to which each such Participant may be entitled, and to determine the manner, time of payment and other requirements of payment of Benefits consistent with the provisions hereof. The Company shall make such payments as are certified to it by the Administrative Committee to be due to Participants. The Administrative Committee shall have the full power and discretionary authority to construe, interpret and administer the Plan, to correct deficiencies therein, and to supply omissions. All decisions, actions, and interpretations of the Administrative Committee shall be final, binding, and conclusive upon the parties. The Administrative Committee may delegate ministerial and other responsibilities to one or more employees of the Company or its Affiliates.

Section 6.04Action by the Administrative Committee. A majority of the members of the Administrative Committee shall constitute a quorum for the transaction of business at a meeting of the Administrative Committee. Any action of the Administrative Committee may be taken upon the affirmative vote of a majority of the members of the Administrative Committee at a meeting, or at the direction of the Chairperson, without a meeting, by mail, telephone, or electronic communication; provided that all of the members of the Administrative Committee are informed of their right to vote on the matter before the Administrative Committee and of the outcome of the vote thereon.

Section 6.05Officers of the Administrative Committee. The Administrative Committee shall designate one of its members to serve as Chairperson thereof. The Administrative Committee shall also designate a person to serve as Secretary of the Administrative Committee, which person may be, but need not be, a member of the Administrative Committee.

Section 6.06Compensation of the Administrative Committee. Members of the Administrative Committee shall receive no compensation for their services as such. However, all reasonable expenses of the Administrative Committee shall be paid or reimbursed by the

12

Company upon proper documentation. The Company shall indemnify members of the Administrative Committee against personal liability for actions taken in good faith in the discharge of their respective duties as members of the Administrative Committee.

Section 6.07Records, Reporting, and Disclosure. The Administrative Committee shall keep all individual and group records relating to Participants and former Participants and all other records necessary for the proper operation of the Plan. Such records shall be made available to the Company and its Affiliates and to each Participant for examination during business hours except that a Participant shall examine only such records as pertain exclusively to the examining Participant and to the Plan. The Administrative Committee shall prepare and shall file as required by law or regulation all reports, forms, documents and other items required by ERISA, the Code, and every other relevant statute, each as amended, and all regulations thereunder (except that the Company or an Affiliate, as payor of the Benefits, shall prepare and distribute to the proper recipients all forms relating to withholding of income or wage taxes, Social Security taxes, and other amounts which may be similarly reportable).

Section 6.08Actions of the Administrative Committee. All determinations made by the Administrative Committee under the Plan shall be made solely at the discretion of the Administrative Committee. The exercise of discretion by the Administrative Committee need not be uniformly applied to similarly situated Participants and shall be final and binding on each Participant or beneficiary to whom the determination is directed.

Section 6.09Bonding. The Administrative Committee shall arrange any bonding that may be required by law, but no amount in excess of the amount required by law (if any) shall be required by the Plan.

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ARTICLE VII

AMENDMENT AND TERMINATION

Section 7.01Amendment, Suspension and Termination. The Company, by action of its Board of Directors or the Compensation Committee, retains the right, at any time and from time to time, to amend, suspend or terminate the Plan in whole or in part, for any reason, and without either the consent of or the prior notification to any Participant. No such amendment shall give the Company or an Affiliate the right to recover any amount paid to a Participant prior to the date of such amendment or to cause the cessation and discontinuance of payments of Benefits to any person or persons under the Plan already receiving Benefits.

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ARTICLE VIII

DUTIES OF THE COMPANY

Section 8.01Records. The Company shall supply to the Administrative Committee all records and information necessary to the performance of the Administrative Committee’s duties.

Section 8.02Payment. The Company shall make payments from its general assets to Participants in accordance with the terms of the Plan, as directed by the Administrative Committee.

Section 8.03Discretion, Delegation.

(a)Any decisions, actions or interpretations to be made under the Plan by the Company shall be made in its sole discretion, not in any fiduciary capacity and need not be uniformly applied to similarly situated individuals, and such decisions, actions or interpretations shall be final, binding and conclusive upon all parties.

(b)The Company may take actions under the Plan by action of its Board of Directors or the Compensation Committee, or by action of any officer or committee to whom any of the Company’s authority with respect to the Plan shall have been delegated.

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ARTICLE IX

CLAIMS PROCEDURES

Section 9.01Application for Benefits. Participants who believe they are eligible for benefits under this Plan may apply for such benefits by completing and filing with the Administrative Committee an application for benefits on a form supplied by the Administrative Committee. Before the date on which benefit payments commence, each such application must be supported by such information as the Administrative Committee deems relevant and appropriate.

Section 9.02Claim. A terminated employee may contest his or her eligibility for the amount of benefit awarded by completing and filing with the Administrative Committee a written request for review in the manner specified by the Administrative Committee. Each such application must be supported by such information as the Administrative Committee deems relevant and appropriate. The Administrative Committee will review the claim and provide notice to the terminated employee, in writing, within 90 days after the claim is filed unless special circumstances require an extension of time for processing the claim. In no event shall the extension exceed a period of 90 days from the end of the initial period. In the event that any claim for benefits is denied in whole or in part, the terminated employee whose claim has been so denied shall be notified of such denial in writing by the Administrative Committee. The notice advising of the denial shall be written in a manner calculated to be understood by the terminated employee and shall set forth: (i) specific references to the pertinent Plan provisions on which the denial is based; (ii) a description of any additional material or information necessary for the claimant to perfect the claim and an explanation as to why such information is necessary; and (iii) an explanation of the Plan's claim procedure and the time limits applicable to such procedures, including a statement of the claimant’s right to bring a civil action under section 502(a) of ERISA following an adverse benefit determination on appeal.

Section 9.03Appeals of Denied Claims for Benefits. All appeals shall be made by the following procedure:

(a)The terminated employee whose claim has been denied shall file with the Administrative Committee a notice of appeal of the denial. Such notice shall be filed within 60 days of notification by the Administrative Committee of the claim denial, shall be made in writing, and shall set forth all of the facts upon which the appeal is based. Appeals not timely filed shall be barred.

(b)The claimant or his duly authorized representative may:

(i)request a review upon written notice to the Administrative Committee;

(ii)examine the Plan and obtain, upon request and without charge, copies of all information relevant to the claimant’s appeal; and

16

(iii)submit issues and comments in writing.

(c)The Named Appeals Fiduciary (as described in Section 9.04) shall issue a decision no later than 60 days after receipt of a request for review unless special circumstances, such as the need to hold a hearing, require a longer period of time, in which case a decision shall be rendered as soon as possible, but not later than 120 days after receipt of the terminated employee’s notice of appeal.

(d)The Named Appeals Fiduciary shall consider the merits of the claimant’s written presentations, the merits of any facts or evidence in support of the denial of benefits, and such other facts and circumstances as the Named Appeals Fiduciary shall deem relevant.

(e)The Named Appeals Fiduciary shall render a determination upon the appealed claim which determination shall be accompanied by a written statement setting forth:

(i)specific reasons for the decision, written in a manner calculated to be understood by the claimant;

(ii)specific references to the pertinent Plan provisions on which the decision is based;

(iii)the claimant’s right to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claim for benefits; and

(iv)the claimant’s right to bring a civil action under section 502(a) of ERISA.

Section 9.04Appointment of the Named Appeals Fiduciary. The Named Appeals Fiduciary shall be the person or persons named as such by the Compensation Committee, or, if no such person or persons be named, then the person or persons named by the Administrative Committee as the Named Appeals Fiduciary. Named Appeals Fiduciaries may at any time be removed by the Compensation Committee, and any Named Appeals Fiduciary named by the Administrative Committee may be removed by the Administrative Committee. All such removals may be with or without cause and shall be effective on the date stated in the notice of removal. The Named Appeals Fiduciary shall be a “Named Fiduciary” within the meaning of ERISA, and unless appointed to other fiduciary responsibilities, shall have no authority, responsibility or liability with respect to any matter other than the proper discharge of the functions of the Named Appeals Fiduciary as set forth herein.

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ARTICLE X

MISCELLANEOUS

Section 10.01Nonalienation of Benefits. None of the payments, benefits or rights of any Participant shall be subject to any claim of any creditor, and, in particular, to the fullest extent permitted by law, all such payments, benefits and rights shall be free from attachment, garnishment, trustee’s process, or any other legal or equitable process available to any creditor of such Participant. No Participant shall have the right to alienate, anticipate, commute, pledge, encumber or assign any of the benefits or payments which the Participant may expect to receive, contingently or otherwise, under this Plan.

Section 10.02No Contract of Employment. Neither the establishment of the Plan, nor any modification thereof, nor the creation of any fund, trust or account, nor the payment of any benefits shall be construed as giving any Participant, or any person whosoever, the right to be retained in the service of the Company or an Affiliate, and all Participants shall remain subject to discharge to the same extent as if the Plan had never been adopted.

Section 10.03Severability of Provisions. If any provision of this Plan shall be held invalid or unenforceable by a court of competent jurisdiction, such invalidity or unenforceability shall not affect any other provisions hereof, and this Plan shall be construed and enforced as if such provisions had not been included.

Section 10.04Successors, Heirs, Assigns, and Personal Representatives. This Plan shall be binding upon the heirs, executors, administrators, successors and assigns of the parties, including each Participant, present and future. If a Change in Control occurs, unless the Compensation Committee directs otherwise before the Change in Control, the Company shall require any successor or successors (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, or a division or Affiliate thereof, (i) to acknowledge expressly that this Plan is binding upon and enforceable against such successor in accordance with the terms hereof, (ii) to become jointly and severally obligated with the Company to perform the obligations under this Plan, and (iii) to agree not to amend or terminate the Plan for a period of one year after the Change in Control without the consent of the affected Participant.

Section 10.05Unfunded Plan. The Plan shall not be funded. The Company may, but shall not be required to, set aside or designate an amount necessary to provide the Benefits specified herein (including the establishment of trusts). In any event, no Participant shall have any right to, or interest in, any assets of the Company or an Affiliate which may be applied by the Company or an Affiliate to the payment of Benefits.

Section 10.06Payments to Incompetent Persons. Any Benefit payable to or for the benefit of an incompetent person or other person incapable of receipting therefor shall be deemed paid when paid to such person’s guardian or to the party providing or reasonably

18

appearing to provide for the care of such person, and such payment shall fully discharge the Company, its Affiliates, the Administrative Committee, the Compensation Committee and all other parties with respect thereto.

Section 10.07Controlling Law. This Plan shall be construed and enforced according to the laws of the Commonwealth of Pennsylvania, to the extent not preempted by Federal law, without giving effect to any Pennsylvania choice of law provisions.

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EX-31.1

EXHIBIT 31.1

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 2, 2013
		/s/ John L. Walsh
		John L. Walsh President and Chief Executive Officer of UGI Corporation

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Kirk R. Oliver, 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 2, 2013
		/s/ Kirk R. Oliver
		Kirk R. Oliver
		Chief Financial Officer of UGI Corporation

EX-32

EXHIBIT 32

Certification by the Chief Executive Officer and Chief Financial Officer

Relating to a Periodic Report Containing Financial Statements

I, John L. Walsh, Chief Executive Officer, and I, Kirk R. Oliver, Chief Financial Officer, of UGI Corporation, a Pennsylvania corporation (the “Company”), hereby certify that to our knowledge:

(1) The Company’s periodic report on Form 10-Q for the period ended June 30, 2013 (the “Form 10-Q”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

CHIEF EXECUTIVE OFFICER		CHIEF FINANCIAL OFFICER
/s/ John L. Walsh		/s/ Kirk R. Oliver
John L. Walsh		Kirk R. Oliver
Date:	August 2, 2013	Date:	August 2, 2013

XML

Defined Benefit Pension and Other Postretirement Plans

9 Months Ended

Jun. 30, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Pension and Other Postretirement Plans

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 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:

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,						Three Months Ended June 30,
	2013			2012			2013			2012
Service cost	$	2.8		$	2.1		$	0.2		$	0.1
Interest cost	5.9			6.1			0.2			0.2
Expected return on assets	(6.9		)	(6.4		)	(0.1		)	(0.1		)
Amortization of:
Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.1		)
Actuarial loss	3.7			2.1			0.1			0.1
Net benefit cost	5.6			4.0			0.3			0.2
Change in associated regulatory liabilities	—			—			0.8			0.8
Net expense	$	5.6		$	4.0		$	1.1		$	1.0
	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Service cost	$	8.5		$	6.4		$	0.5		$	0.3
Interest cost	17.6			18.3			0.7			0.8
Expected return on assets	(20.7		)	(19.2		)	(0.4		)	(0.4		)
Amortization of:
Prior service cost (benefit)	0.2			0.2			(0.2		)	(0.3		)
Actuarial loss	11.2			6.3			0.3			0.3
Net benefit cost	16.8			12.0			0.9			0.7
Change in associated regulatory liabilities	—			—			2.4			2.3
Net expense	$	16.8		$	12.0		$	3.3		$	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 Plan benefits equal to at least the minimum contribution set forth in applicable employee benefit laws. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $2.5 to the Pension Plan during the remainder of Fiscal 2013. During the nine months ended June 30, 2013 and 2012, the Company made cash contributions to the Pension Plan of $13.4 and $25.4, respectively. 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. 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, 2013 and 2012, nor are they expected to be material for all of Fiscal 2013.

We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans (“Supplemental Defined Benefit Plans”). We recorded pre-tax expense associated with these plans of $0.8 and $0.6 for the three months ended June 30, 2013 and 2012, respectively. We recorded pre-tax expense associated with these plans of $2.4 and $2.1 for the nine months ended June 30, 2013 and 2012, respectively. During the nine months ended June 30, 2013, the Company made payments with respect to the Supplemental Defined Benefit Plans totaling $20.6, including $20.0 used to fund trusts established by the Company for Supplemental Defined Benefit Plan participants who chose to defer payment upon retirement.

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Disclosures About Derivative Instruments and Hedging Activities (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Designated as Hedging Instrument [Member] | LPG (millions of gallons) [Member]
Outstanding derivative commodity instruments volumes
Outstanding derivative commodity instruments volumes	236,700,000	231,900,000	236,700,000	231,900,000
Designated as Hedging Instrument [Member] | Natural gas (millions of dekatherms) [Member]
Outstanding derivative commodity instruments volumes
Outstanding derivative commodity instruments volumes	19,400,000	21,200,000	19,400,000	21,200,000
Designated as Hedging Instrument [Member] | Electricity (millions of kilowatt-hours) [Member] | Forward Purchase Contracts [Member]
Outstanding derivative commodity instruments volumes
Outstanding derivative commodity instruments volumes	927,200,000	1,688,400,000	927,200,000	1,688,400,000
Designated as Hedging Instrument [Member] | Electricity (millions of kilowatt-hours) [Member] | Forward Sales Contracts [Member]
Outstanding derivative commodity instruments volumes
Outstanding derivative commodity instruments volumes	451,000,000	131,800,000	451,000,000	131,800,000
Cash Flow Hedges [Member]
Derivative [Line Items]
Derivative Instruments Gain Loss Recognized in Other Comprehensive Income and Noncontrolling Interests Effective Portion	$ (9.1)	$ (72.8)	$ (6.5)	$ (192.4)
Interest Rate Contracts [Member] | Cash Flow Hedges [Member] | Interest Expense/Other Income [Member]
Derivative [Line Items]
Derivative Instruments Gain Loss Recognized in Other Comprehensive Income and Noncontrolling Interests Effective Portion	$ 14.0	$ (16.6)	$ 23.0	$ (29.0)

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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, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Revenues	$ 1,372.3	$ 1,277.2	$ 5,932.6	$ 5,393.5
Costs and expenses:
Cost of sales (excluding depreciation shown below)	827.9	810.2	3,547.3	3,438.6
Operating and administrative expenses	404.7	405.8	1,297.4	1,191.5
Utility taxes other than income taxes	3.7	3.9	12.7	12.9
Depreciation	76.5	69.5	220.0	191.0
Amortization	15.4	15.1	46.3	36.7
Other income, net	(9.0)	(8.1)	(26.5)	(27.1)
Total costs and expenses	1,319.2	1,296.4	5,097.2	4,843.6
Operating income (loss)	53.1	(19.2)	835.4	549.9
(Loss) income from equity investees	0	(0.1)	0.1	(0.2)
Gain (loss) on extinguishments of debt	0	0.1	0	(13.3)
Interest expense	(59.2)	(61.3)	(179.6)	(162.6)
(Loss) income before income taxes	(6.1)	(80.5)	655.9	373.8
Income tax (expense) benefit	(9.0)	4.0	(174.1)	(113.2)
Net (loss) income	(15.1)	(76.5)	481.8	260.6
Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners	29.8	70.2	(192.6)	(46.5)
Net income (loss) attributable to UGI Corporation	$ 14.7	$ (6.3)	$ 289.2	$ 214.1
Earnings (loss) per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)	$ 0.13	$ (0.06)	$ 2.54	$ 1.90
Diluted (in dollars per share)	$ 0.13	$ (0.06)	$ 2.51	$ 1.89
Average common shares outstanding (thousands):
Basic (in shares)	114,240	112,726	113,693	112,484
Diluted (in shares)	116,196	112,726	115,275	113,295
Dividends declared per common share (in dollars per share)	$ 0.2825	$ 0.27	$ 0.8225	$ 0.79

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Significant Accounting Policies

9 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Significant Accounting Policies

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 report the public’s and ETP’s limited partner interests in the Partnership, and outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests.We eliminate all significant intercompany accounts and transactions when we consolidate. Entities in which we do not have control but have 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 that 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, 2012, condensed consolidated balance sheet data was derived from audited financial statements but does 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, 2012 (“Company’s 2012 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 brokerage accounts that are restricted from withdrawal.

Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders 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 June 30,		Nine Months Ended June 30,
	2013	2012	2013	2012
Denominator (thousands of shares):
Average common shares outstanding for basic computation	114,240	112,726	113,693	112,484
Incremental shares issuable for stock options and awards	1,956	—	1,582	811
Average common shares outstanding for diluted computation	116,196	112,726	115,275	113,295

Comprehensive Income. Comprehensive income (loss) comprises net income (loss) and other comprehensive income (loss). Other comprehensive income (loss) 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 and intracompany transaction adjustments.

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

Income Taxes. During the three months ended December 31, 2011, the Company changed the U.S. tax status of a foreign entity. As a result of the change in tax status, we concluded that it was more likely than not that a portion of our foreign tax credits would be utilized and, accordingly, adjusted our foreign tax credit valuation allowance which reduced income tax expense by $4.7 for the nine months ended June 30, 2012.

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.

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Significant Accounting Policies (Policies)

9 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Restricted Cash

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

Earnings Per Common Share

Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders 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 June 30,		Nine Months Ended June 30,
	2013	2012	2013	2012
Denominator (thousands of shares):
Average common shares outstanding for basic computation	114,240	112,726	113,693	112,484
Incremental shares issuable for stock options and awards	1,956	—	1,582	811
Average common shares outstanding for diluted computation	116,196	112,726	115,275	113,295

Comprehensive Income

Comprehensive Income. Comprehensive income (loss) comprises net income (loss) and other comprehensive income (loss). Other comprehensive income (loss) 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 and intracompany transaction adjustments.

Income Taxes

Income Taxes. During the three months ended December 31, 2011, the Company changed the U.S. tax status of a foreign entity. As a result of the change in tax status, we concluded that it was more likely than not that a portion of our foreign tax credits would be utilized and, accordingly, adjusted our foreign tax credit valuation allowance which reduced income tax expense by $4.7 for the nine months ended June 30, 2012.

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.

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Disclosures About Derivative Instruments and Hedging Activities (Details Textual) In Millions, unless otherwise specified				9 Months Ended				9 Months Ended
	Jun. 30, 2013 USD ($)	Sep. 30, 2012 USD ($)	Jun. 30, 2012 USD ($)	Jun. 30, 2013 Foreign Currency [Member] USD ($)	Jun. 30, 2012 Foreign Currency [Member] USD ($)	Jun. 30, 2013 Interest Rate Swaps [Member] EUR (€)	Jun. 30, 2012 Interest Rate Swaps [Member] EUR (€)	Jun. 30, 2012 Interest Rate Protection Agreements [Member] USD ($)	Jun. 30, 2013 Interest Rate Protection Agreements [Member] USD ($)	Jun. 30, 2012 Net Investment Hedges [Member] EUR (€)	Jun. 30, 2013 LPG (millions of gallons) [Member]	Jun. 30, 2013 Natural Gas (millions of dekatherms) [Member]	Jun. 30, 2013 Electricity (millions of kilowatt-hours) [Member] Forward Purchase Contracts [Member]	Jun. 30, 2013 Electricity (millions of kilowatt-hours) [Member] Forward Sales Contracts [Member]	Jun. 30, 2013 Electric transmission congestion - Electric Utility [Member] kWh	Jun. 30, 2012 Electric transmission congestion - Electric Utility [Member] kWh	Jun. 30, 2013 Gas Utility [Member] DTH	Jun. 30, 2012 Gas Utility [Member] DTH	Jun. 30, 2013 Midstream & Marketing [Member] Electric transmission congestion (excluding Electric Utility) [Member] kWh	Jun. 30, 2012 Midstream & Marketing [Member] Electric transmission congestion (excluding Electric Utility) [Member] kWh	Jun. 30, 2013 Electric Utility - Forward Contract [Member] USD ($) kWh	Jun. 30, 2012 Electric Utility - Forward Contract [Member] USD ($) kWh	Jun. 30, 2013 Midstream and Marketing Natural Gas [Member] DTH	Jun. 30, 2012 Midstream and Marketing Natural Gas [Member] DTH	Jun. 30, 2013 Midstream and Marketing Propane Storage [Member] gal	Jun. 30, 2012 Midstream and Marketing Propane Storage [Member] gal
Disclosures About Derivative Instruments Hedging Activities (Textual) [Abstract]
Notional amount (in units)															260,600,000	261,000,000	11,700,000	13,200,000	1,609,200,000	1,285,500,000	327,400,000	654,700,000	2,700,000	4,100,000	1,800,000	2,200,000
Maximum length of time hedged in price risk cash flow hedges (in months)				33 months							19 months	41 months	27 months	14 months			16 months		11 months		11 months
Derivative Liability, Fair Value, Gross Liability	$ 80.7		$ 187.0																		$ 6.1	$ 13.1
Notional amount				170.3	75.0	440.5	441.9	173.0	173.0	14.5
Weighted Average Length if Time Hedged (in months)				14 months							7 months	10 months	9 months	3 months
Recorded loss amount included in Other Income, Net								0.7
Minimum approximate range of estimated dollar-denominated purchases of LPG (as a percent)				15.00%
Maximum approximate range of estimated dollar-denominated purchases of LPG (as a percent)				30.00%
Disclosures About Derivative Instruments Hedging Activities (Additional Textual) [Abstract]
Net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months	15.6
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	2.2
Amount of net gains associated with currency rate risk to be reclassified into earnings during the next 12 months	1.0
Restricted Cash in brokerage accounts	$ 6.0	$ 3.0	$ 7.6

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Debt

9 Months Ended

Jun. 30, 2013

Debt Disclosure [Abstract]

Debt

Debt

On December 18, 2012, Energy Services amended and restated its unsecured credit agreement with a group of banks (“Energy Services Credit Agreement”) to, among other things, increase its borrowing capacity and extend its expiration. The Energy Services Credit Agreement provides for borrowings up to $240 (including a $50 sublimit for letters of credit) and expires in June 2016. The Energy Services Credit Agreement also provides an option to increase the borrowing capacity by up to an additional $30, to a total of $270, upon approval from one or more of the banks.

Under the Energy Services Credit Agreement, Energy Services may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement, does not exceed 2.25 to 1.00. In addition, the Energy Services Credit Agreement requires Energy Services to not exceed a ratio of Consolidated Total Indebtedness, as defined, to Consolidated EBITDA, as defined; a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense, as defined; a maximum ratio of Consolidated Total Indebtedness to Consolidated Total Capitalization, as defined, at any time when Consolidated Total Indebtedness is greater than or equal to $250; and a minimum Consolidated Net Worth, as defined, of $200.

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Defined Benefit Pension and Other Postretirement Plans (Details Textual) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Defined Benefit Pension and Other Postretirement Plans (Textual) [Abstract]
Net cost to sponsor unfunded and non-qualified supplemental executive retirement plans	$ 0.8	$ 0.6	$ 2.4	$ 2.1
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution made to Pension Plan			13.4	25.4
Expected contribution to pensions plans during remainder of fiscal year	2.5		2.5
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions			20.6
Portion used to fund company established trusts [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions			$ 20.0

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Inventories (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Inventories
Total inventories	$ 304.0	$ 356.9	$ 317.3
Non-utility LPG and natural gas [Member]
Inventories
Total inventories	194.6	240.7	220.1
Gas Utility Natural Gas [Member]
Inventories
Total inventories	43.1	57.7	27.8
Materials, Supplies and Other [Member]
Inventories
Total inventories	$ 66.3	$ 58.5	$ 69.4

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Partnership Acquisition of Heritage Propane (Details Textual) (Heritage Propane [Member], USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended
	Jan. 12, 2012
Heritage Propane [Member]
Acquisition (Textual) [Abstract]
Purchase price of the acquisition	$ 2,604.8
Business acquired by parent through subsidiaries for cash	1,472.2
Common units issued by AmeriGas Partners (in units)	29,567,362
Consideration in AmeriGas Partners Common Units	$ 1,132.6

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Goodwill and Intangible Assets (Tables)

9 Months Ended

Jun. 30, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Component of company's intangible assets

Goodwill and intangible assets comprise the following:

	June 30, 2013			September 30, 2012			June 30, 2012
Goodwill (not subject to amortization)	$	2,834.0		$	2,818.3		$	2,756.0
Intangible assets:
Customer relationships, noncompete agreements and other	$	692.6		$	691.9		$	689.3
Trademarks and tradenames (not subject to amortization)	128.4			137.2			189.6
Gross carrying amount	821.0			829.1			878.9
Accumulated amortization	(212.4		)	(170.9		)	(161.2		)
Intangible assets, net	$	608.6		$	658.2		$	717.7

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Partnership Acquisition of Heritage Propane (Tables)

9 Months Ended

Jun. 30, 2013

Business Combinations [Abstract]

Partnership's unaudited consolidated results of operations

The following presents unaudited pro forma income statement and earnings per share data as if the Heritage Acquisition had occurred on October 1, 2011:

	Nine Months Ended June 30,
	2013 (As Reported)		2012 Pro Forma
Revenues	$	5,932.6	$	5,885.2
Net income attributable to UGI Corporation	$	289.2	$	211.4
Earnings per common share attributable to UGI Corporation stockholders:
Basic	$	2.54	$	1.88
Diluted	$	2.51	$	1.87

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Utility Regulatory Assets and Liabilities and Regulatory Matters (Details Textual) (USD $) In Millions, unless otherwise specified				0 Months Ended
	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012	Oct. 03, 2012 Allentown, Pennsylvania Natural Gas Explosion [Member] UGI Utilities [Member]	Feb. 09, 2011 Allentown, Pennsylvania Natural Gas Explosion [Member] UGI Utilities [Member] Person	Jun. 30, 2013 Allentown Incident [Member] UGI Utilities [Member]	Jun. 30, 2013 Revised Penalty [Member] Allentown Incident [Member] UGI Utilities [Member]
Regulatory Assets [Line Items]
Gas utility unrealized gains or losses on derivative financial instruments contracts	$ (1.4)	$ 5.3	$ 0.3
Fair Value of Electric Utility Electricity Supply Contracts	(6.1)	(9.2)	(13.1)
Loss Contingency, Deaths From Natural Gas Explosion					5
Penalty assessed						0.4	0.5
Site Contingency, Accelerated Time Frame Replacing Remainder of Cast-Iron Mains				14 years
Loss Contingency, Agreement Permitted To Retain Current Timeframe for Replacing The Remainder of Their Bare Steel Mains				30 years
Net Book Value of Asset Transferred	$ 2.6

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Nature of Operations (Details)	9 Months Ended
	Jun. 30, 2013
Nature of Operations (Additional Textual) [Abstract]
General Partner held a general partner interest in AmeriGas Partners	1.00%
Percentage of limited partnership interest in AmeriGas Partners	25.30%
Effective ownership interest in AmeriGas OLP	27.10%
Limited Partnership Common Units held in AmeriGas Partners (in units)	23,756,882
General public as limited partner interests in AmeriGas Partners	73.70%
Common Units Owned by Public (in units)	39,492,279
Common Units Owned by ETP (in units)	29,567,362
Subsidiary units issued in secodary offering	7,500,000

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Goodwill and Intangible Assets (Details Textual) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Component of Company's Intangible Assets (Textual) [Abstract]
Amortization expense of intangible assets	$ 13.3	$ 12.4	$ 40.2	$ 31.2
Expected aggregate amortization expense of intangible assets for the next five fiscal years:
Remainder of fiscal 2013	12.5		12.5
Fiscal 2014	50.5		50.5
Fiscal 2015	47.4		47.4
Fiscal 2016	41.3		41.3
Fiscal 2017	$ 35.0		$ 35.0

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Debt (Details Textual) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Jun. 30, 2013
Debt Instrument [Line Items]
Potential Increase to borrowing capacity	$ 30
Borrowing capacity potential increase	270
Energy Services Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	240
Ratio of Consolidated Indebtedness to EBITDA	2.25
Minimum Consolidated Indebtedness	250
Minimum Consolidated Net Worth	200
Energy Services Credit Agreement [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Revolving Credit Agreement Sublimit for Letters of Credit	$ 50

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Fair Value Measurement (Tables)

9 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

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

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, 2013, September 30, 2012 and June 30, 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	2.2		$	7.4		$	—	$	9.6
Foreign currency contracts	$	—		$	1.0		$	—	$	1.0
Interest rate contracts	$	—		$	8.1		$	—	$	8.1
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(8.0	)	$	(24.1	)	$	—	$	(32.1	)
Foreign currency contracts	$	—		$	(1.7	)	$	—	$	(1.7	)
Interest rate contracts	$	—		$	(46.9	)	$	—	$	(46.9	)
September 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	8.6		$	4.5		$	—	$	13.1
Foreign currency contracts	$	—		$	1.8		$	—	$	1.8
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(7.8	)	$	(53.2	)	$	—	$	(61.0	)
Interest rate contracts	$	—		$	(71.9	)	$	—	$	(71.9	)
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5.1		$	12.3		$	—	$	17.4
Foreign currency contracts	$	—		$	7.1		$	—	$	7.1
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(18.0	)	$	(102.0	)	$	—	$	(120.0	)
Interest rate contracts	$	—		$	(67.0	)	$	—	$	(67.0	)

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Segment Information (Details Textual)	9 Months Ended
	Jun. 30, 2013 Reportable_Segments
Segment Reporting Information [Line Items]
Number of reportable segments (in reportable segments)	6
Segment Information (Textual) [Abstract]
General Partner's interest in AmeriGas OLP (as a percent)	1.01%

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Significant Accounting Policies (Tables)

9 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

Shares used in computing basic and diluted earnings per share

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

	Three Months Ended June 30,		Nine Months Ended June 30,
	2013	2012	2013	2012
Denominator (thousands of shares):
Average common shares outstanding for basic computation	114,240	112,726	113,693	112,484
Incremental shares issuable for stock options and awards	1,956	—	1,582	811
Average common shares outstanding for diluted computation	116,196	112,726	115,275	113,295

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Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Tax on (loss) gain on derivative instruments	$ (1.9)	$ 9.3	$ (4.5)	$ 48.6
Tax on reclassifications on derivative instruments	(1.6)	(9.5)	(15.1)	(31.3)
Tax on foreign currency adjustments	(2.4)	11.2	1.8	9.7
Tax on benefit plans	$ (0.2)	$ 0	$ (0.7)	$ (0.2)

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Condensed Consolidated Statements of Changes in Equity (USD $) In Millions	Total	Parent [Member]	Common stock, without par value	Retained earnings	Accumulated other comprehensive income (loss)	Treasury stock	Noncontrolling Interest [Member]	Accumulated Defined Benefit Plans Adjustment [Member] Accumulated other comprehensive income (loss)
Stockholders' Equity Attributable to Noncontrolling Interest at Sep. 30, 2011							$ 213.4
Beginning Balance at Sep. 30, 2011			937.4	1,085.8	(17.7)	(27.8)
Common Stock issued in connection with employee and director plans, net of tax withheld			7.6
Dividend reinvestment plan			1.6			0.6
Excess tax benefits realized on equity-based compensation			0.8
Stock-based compensation expense			7.0
Adjustments to reflect change in ownership of AmeriGas Partners, net of tax			194.4		1.9		(321.4)
Net income attributable to UGI Corporation	214.1			214.1
Cash dividends on Common Stock				(88.7)
Net gains (losses) on derivative instruments, net of tax	(143.9)				(74.1)
Reclassification of net losses on derivative instruments, net of tax	(69.5)				45.8
Benefit plans, net of tax								0.3
Foreign currency, net of tax	(33.9)				(33.9)
Common Stock issued in connection with employee and director plans, net of tax withheld						2.9
Reacquired common stock - employee and director plans						0
Net income attributable to noncontrolling interests, principally in AmeriGas Partners	46.5						46.5
Net losses on derivative instruments							(69.8)
Reclassifications of net losses on derivative instruments							23.7
Dividends and distributions							(126.8)
AmeriGas Partners Common Unit public offering							276.6
AmeriGas Partners Common Units issued for Heritage Acquisition							1,132.6
Other							4.0
Total equity	3,436.8
Stockholders' Equity Attributable to Noncontrolling Interest at Jun. 30, 2012	1,178.8						1,178.8
Ending Balance at Jun. 30, 2012	2,258.0	2,258.0	1,148.8	1,211.2	(77.7)	(24.3)
Stockholders' Equity Attributable to Noncontrolling Interest at Sep. 30, 2012	1,085.7						1,085.7
Beginning Balance at Sep. 30, 2012	2,233.1		1,157.7	1,166.1	(62.0)	(28.7)
Common Stock issued in connection with employee and director plans, net of tax withheld			19.7
Dividend reinvestment plan			1.4			0.8
Excess tax benefits realized on equity-based compensation			5.7
Stock-based compensation expense			8.4
Adjustments to reflect change in ownership of AmeriGas Partners, net of tax			0		0		0
Net income attributable to UGI Corporation	289.2			289.2
Cash dividends on Common Stock				(93.4)
Net gains (losses) on derivative instruments, net of tax	(11.1)				6.6
Reclassification of net losses on derivative instruments, net of tax	(59.7)				22.3
Benefit plans, net of tax								1.1
Foreign currency, net of tax	1.3				1.3
Common Stock issued in connection with employee and director plans, net of tax withheld						20.8
Reacquired common stock - employee and director plans						(19.1)
Net income attributable to noncontrolling interests, principally in AmeriGas Partners	192.6						192.6
Net losses on derivative instruments							(17.8)
Reclassifications of net losses on derivative instruments							37.4
Dividends and distributions							(168.7)
AmeriGas Partners Common Unit public offering							0
AmeriGas Partners Common Units issued for Heritage Acquisition							0
Other							3.0
Total equity	3,630.1
Stockholders' Equity Attributable to Noncontrolling Interest at Jun. 30, 2013	1,132.2						1,132.2
Ending Balance at Jun. 30, 2013	$ 2,497.9	$ 2,497.9	$ 1,192.9	$ 1,361.9	$ (30.7)	$ (26.2)

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Accounting Changes

9 Months Ended

Jun. 30, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Changes

Accounting Changes

New Accounting Standards Not Yet Adopted

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. In February 2013, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance regarding disclosures for items reclassified out of accumulated other comprehensive income (“AOCI”). The new disclosure guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2012. The new disclosures are to be applied prospectively, and early adoption is permitted. We expect to adopt the new guidance in Fiscal 2014. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

Disclosures about Offsetting Assets and Liabilities.In December 2011 (and amended in January 2013), the FASB issued new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new guidance is effective for annual reporting periods beginning on or after January 1, 2013 (Fiscal 2014) and interim periods within those annual periods, and is required to be applied retrospectively. As this guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position.

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Nature of Operations

9 Months Ended

Jun. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations

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 (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; (3) own all or a portion of electricity generation facilities; and (4) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering 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 retail propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”). AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”) and prior to its merger with AmeriGas OLP on July 1, 2013 (the “Merger”), AmeriGas OLP’s principal operating subsidiary Heritage Operating, L.P. (“HOLP”). AmeriGas OLP and HOLP, prior to the Merger are collectively referred to herein as 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, 2013, the General Partner held a 1% general partner interest and 25.3% limited partner interest in AmeriGas Partners and an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises 39,492,279 publicly held Common Units and 29,567,362 Common Units held by a subsidiary of Energy Transfer Partners, L.P. (“ETP”) as a result of the January 12, 2012, acquisition of substantially all of ETP's propane operations (“Heritage Propane”). In July 2013, ETP sold 7,500,000 of the Common Units it held in an underwritten public offering. AmeriGas Partners did not receive any proceeds from the sale of the Common Units by ETP.

Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries conducts (1) an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“Antargaz”); (2) an LPG distribution business in central, northern and eastern Europe (“Flaga”); (3) an LPG distribution business in the United Kingdom (“AvantiGas”); and (4) an LPG distribution business in the Nantong region of China. We refer to our foreign LPG operations collectively as “International Propane.”

Enterprises, through UGI Energy Services, Inc. (“Energy Services”) and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage, natural gas gathering 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 electricity generation facilities located in Pennsylvania. These businesses 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 a first-tier subsidiary. 

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.” UGI Gas, PNG and CPG are collectively referred to as “Gas Utility.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission, and Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Jun. 30, 2013		Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012		Sep. 30, 2012
Segment information
Revenues	$ 1,372.3		$ 1,277.2		$ 5,932.6		$ 5,393.5
Cost of sales	827.9		810.2		3,547.3		3,438.6
Segment profit:
Operating income (loss)	53.1		(19.2)		835.4		549.9
(Loss) income from equity investees	0		(0.1)		0.1		(0.2)
Gain (loss) on extinguishment of debt	0		0.1		0		(13.3)
Interest expense	(59.2)		(61.3)		(179.6)		(162.6)
Income (loss) before income taxes	(6.1)		(80.5)		655.9		373.8
Noncontrolling interests' net income (loss)	(29.8)		(70.2)		192.6		46.5
Depreciation and amortization	91.9		84.6		266.3		227.7
Capital expenditures	107.6		83.7		292.5		237.7
Total assets (at period end)	9,828.8		9,652.2		9,828.8		9,652.2		9,709.7
Bank loans (at period end)	135.9		187.3		135.9		187.3		165.1
Goodwill (at period end)	2,834.0		2,756.0		2,834.0		2,756.0		2,818.3
Eliminations [Member]
Segment information
Revenues	(61.5)	[1]	(33.4)	[1]	(181.1)	[1]	(134.2)	[1]
Cost of sales	(60.1)	[1]	(32.1)	[1]	(176.2)	[1]	(130.7)	[1]
Segment profit:
Operating income (loss)	(0.2)	[1]			(1.1)	[1]	0
Income (loss) before income taxes	(0.2)		0		(1.1)		0
Depreciation and amortization	(0.1)				(0.1)
Capital expenditures	(0.1)				(1.1)
Total assets (at period end)	(95.9)		(87.4)		(95.9)		(87.4)
AmeriGas Propane [Member]
Segment information
Revenues	581.7		571.9		2,634.6		2,411.3
Cost of sales	305.7		334.0		1,370.2		1,447.8
Segment profit:
Operating income (loss)	6.6		(48.4)		403.9		206.7
Gain (loss) on extinguishment of debt	0		0.1		0		(13.3)
Interest expense	(41.2)		(41.8)		(124.2)		(103.4)
Income (loss) before income taxes	(34.6)		(90.1)		279.7		90.0
Partnership EBITDA	59.1	[2]	1.8	[2]	550.5	[3]	310.0	[3]
Noncontrolling interests' net income (loss)	(29.6)		(70.0)		192.4		46.2
Depreciation and amortization	52.5		49.5		150.5		118.5
Capital expenditures	26.3		25.2		80.7		70.3
Total assets (at period end)	4,388.1		4,579.5		4,388.1		4,579.5
Bank loans (at period end)	80.0		68.8		80.0		68.8
Goodwill (at period end)	1,929.2		1,866.7		1,929.2		1,866.7
Noncontrolling Interests Principally General Partners Interest in Related Parties	0	[4]	(0.6)	[4]	3.9	[4]	1.9	[4]
Gas Utility [Member]
Segment information
Revenues	126.7		122.3		743.6		696.8
Cost of sales	52.4		51.4		372.7		370.6
Segment profit:
Operating income (loss)	16.1		22.5		191.6		168.7
Interest expense	(9.2)		(9.9)		(28.1)		(30.1)
Income (loss) before income taxes	6.9		12.6		163.5		138.6
Depreciation and amortization	13.1		12.3		38.4		36.6
Capital expenditures	37.3		29.0		90.2		76.5
Total assets (at period end)	2,164.4		2,027.0		2,164.4		2,027.0
Bank loans (at period end)	0		0		0		0
Goodwill (at period end)	182.1		182.1		182.1		182.1
Midstream And Marketing, Energy Services [Member]
Segment information
Revenues	233.0		157.0		764.8		652.5
Cost of sales	213.9		140.0		648.8		553.1
Segment profit:
Operating income (loss)	7.4		6.8		78.2		67.3
Interest expense	(0.6)		(1.2)		(2.4)		(3.6)
Income (loss) before income taxes	6.8		5.6		75.8		63.7
Depreciation and amortization	2.1		0.9		5.6		2.4
Capital expenditures	22.0		7.3		54.8		30.2
Total assets (at period end)	437.0		355.0		437.0		355.0
Bank loans (at period end)	45.5		95.0		45.5		95.0
Goodwill (at period end)	2.8		2.8		2.8		2.8
Midstream & Marketing, Electric Generation [Member]
Segment information
Revenues	15.7		10.9		47.7		27.1
Cost of sales	7.7		6.4		27.9		17.6
Segment profit:
Operating income (loss)	0.8		(1.9)		1.5		(7.9)
Interest expense	0		0		0		0
Income (loss) before income taxes	0.8		(1.9)		1.5		(7.9)
Depreciation and amortization	2.6		2.3		7.5		6.6
Capital expenditures	4.4		6.3		15.4		17.4
Total assets (at period end)	267.2		261.3		267.2		261.3
Bank loans (at period end)	0		0		0		0
Goodwill (at period end)	0		0		0		0
International Propane, Antargaz [Member]
Segment information
Revenues	249.2		211.8		1,121.1		958.7
Cost of sales	148.7		133.6		714.4		597.9
Segment profit:
Operating income (loss)	14.5		(1.2)		129.8		96.3
(Loss) income from equity investees	0		(0.1)		0.1		(0.2)
Interest expense	(6.2)		(6.3)		(19.0)		(19.7)
Income (loss) before income taxes	8.3		(7.6)		110.9		76.4
Noncontrolling interests' net income (loss)	(0.3)		(0.2)		0.1		0.3
Depreciation and amortization	14.0		13.5		42.3		42.6
Capital expenditures	11.7		12.0		37.1		28.0
Total assets (at period end)	1,771.7		1,664.7		1,771.7		1,664.7
Goodwill (at period end)	619.2		605.0		619.2		605.0
International Propane, Flaga & Other [Member]
Segment information
Revenues	182.5		193.4		659.0		646.5
Cost of sales	134.8		153.0		507.1		506.3
Segment profit:
Operating income (loss)	6.5		2.4		30.6		16.8
Interest expense	(1.2)		(1.2)		(3.8)		(3.4)
Income (loss) before income taxes	5.3		1.2		26.8		13.4
Noncontrolling interests' net income (loss)	0.1				0.1
Depreciation and amortization	6.1		4.7		17.4		16.6
Capital expenditures	4.0		2.8		10.3		11.5
Total assets (at period end)	543.1		513.2		543.1		513.2
Bank loans (at period end)	10.4		23.5		10.4		23.5
Goodwill (at period end)	93.7		92.4		93.7		92.4
Corporate & Other [Member]
Segment information
Revenues	45.0	[5]	43.3	[5]	142.9	[5]	134.8	[5]
Cost of sales	24.8	[5]	23.9	[5]	82.4	[5]	76.0	[5]
Segment profit:
Operating income (loss)	1.4	[5]	0.6	[5]	0.9	[5]	2.0	[5]
Interest expense	(0.8)	[5]	(0.9)	[5]	(2.1)	[5]	(2.4)	[5]
Income (loss) before income taxes	0.6	[5]	(0.3)	[5]	(1.2)	[5]	(0.4)	[5]
Depreciation and amortization	1.6	[5]	1.4	[5]	4.7	[5]	4.4	[5]
Capital expenditures	2.0	[5]	1.1	[5]	5.1	[5]	3.8	[5]
Total assets (at period end)	353.2	[5]	338.9	[5]	353.2	[5]	338.9	[5]
Goodwill (at period end)	$ 7.0	[5]	$ 7.0	[5]	$ 7.0	[5]	$ 7.0	[5]

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

[2] The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:Three Months Ended June 30, 2013 2012Partnership EBITDA $59.1 1.8Depreciation and amortization (52.5) (49.5)Gain on extinguishments of debt — (0.1)Noncontrolling interests (i) — (0.6)Operating income (loss) $6.6 $(48.4)(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

[3] The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:Nine Months Ended June 30, 2013 2012Partnership EBITDA $550.5 $310.0Depreciation and amortization (150.5) (118.5)Loss on extinguishments of debt — 13.3Noncontrolling interests (i) 3.9 1.9Operating income $403.9 $206.7(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

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

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

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Segment Information (Tables)

9 Months Ended

Jun. 30, 2013

Segment Reporting Information [Line Items]

Segment Information

Three Months Ended June 30, 2013:

														Midstream & Marketing					International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	1,372.3		$	(61.5	)	(c)	$	581.7		$	126.7		$	233.0		$	15.7	$	249.2		$	182.5		$	45.0
Cost of sales	$	827.9		$	(60.1	)	(c)	$	305.7		$	52.4		$	213.9		$	7.7	$	148.7		$	134.8		$	24.8
Segment profit:
Operating income (loss)	$	53.1		$	(0.2	)		$	6.6		$	16.1		$	7.4		$	0.8	$	14.5		$	6.5		$	1.4
Income from equity investees	—			—				—			—			—			—		—			—			—
Interest expense	(59.2		)	—				(41.2		)	(9.2		)	(0.6		)	—		(6.2		)	(1.2		)	(0.8		)
(Loss) income before income taxes	$	(6.1	)	$	(0.2	)		$	(34.6	)	$	6.9		$	6.8		$	0.8	$	8.3		$	5.3		$	0.6
Partnership EBITDA (a)								$	59.1
Noncontrolling interests’ net income (loss)	$	(29.8	)	$	—			$	(29.6	)	$	—		$	—		$	—	$	(0.3	)	$	0.1		$	—
Depreciation and amortization	$	91.9		$	(0.1	)		$	52.5		$	13.1		$	2.1		$	2.6	$	14.0		$	6.1		$	1.6
Capital expenditures	$	107.6		$	(0.1	)		$	26.3		$	37.3		$	22.0		$	4.4	$	11.7		$	4.0		$	2.0
Total assets (at period end)	$	9,828.8		$	(95.9	)		$	4,388.1		$	2,164.4		$	437.0		$	267.2	$	1,771.7		$	543.1		$	353.2
Bank loans (at period end)	$	135.9		$	—			$	80.0		$	—		$	45.5		$	—	$	—		$	10.4		$	—
Goodwill (at period end)	$	2,834.0		$	—			$	1,929.2		$	182.1		$	2.8		$	—	$	619.2		$	93.7		$	7.0

Three Months Ended June 30, 2012:

														Midstream & Marketing						International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation			Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	1,277.2		$	(33.4	)	(c)	$	571.9		$	122.3		$	157.0		$	10.9		$	211.8		$	193.4		$	43.3
Cost of sales	$	810.2		$	(32.1	)	(c)	$	334.0		$	51.4		$	140.0		$	6.4		$	133.6		$	153.0		$	23.9
Segment profit:
Operating (loss) income	$	(19.2	)	$	—			$	(48.4	)	$	22.5		$	6.8		$	(1.9	)	$	(1.2	)	$	2.4		$	0.6
Income from equity investees	(0.1		)	—				—			—			—			—			(0.1		)	—			—
Gain on extinguishments of debt	0.1			—				0.1			—			—			—			—			—			—
Interest expense	(61.3		)	—				(41.8		)	(9.9		)	(1.2		)	—			(6.3		)	(1.2		)	(0.9		)
(Loss) income before income taxes	$	(80.5	)	$	—			$	(90.1	)	$	12.6		$	5.6		$	(1.9	)	$	(7.6	)	$	1.2		$	(0.3	)
Partnership EBITDA (a)								$	1.8
Noncontrolling interests’ net loss	$	(70.2	)	$	—			$	(70.0	)	$	—		$	—		$	—		$	(0.2	)	$	—		$	—
Depreciation and amortization	$	84.6		$	—			$	49.5		$	12.3		$	0.9		$	2.3		$	13.5		$	4.7		$	1.4
Capital expenditures	$	83.7		$	—			$	25.2		$	29.0		$	7.3		$	6.3		$	12.0		$	2.8		$	1.1
Total assets (at period end)	$	9,652.2		$	(87.4	)		$	4,579.5		$	2,027.0		$	355.0		$	261.3		$	1,664.7		$	513.2		$	338.9
Bank loans (at period end)	$	187.3		$	—			$	68.8		$	—		$	95.0		$	—		$	—		$	23.5		$	—
Goodwill (at period end)	$	2,756.0		$	—			$	1,866.7		$	182.1		$	2.8		$	—		$	605.0		$	92.4		$	7.0

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

Three Months Ended June 30,	2013			2012
Partnership EBITDA	$	59.1		1.8
Depreciation and amortization	(52.5		)	(49.5		)
Gain on extinguishments of debt	—			(0.1		)
Noncontrolling interests (i)	—			(0.6		)
Operating income (loss)	$	6.6		$	(48.4	)

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

(b) Corporate & Other results principally comprise Electric Utility, Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC/R”), net expenses of UGI’s captive general liability insurance company and UGI’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and 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 among Midstream & Marketing, Gas Utility and AmeriGas Propane.

Nine Months Ended June 30, 2013:

														Midstream & Marketing					International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	5,932.6		$	(181.1	)	(c)	$	2,634.6		$	743.6		$	764.8		$	47.7	$	1,121.1		$	659.0		$	142.9
Cost of sales	$	3,547.3		$	(176.2	)	(c)	$	1,370.2		$	372.7		$	648.8		$	27.9	$	714.4		$	507.1		$	82.4
Segment profit:
Operating income	$	835.4		$	(1.1	)		$	403.9		$	191.6		$	78.2		$	1.5	$	129.8		$	30.6		$	0.9
Income from equity investees	0.1			—				—			—			—			—		0.1			—			—
Interest expense	(179.6		)	—				(124.2		)	(28.1		)	(2.4		)	—		(19.0		)	(3.8		)	(2.1		)
Income (loss) before income taxes	$	655.9		$	(1.1	)		$	279.7		$	163.5		$	75.8		$	1.5	$	110.9		$	26.8		$	(1.2	)
Partnership EBITDA (a)								$	550.5
Noncontrolling interests’ net income	$	192.6		$	—			$	192.4		$	—		$	—		$	—	$	0.1		$	0.1		$	—
Depreciation and amortization	$	266.3		$	(0.1	)		$	150.5		$	38.4		$	5.6		$	7.5	$	42.3		$	17.4		$	4.7
Capital expenditures	$	292.5		$	(1.1	)		$	80.7		$	90.2		$	54.8		$	15.4	$	37.1		$	10.3		$	5.1
Total assets (at period end)	$	9,828.8		$	(95.9	)		$	4,388.1		$	2,164.4		$	437.0		$	267.2	$	1,771.7		$	543.1		$	353.2
Bank loans (at period end)	$	135.9		$	—			$	80.0		$	—		$	45.5		$	—	$	—		$	10.4		$	—
Goodwill (at period end)	$	2,834.0		$	—			$	1,929.2		$	182.1		$	2.8		$	—	$	619.2		$	93.7		$	7.0

Nine Months Ended June 30, 2012:

														Midstream & Marketing						International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation			Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	5,393.5		$	(134.2	)	(c)	$	2,411.3		$	696.8		$	652.5		$	27.1		$	958.7		$	646.5		$	134.8
Cost of sales	$	3,438.6		$	(130.7	)	(c)	$	1,447.8		$	370.6		$	553.1		$	17.6		$	597.9		$	506.3		$	76.0
Segment profit:
Operating income (loss)	$	549.9		$	—			$	206.7		$	168.7		$	67.3		$	(7.9	)	$	96.3		$	16.8		$	2.0
Loss from equity investees	(0.2		)	—				—			—			—			—			(0.2		)	—			—
Loss on extinguishments of debt	(13.3		)	—				(13.3		)	—			—			—			—			—			—
Interest expense	(162.6		)	—				(103.4		)	(30.1		)	(3.6		)	—			(19.7		)	(3.4		)	(2.4		)
Income (loss) before income taxes	$	373.8		$	—			$	90.0		$	138.6		$	63.7		$	(7.9	)	$	76.4		$	13.4		$	(0.4	)
Partnership EBITDA (a)								$	310.0
Noncontrolling interests’ net income	$	46.5		$	—			$	46.2		$	—		$	—		$	—		$	0.3		$	—		$	—
Depreciation and amortization	$	227.7		$	—			$	118.5		$	36.6		$	2.4		$	6.6		$	42.6		$	16.6		$	4.4
Capital expenditures	$	237.7		$	—			$	70.3		$	76.5		$	30.2		$	17.4		$	28.0		$	11.5		$	3.8
Total assets (at period end)	$	9,652.2		$	(87.4	)		$	4,579.5		$	2,027.0		$	355.0		$	261.3		$	1,664.7		$	513.2		$	338.9
Bank loans (at period end)	$	187.3		$	—			$	68.8		$	—		$	95.0		$	—		$	—		$	23.5		$	—
Goodwill (at period end)	$	2,756.0		$	—			$	1,866.7		$	182.1		$	2.8		$	—		$	605.0		$	92.4		$	7.0

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

Nine Months Ended June 30,	2013			2012
Partnership EBITDA	$	550.5		$	310.0
Depreciation and amortization	(150.5		)	(118.5		)
Loss on extinguishments of debt	—			13.3
Noncontrolling interests (i)	3.9			1.9
Operating income	$	403.9		$	206.7

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

(b) Corporate & Other results principally comprise Electric Utility, Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC/R”), net expenses of UGI’s captive general liability insurance company and UGI’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and 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 among Midstream & Marketing, Gas Utility and AmeriGas Propane.

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Disclosures About Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding derivative commodity instruments volumes

At June 30, 2013 and 2012, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:

	Volumes
	June 30,
Commodity	2013	2012
LPG (millions of gallons)	236.7	231.9
Natural gas (millions of dekatherms)	19.4	21.2
Electricity forward purchase contracts (millions of kilowatt-hours)	927.2	1688.4
Electricity forward sales contracts (millions of kilowatt-hours)	451.0	131.8

Balance sheet location and fair value of derivative assets and liabilities

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2013 and 2012:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value June 30,				Balance Sheet	Fair Value June 30,
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	7.5	$	4.2	Derivative financial instruments and Other noncurrent liabilities	$	(24.4	)	$	(95.5	)
Foreign currency contracts	Derivative financial instruments and Other assets	1.0		7.1		Other noncurrent liabilities	(0.4		)	—
Interest rate contracts	Derivative financial instruments	8.1		—		Derivative financial instruments and Other noncurrent liabilities	(46.9		)	(67.0		)
Total Derivatives Designated as Hedging Instruments		$	16.6	$	11.3		$	(71.7	)	$	(162.5	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	$	0.1	$	0.6	Derivative financial instruments and Other noncurrent liabilities	$	(7.6	)	$	(13.4	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	$	2.0	$	12.6	Derivative financial instruments	$	(0.1	)	$	(11.1	)
Foreign currency contracts	Derivative financial instruments	—		—		Derivative financial instruments	(1.3		)	—
Total Derivatives		$	18.7	$	24.5		$	(80.7	)	$	(187.0	)

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

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 months ended June 30, 2013 and 2012:

Three Months Ended June 30,	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2013			2012			2013			2012			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(22.8	)	$	(59.3	)	$	(6.9	)	$	(31.0	)	Cost of sales
Foreign currency contracts	(0.3		)	3.1			—			—			Cost of sales
Interest rate contracts	14.0			(16.6		)	(3.6		)	(3.3		)	Interest expense / other income, net
Total	$	(9.1	)	$	(72.8	)	$	(10.5	)	$	(34.3	)
Net Investment Hedges:
Foreign currency contracts	$	—		$	0.9
	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2013			2012
Commodity contracts	$	2.0		$	(15.9	)							Cost of sales
Commodity contracts	(0.1		)	(0.1		)							Operating expenses / other income, net
Foreign currency contracts	(0.9		)	—									Other income, net
Total	$	1.0		$	(16.0	)

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 nine months ended June 30, 2013 and 2012:

Nine Months Ended June 30,	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2013			2012			2013			2012			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(28.1	)	$	(166.2	)	$	(64.1	)	$	(94.4	)	Cost of sales
Foreign currency contracts	(1.4		)	2.8			(0.1		)	2.0			Cost of sales
Interest rate contracts	23.0			(29.0		)	(10.6		)	(8.4		)	Interest expense / other income, net
Total	$	(6.5	)	$	(192.4	)	$	(74.8	)	$	(100.8	)
Net Investment Hedges:
Foreign currency contracts	$	—		$	0.9
	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2013			2012
Commodity contracts	$	2.4		$	(12.6	)							Cost of sales
Commodity contracts	—			0.1									Operating expenses / other income, net
Foreign currency contracts	(1.1		)	0.5									Other income, net
Total	$	1.3		$	(12.0	)

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Partnership Acquisition of Heritage Propane (Details 1) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Partnership unaudited consolidated results of operations
Net income attributable to UGI Corporation	$ 14.7	$ (6.3)	$ 289.2	$ 214.1
Earnings Per Share, Basic	$ 0.13	$ (0.06)	$ 2.54	$ 1.90
Earnings per common share attributable to UGI Corporation stockholders:
Earnings Per Share, Diluted	$ 0.13	$ (0.06)	$ 2.51	$ 1.89
Heritage Propane [Member]
Heritage Acquisition [Line Items]
Revenues			5,932.6
Partnership unaudited consolidated results of operations
Revenues				5,885.2
Net income attributable to UGI Corporation			289.2
Net income attributable to UGI Corporation				$ 211.4
Earnings Per Share, Basic			$ 2.54
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)				$ 1.88
Earnings Per Share, Diluted			$ 2.51
Diluted (in dollars per share)				$ 1.87

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Disclosures About Derivative Instruments and Hedging Activities (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
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 (Loss) Recognized in Income	$ 1.0	$ (16.0)	$ 1.3	$ (12.0)
Cash Flow Hedges [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Gain (loss) recognized in AOCI and noncontrolling interests	(9.1)	(72.8)	(6.5)	(192.4)
Gain (loss) reclassified from AOCI and noncontrolling interest into income	(10.5)	(34.3)	(74.8)	(100.8)
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 (Loss) Recognized in Income	2.0	(15.9)	2.4	(12.6)
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 (Loss) Recognized in Income	(0.1)	(0.1)	0	0.1
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
Gain (loss) recognized in AOCI and noncontrolling interests	(22.8)	(59.3)	(28.1)	(166.2)
Gain (loss) reclassified from AOCI and noncontrolling interest into income	(6.9)	(31.0)	(64.1)	(94.4)
Foreign Currency Contracts [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Other Income [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Gain (Loss) Recognized in Income	(0.9)	0	(1.1)	0.5
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
Gain (loss) recognized in AOCI and noncontrolling interests	(0.3)	3.1	(1.4)	2.8
Gain (loss) reclassified from AOCI and noncontrolling interest into income	0	0	(0.1)	2.0
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
Gain (loss) recognized in AOCI and noncontrolling interests	0	0.9	0	0.9
Interest Rate Contracts [Member] | Cash Flow Hedges [Member] | Interest Expense/Other Income [Member]
Effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interest
Gain (loss) recognized in AOCI and noncontrolling interests	14.0	(16.6)	23.0	(29.0)
Gain (loss) reclassified from AOCI and noncontrolling interest into income	$ (3.6)	$ (3.3)	$ (10.6)	$ (8.4)

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Commitments and Contingencies (Details Textual) (USD $) In Millions, unless otherwise specified	9 Months Ended					12 Months Ended
	Jun. 30, 2013 Environmental matters [Member]	Jun. 30, 2013 Environmental matters [Member] CPG MGP [Member]	Jun. 30, 2013 Environmental matters [Member] PNG MGP [Member]	Jun. 30, 2013 CPG and PNG COAs [Member] UGI Utilities [Member]	Jun. 30, 2012 CPG and PNG COAs [Member] UGI Utilities [Member]	Sep. 30, 2008 CA cylinder investigation [Member] Partnership [Member] lb	Sep. 30, 2008 FTC Investigation [Member] Partnership [Member] lb	Jun. 30, 2013 BP Matter [Member] Partnership [Member] Customer
Commitments and Contingencies [Line Items]
Environmental expenditures cap during calendar year		$ 1.8	$ 1.1
Accrual for environmental loss contingencies				$ 14.4	$ 15.8
Base year for determination of investigation and remediation cost (in years)	5 years
Amount of propane in cylinders before reduction (in pounds)						17	17
Amount of propane in cylinders after reduction (in pounds)						15	15
Alleged number of residential customers (in customers)								400

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Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	$ 320.9	$ 338.4	$ 291.0
Regulatory Liabilities	40.0	28.3	34.0
Postretirement benefits [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Liabilities	14.2	13.1	12.3
Environmental overcollections [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Liabilities	2.9	2.9	3.7
Deferred fuel and power refunds [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Liabilities	14.2	4.4	10.3
State tax benefits - distribution system repairs [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Liabilities	8.0	7.4	7.0
Other [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Liabilities	0.7	0.5	0.7
Income taxes recoverable [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	104.7	103.2	99.9
Underfunded pension and postretirement plans [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	177.8	188.2	144.6
Environmental costs [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	16.6	16.8	16.6
Deferred fuel and power costs [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	4.1	11.6	9.8
Removal costs, net [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	12.1	12.7	11.8
Other [Member]
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	$ 5.6	$ 5.9	$ 8.3

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Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Accounts receivable, allowances for doubtful accounts	$ 48.0	$ 36.1	$ 45.7
Property, plant and equipment, accumulated depreciation and amortization	$ 2,495.4	$ 2,286.0	$ 2,226.8
UGI Common Stock, without par value (in dollars per share)
UGI Common Stock, without par value, shares authorized (in shares)	300,000,000	300,000,000	300,000,000
UGI Common Stock, without par value, shares issued (in shares)	115,759,694	115,624,594	115,623,094

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Segment Information

9 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

Segment Information

Segment Information

Our operations comprise six reportable segments generally based upon products sold, geographic location and regulatory environment. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) Gas Utility; (5) Energy Services; and (6) Electric Generation. We refer to both international segments together as “International Propane” and Energy Services and Electric Generation together as “Midstream & Marketing.” For Fiscal 2012, the Company began reporting its Electric Generation operating segment as a separate reportable segment and our former Electric Utility reportable segment was combined with Corporate & Other. Previously, the Electric Generation operating segment was included in the Energy Services reportable segment. Segment information for the three and nine months ended June 30, 2012 presented below has been adjusted to conform to the current year presentation.

The accounting policies of our reportable segments are the same as those described in Note 2, “Significant Accounting Policies” in the Company’s 2012 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 other reportable segments principally based upon their income before income taxes.

Three Months Ended June 30, 2013:

														Midstream & Marketing					International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	1,372.3		$	(61.5	)	(c)	$	581.7		$	126.7		$	233.0		$	15.7	$	249.2		$	182.5		$	45.0
Cost of sales	$	827.9		$	(60.1	)	(c)	$	305.7		$	52.4		$	213.9		$	7.7	$	148.7		$	134.8		$	24.8
Segment profit:
Operating income (loss)	$	53.1		$	(0.2	)		$	6.6		$	16.1		$	7.4		$	0.8	$	14.5		$	6.5		$	1.4
Income from equity investees	—			—				—			—			—			—		—			—			—
Interest expense	(59.2		)	—				(41.2		)	(9.2		)	(0.6		)	—		(6.2		)	(1.2		)	(0.8		)
(Loss) income before income taxes	$	(6.1	)	$	(0.2	)		$	(34.6	)	$	6.9		$	6.8		$	0.8	$	8.3		$	5.3		$	0.6
Partnership EBITDA (a)								$	59.1
Noncontrolling interests’ net income (loss)	$	(29.8	)	$	—			$	(29.6	)	$	—		$	—		$	—	$	(0.3	)	$	0.1		$	—
Depreciation and amortization	$	91.9		$	(0.1	)		$	52.5		$	13.1		$	2.1		$	2.6	$	14.0		$	6.1		$	1.6
Capital expenditures	$	107.6		$	(0.1	)		$	26.3		$	37.3		$	22.0		$	4.4	$	11.7		$	4.0		$	2.0
Total assets (at period end)	$	9,828.8		$	(95.9	)		$	4,388.1		$	2,164.4		$	437.0		$	267.2	$	1,771.7		$	543.1		$	353.2
Bank loans (at period end)	$	135.9		$	—			$	80.0		$	—		$	45.5		$	—	$	—		$	10.4		$	—
Goodwill (at period end)	$	2,834.0		$	—			$	1,929.2		$	182.1		$	2.8		$	—	$	619.2		$	93.7		$	7.0

Three Months Ended June 30, 2012:

														Midstream & Marketing						International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation			Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	1,277.2		$	(33.4	)	(c)	$	571.9		$	122.3		$	157.0		$	10.9		$	211.8		$	193.4		$	43.3
Cost of sales	$	810.2		$	(32.1	)	(c)	$	334.0		$	51.4		$	140.0		$	6.4		$	133.6		$	153.0		$	23.9
Segment profit:
Operating (loss) income	$	(19.2	)	$	—			$	(48.4	)	$	22.5		$	6.8		$	(1.9	)	$	(1.2	)	$	2.4		$	0.6
Income from equity investees	(0.1		)	—				—			—			—			—			(0.1		)	—			—
Gain on extinguishments of debt	0.1			—				0.1			—			—			—			—			—			—
Interest expense	(61.3		)	—				(41.8		)	(9.9		)	(1.2		)	—			(6.3		)	(1.2		)	(0.9		)
(Loss) income before income taxes	$	(80.5	)	$	—			$	(90.1	)	$	12.6		$	5.6		$	(1.9	)	$	(7.6	)	$	1.2		$	(0.3	)
Partnership EBITDA (a)								$	1.8
Noncontrolling interests’ net loss	$	(70.2	)	$	—			$	(70.0	)	$	—		$	—		$	—		$	(0.2	)	$	—		$	—
Depreciation and amortization	$	84.6		$	—			$	49.5		$	12.3		$	0.9		$	2.3		$	13.5		$	4.7		$	1.4
Capital expenditures	$	83.7		$	—			$	25.2		$	29.0		$	7.3		$	6.3		$	12.0		$	2.8		$	1.1
Total assets (at period end)	$	9,652.2		$	(87.4	)		$	4,579.5		$	2,027.0		$	355.0		$	261.3		$	1,664.7		$	513.2		$	338.9
Bank loans (at period end)	$	187.3		$	—			$	68.8		$	—		$	95.0		$	—		$	—		$	23.5		$	—
Goodwill (at period end)	$	2,756.0		$	—			$	1,866.7		$	182.1		$	2.8		$	—		$	605.0		$	92.4		$	7.0

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

Three Months Ended June 30,	2013			2012
Partnership EBITDA	$	59.1		1.8
Depreciation and amortization	(52.5		)	(49.5		)
Gain on extinguishments of debt	—			(0.1		)
Noncontrolling interests (i)	—			(0.6		)
Operating income (loss)	$	6.6		$	(48.4	)

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

(b) Corporate & Other results principally comprise Electric Utility, Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC/R”), net expenses of UGI’s captive general liability insurance company and UGI’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and 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 among Midstream & Marketing, Gas Utility and AmeriGas Propane.

Nine Months Ended June 30, 2013:

														Midstream & Marketing					International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	5,932.6		$	(181.1	)	(c)	$	2,634.6		$	743.6		$	764.8		$	47.7	$	1,121.1		$	659.0		$	142.9
Cost of sales	$	3,547.3		$	(176.2	)	(c)	$	1,370.2		$	372.7		$	648.8		$	27.9	$	714.4		$	507.1		$	82.4
Segment profit:
Operating income	$	835.4		$	(1.1	)		$	403.9		$	191.6		$	78.2		$	1.5	$	129.8		$	30.6		$	0.9
Income from equity investees	0.1			—				—			—			—			—		0.1			—			—
Interest expense	(179.6		)	—				(124.2		)	(28.1		)	(2.4		)	—		(19.0		)	(3.8		)	(2.1		)
Income (loss) before income taxes	$	655.9		$	(1.1	)		$	279.7		$	163.5		$	75.8		$	1.5	$	110.9		$	26.8		$	(1.2	)
Partnership EBITDA (a)								$	550.5
Noncontrolling interests’ net income	$	192.6		$	—			$	192.4		$	—		$	—		$	—	$	0.1		$	0.1		$	—
Depreciation and amortization	$	266.3		$	(0.1	)		$	150.5		$	38.4		$	5.6		$	7.5	$	42.3		$	17.4		$	4.7
Capital expenditures	$	292.5		$	(1.1	)		$	80.7		$	90.2		$	54.8		$	15.4	$	37.1		$	10.3		$	5.1
Total assets (at period end)	$	9,828.8		$	(95.9	)		$	4,388.1		$	2,164.4		$	437.0		$	267.2	$	1,771.7		$	543.1		$	353.2
Bank loans (at period end)	$	135.9		$	—			$	80.0		$	—		$	45.5		$	—	$	—		$	10.4		$	—
Goodwill (at period end)	$	2,834.0		$	—			$	1,929.2		$	182.1		$	2.8		$	—	$	619.2		$	93.7		$	7.0

Nine Months Ended June 30, 2012:

														Midstream & Marketing						International Propane
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation			Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	5,393.5		$	(134.2	)	(c)	$	2,411.3		$	696.8		$	652.5		$	27.1		$	958.7		$	646.5		$	134.8
Cost of sales	$	3,438.6		$	(130.7	)	(c)	$	1,447.8		$	370.6		$	553.1		$	17.6		$	597.9		$	506.3		$	76.0
Segment profit:
Operating income (loss)	$	549.9		$	—			$	206.7		$	168.7		$	67.3		$	(7.9	)	$	96.3		$	16.8		$	2.0
Loss from equity investees	(0.2		)	—				—			—			—			—			(0.2		)	—			—
Loss on extinguishments of debt	(13.3		)	—				(13.3		)	—			—			—			—			—			—
Interest expense	(162.6		)	—				(103.4		)	(30.1		)	(3.6		)	—			(19.7		)	(3.4		)	(2.4		)
Income (loss) before income taxes	$	373.8		$	—			$	90.0		$	138.6		$	63.7		$	(7.9	)	$	76.4		$	13.4		$	(0.4	)
Partnership EBITDA (a)								$	310.0
Noncontrolling interests’ net income	$	46.5		$	—			$	46.2		$	—		$	—		$	—		$	0.3		$	—		$	—
Depreciation and amortization	$	227.7		$	—			$	118.5		$	36.6		$	2.4		$	6.6		$	42.6		$	16.6		$	4.4
Capital expenditures	$	237.7		$	—			$	70.3		$	76.5		$	30.2		$	17.4		$	28.0		$	11.5		$	3.8
Total assets (at period end)	$	9,652.2		$	(87.4	)		$	4,579.5		$	2,027.0		$	355.0		$	261.3		$	1,664.7		$	513.2		$	338.9
Bank loans (at period end)	$	187.3		$	—			$	68.8		$	—		$	95.0		$	—		$	—		$	23.5		$	—
Goodwill (at period end)	$	2,756.0		$	—			$	1,866.7		$	182.1		$	2.8		$	—		$	605.0		$	92.4		$	7.0

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

Nine Months Ended June 30,	2013			2012
Partnership EBITDA	$	550.5		$	310.0
Depreciation and amortization	(150.5		)	(118.5		)
Loss on extinguishments of debt	—			13.3
Noncontrolling interests (i)	3.9			1.9
Operating income	$	403.9		$	206.7

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

(b) Corporate & Other results principally comprise Electric Utility, Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC/R”), net expenses of UGI’s captive general liability insurance company and UGI’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and 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 among Midstream & Marketing, Gas Utility and AmeriGas Propane.

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Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Net (loss) income	$ (15.1)	$ (76.5)	$ 481.8	$ 260.6
Net losses on derivative instruments (net of tax of $(1.9), $9.3, $(4.5) and $48.6, respectively)	(11.0)	(63.2)	(11.1)	(143.9)
Reclassifications of net losses on derivative instruments (net of tax of $(1.6), $(9.5), $(15.1) and $(13.3), respectively)	8.9	24.8	59.7	69.5
Foreign currency adjustments (net of tax of $(2.4), $11.2, $1.8 and $9.7, respectively)	8.8	(35.6)	1.3	(33.9)
Benefit plans (net of tax of $(0.2), $(0.0), $(0.7), and $(0.2), respectively	0.3	0.1	1.1	0.3
Other comprehensive income (loss)	7.0	(73.9)	51.0	(108.0)
Comprehensive (loss) income	(8.1)	(150.4)	532.8	152.6
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	37.8	107.3	(212.2)	(0.4)
Comprehensive income (loss) attributable to UGI Corporation	$ 29.7	$ (43.1)	$ 320.6	$ 152.2

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Inventories (Details Textual) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013 Storage_Agreement	Sep. 30, 2012 ft3	Jun. 30, 2012 ft3
Public Utilities, Inventory [Line Items]
Number Of Storage Agreements	3
Volume of gas storage inventories released under SCAAs with non-affiliates (in cubic feet)		3,800,000,000	1,900,000,000
Carrying value of gas storage inventories released under SCAAs with non-affiliates		$ 11.4	$ 5.3
UGI Utilities [Member] | Expires in October 2013 [Member]
Public Utilities, Inventory [Line Items]
Number Of Storage Agreements	1
UGI Utilities [Member] | Expires in October 2015 [Member]
Public Utilities, Inventory [Line Items]
Number Of Storage Agreements	2

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Condensed Consolidated Balance Sheets (unaudited) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Current assets:
Cash and cash equivalents	$ 401.8	$ 319.9	$ 436.5
Restricted cash	6.0	3.0	7.6
Accounts receivable (less allowances for doubtful accounts of $48.0, $36.1 and $45.7, respectively)	752.6	632.6	624.9
Accrued utility revenues	11.8	16.9	15.0
Inventories	304.0	356.9	317.3
Deferred income taxes	27.3	56.8	52.3
Utility regulatory assets	3.7	6.5	2.7
Derivative financial instruments	18.7	13.2	21.6
Prepaid expenses and other current assets	36.1	98.7	59.4
Total current assets	1,562.0	1,504.5	1,537.3
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,495.4, $2,286.0 and $2,226.8, respectively)	4,325.0	4,233.1	4,188.9
Goodwill	2,834.0	2,818.3	2,756.0
Intangible assets, net	608.6	658.2	717.7
Other assets	499.2	495.6	452.3
Total assets	9,828.8	9,709.7	9,652.2
Current liabilities:
Current maturities of long-term debt	195.6	166.7	86.1
Bank loans	135.9	165.1	187.3
Accounts payable	384.5	411.3	346.0
Derivative financial instruments	56.8	100.9	116.5
Other current liabilities	552.9	643.0	577.4
Total current liabilities	1,325.7	1,487.0	1,313.3
Long-term debt	3,298.2	3,347.6	3,475.1
Deferred income taxes	956.9	935.0	832.8
Deferred investment tax credits	4.4	4.6	4.7
Other noncurrent liabilities	613.5	616.7	589.5
Total liabilities	6,198.7	6,390.9	6,215.4
Commitments and contingencies (note 11)
UGI Corporation stockholders' equity
UGI Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,759,694, 115,624,594 and 115,623,094 shares, respectively)	1,192.9	1,157.7	1,148.8
Retained earnings	1,361.9	1,166.1	1,211.2
Accumulated other comprehensive loss	(30.7)	(62.0)	(77.7)
Treasury stock, at cost	(26.2)	(28.7)	(24.3)
Total UGI Corporation stockholders' equity	2,497.9	2,233.1	2,258.0
Noncontrolling interests, principally in AmeriGas Partners	1,132.2	1,085.7	1,178.8
Total equity	3,630.1	3,318.8	3,436.8
Total liabilities and equity	$ 9,828.8	$ 9,709.7	$ 9,652.2

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Fair Value Measurement (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Commodity contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 9.6	$ 13.1	$ 17.4
Derivative financial instruments, liabilities	(32.1)	(61.0)	(120.0)
Foreign currency contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	1.0	1.8	7.1
Derivative financial instruments, liabilities	(1.7)
Interest rate contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	8.1
Derivative financial instruments, liabilities	(46.9)	(71.9)	(67.0)
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member] | Commodity contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	2.2	8.6	5.1
Derivative financial instruments, liabilities	(8.0)	(7.8)	(18.0)
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member] | Foreign currency contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets
Derivative financial instruments, liabilities
Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) [Member] | Interest rate contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets
Derivative financial instruments, liabilities
Significant Other Observable Inputs (Level 2) [Member] | Commodity contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	7.4	4.5	12.3
Derivative financial instruments, liabilities	(24.1)	(53.2)	(102.0)
Significant Other Observable Inputs (Level 2) [Member] | Foreign currency contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	1.0	1.8	7.1
Derivative financial instruments, liabilities	(1.7)
Significant Other Observable Inputs (Level 2) [Member] | Interest rate contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	8.1
Derivative financial instruments, liabilities	(46.9)	(71.9)	(67.0)
Unobservable Inputs (Level 3) [Member] | Commodity contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets
Derivative financial instruments, liabilities
Unobservable Inputs (Level 3) [Member] | Foreign currency contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets
Derivative financial instruments, liabilities
Unobservable Inputs (Level 3) [Member] | Interest rate contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets
Derivative financial instruments, liabilities

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Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)

9 Months Ended

Jun. 30, 2013

Regulated Operations [Abstract]

Regulatory assets and liabilities associated with Gas Utility and Electric Utility

The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:

	June 30, 2013		September 30, 2012		June 30, 2012
Regulatory assets:
Income taxes recoverable	$	104.7	$	103.2	$	99.9
Underfunded pension and postretirement plans	177.8		188.2		144.6
Environmental costs	16.6		16.8		16.6
Deferred fuel and power costs	4.1		11.6		9.8
Removal costs, net	12.1		12.7		11.8
Other	5.6		5.9		8.3
Total regulatory assets	$	320.9	$	338.4	$	291.0
Regulatory liabilities:
Postretirement benefits	$	14.2	$	13.1	$	12.3
Environmental overcollections	2.9		2.9		3.7
Deferred fuel and power refunds	14.2		4.4		10.3
State tax benefits—distribution system repairs	8.0		7.4		7.0
Other	0.7		0.5		0.7
Total regulatory liabilities	$	40.0	$	28.3	$	34.0

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Error in Method of Accounting For Certain Customer Credits (Notes)

9 Months Ended

Jun. 30, 2013

Accounting Changes and Error Corrections [Text Block]

Error in Accounting For Certain Customer Credits

During the three months ended March 31, 2013, the Partnership identified an error in accounting for certain customer credits. The Partnership determined that the recording of propane revenues did not appropriately consider the effects of certain customer credits which were recorded when issued in a subsequent period. As a result, beginning January 1, 2013, the Partnership changed its accounting for customer credits to record an estimate of such credits at the time propane revenues are recorded. Such estimate considers the Partnership’s history of providing credits, propane revenue activity and other factors. The Company has evaluated the impact of the error on prior periods and has determined that the effect is not material to any prior period financial statements. The Company has also evaluated and concluded that the impact of recording the cumulative effect of the correction of the error as of January 1, 2013, is not material to the financial statements for the three and six months ended March 31, 2013, nor is it expected to be material to the financial statements for Fiscal 2013. The correction of the error in accounting for customer credits had the effect of increasing revenues and accounts receivable by $3.6, and increasing net income attributable to UGI Corporation by $0.6, for the three months ended June 30, 2013, and decreasing revenues and accounts receivable by $5.1, and decreasing net income attributable to UGI Corporation by $0.9, for the nine months ended June 30, 2013. If the Company had corrected the error in its method of accounting and recorded the estimate of credits as of September 30, 2012, the cumulative effect of the change as of that date would have decreased net income attributable to UGI Corporation by approximately $0.7.

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Energy Services Accounts Receivable Securitization Facility (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Energy services accounts receivable securitization facility (Textual) [Abstract]
Receivables facility	$ 100
Energy Services [Member]
Energy services accounts receivable securitization facility (Textual) [Abstract]
Sale of trade receivables	766.1	674.4
Energy Services Funding Corporation [Member]
Energy services accounts receivable securitization facility (Textual) [Abstract]
Sale of undivided interests in its trade receivables to the commercial paper conduit	224.0	266.5
Outstanding balance of trade receivables	58.2	41.0
Outstanding balance of trade receivables sold	$ 9.5	$ 10.0

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Disclosures About Derivative Instruments and Hedging Activities (Details 1) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Jun. 30, 2012
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	$ 18.7	$ 24.5
Total Derivatives Liability	(80.7)	(187.0)
Designated as Hedging Instrument [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	16.6	11.3
Total Derivatives Liability	(71.7)	(162.5)
Derivative Financial Instruments and Other Assets [Member] | Designated as Hedging Instrument [Member] | Commodity Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	7.5	4.2
Derivative Financial Instruments and Other Assets [Member] | Designated as Hedging Instrument [Member] | Foreign Currency Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	1.0	7.1
Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Foreign Currency Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(0.4)
Derivative Financial Instruments and Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Commodity Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(24.4)	(95.5)
Derivative Financial Instruments and Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Foreign Currency Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability
Derivative Financial Instruments and Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(46.9)	(67.0)
Derivative Financial Instruments and Other Noncurrent Liabilities [Member] | Derivatives Subject to Utility Rate Regulation [Member] | Commodity Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(7.6)	(13.4)
Derivative Financial Instruments [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	8.1
Derivative Financial Instruments [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Commodity Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	2.0	12.6
Derivative Financial Instruments [Member] | Derivatives Subject to Utility Rate Regulation [Member] | Commodity Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Assets	0.1	0.6
Derivative Financial Instruments, Liabilities [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Commodity Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	(0.1)	(11.1)
Derivative Financial Instruments, Liabilities [Member] | Derivatives Not Designated as Hedging Instruments [Member] | Foreign Currency Contracts [Member]
Balance sheet location and fair value of derivative assets and liabilities
Total Derivatives Liability	$ (1.3)

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Goodwill and Intangible Assets (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Component of Company's Intangible Assets [Abstract]
Goodwill (not subject to amortization)	$ 2,834.0	$ 2,818.3	$ 2,756.0
Intangible assets:
Customer relationships, noncompete agreements and other	692.6	691.9	689.3
Trademarks and tradenames (not subject to amortization)	128.4	137.2	189.6
Gross carrying amount	821.0	829.1	878.9
Accumulated amortization	(212.4)	(170.9)	(161.2)
Intangible assets, net	$ 608.6	$ 658.2	$ 717.7

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Significant Accounting Policies (Details) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Denominator (thousands of shares):
Average common shares outstanding for basic computation (in shares)	114,240	112,726	113,693	112,484
Incremental shares issuable for stock options and awards (in shares)	1,956	0	1,582	811
Average common shares outstanding for diluted computation (in shares)	116,196	112,726	115,275	113,295

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Significant Accounting Policies (Details Textual) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Significant Accounting Policies (Textual) [Abstract]
Decrease in income tax expense		$ 4.7
Ownership interests in certain subsidiaries under equity method investment, maximum	100.00%

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Goodwill and Intangible Assets

9 Months Ended

Jun. 30, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets

Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following:

	June 30, 2013			September 30, 2012			June 30, 2012
Goodwill (not subject to amortization)	$	2,834.0		$	2,818.3		$	2,756.0
Intangible assets:
Customer relationships, noncompete agreements and other	$	692.6		$	691.9		$	689.3
Trademarks and tradenames (not subject to amortization)	128.4			137.2			189.6
Gross carrying amount	821.0			829.1			878.9
Accumulated amortization	(212.4		)	(170.9		)	(161.2		)
Intangible assets, net	$	608.6		$	658.2		$	717.7

The decrease in trademarks and tradenames and the increase in goodwill during the nine months ended June 30, 2013, principally reflects a correcting adjustment associated with the Heritage Acquisition. Amortization expense of intangible assets was $13.3 and $40.2 for the three and nine months ended June 30, 2013, respectively, and $12.4 and $31.2 for the three and nine months ended June 30, 2012, respectively. No amortization is included in cost of sales in the Condensed Consolidated Statements of Income. As of June 30, 2013, our expected aggregate amortization expense of intangible assets for the remainder of Fiscal 2013 and for the next four fiscal years is as follows: remainder of Fiscal 2013 — $12.5; Fiscal 2014 — $50.5; Fiscal 2015 — $47.4; Fiscal 2016 — $41.3; Fiscal 2017 — $35.0.

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Defined Benefit Pension and Other Postretirement Plans (Tables)

9 Months Ended

Jun. 30, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Component of net periodic pension expense and other postretirement benefit costs

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

	Pension Benefits						Other Postretirement Benefits
	Three Months Ended June 30,						Three Months Ended June 30,
	2013			2012			2013			2012
Service cost	$	2.8		$	2.1		$	0.2		$	0.1
Interest cost	5.9			6.1			0.2			0.2
Expected return on assets	(6.9		)	(6.4		)	(0.1		)	(0.1		)
Amortization of:
Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.1		)
Actuarial loss	3.7			2.1			0.1			0.1
Net benefit cost	5.6			4.0			0.3			0.2
Change in associated regulatory liabilities	—			—			0.8			0.8
Net expense	$	5.6		$	4.0		$	1.1		$	1.0
	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended						Nine Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Service cost	$	8.5		$	6.4		$	0.5		$	0.3
Interest cost	17.6			18.3			0.7			0.8
Expected return on assets	(20.7		)	(19.2		)	(0.4		)	(0.4		)
Amortization of:
Prior service cost (benefit)	0.2			0.2			(0.2		)	(0.3		)
Actuarial loss	11.2			6.3			0.3			0.3
Net benefit cost	16.8			12.0			0.9			0.7
Change in associated regulatory liabilities	—			—			2.4			2.3
Net expense	$	16.8		$	12.0		$	3.3		$	3.0

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Segment Information (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Jun. 30, 2013		Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012
Reconciliation of partnership EBITDA
Depreciation and amortization	$ (91.9)		$ (84.6)		$ (266.3)		$ (227.7)
Loss on extinguishment of debt	0		(0.1)		0		13.3
Operating income	53.1		(19.2)		835.4		549.9
AmeriGas Propane [Member]
Reconciliation of partnership EBITDA
Partnership EBITDA	59.1	[1]	1.8	[1]	550.5	[2]	310.0	[2]
Depreciation and amortization	(52.5)		(49.5)		(150.5)		(118.5)
Loss on extinguishment of debt	0		(0.1)		0		13.3
Noncontrolling interests	0	[3]	(0.6)	[3]	3.9	[3]	1.9	[3]
Operating income	$ 6.6		$ (48.4)		$ 403.9		$ 206.7

[1] The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:Three Months Ended June 30, 2013 2012Partnership EBITDA $59.1 1.8Depreciation and amortization (52.5) (49.5)Gain on extinguishments of debt — (0.1)Noncontrolling interests (i) — (0.6)Operating income (loss) $6.6 $(48.4)(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

[2] The following table provides a reconciliation of Partnership EBITDA to AmeriGas Propane operating income:Nine Months Ended June 30, 2013 2012Partnership EBITDA $550.5 $310.0Depreciation and amortization (150.5) (118.5)Loss on extinguishments of debt — 13.3Noncontrolling interests (i) 3.9 1.9Operating income $403.9 $206.7(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

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

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Utility Regulatory Assets and Liabilities and Regulatory Matters

9 Months Ended

Jun. 30, 2013

Regulated Operations [Abstract]

Utility Regulatory Assets and Liabilities and Regulatory Matters

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 2012 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, 2013		September 30, 2012		June 30, 2012
Regulatory assets:
Income taxes recoverable	$	104.7	$	103.2	$	99.9
Underfunded pension and postretirement plans	177.8		188.2		144.6
Environmental costs	16.6		16.8		16.6
Deferred fuel and power costs	4.1		11.6		9.8
Removal costs, net	12.1		12.7		11.8
Other	5.6		5.9		8.3
Total regulatory assets	$	320.9	$	338.4	$	291.0
Regulatory liabilities:
Postretirement benefits	$	14.2	$	13.1	$	12.3
Environmental overcollections	2.9		2.9		3.7
Deferred fuel and power refunds	14.2		4.4		10.3
State tax benefits—distribution system repairs	8.0		7.4		7.0
Other	0.7		0.5		0.7
Total regulatory liabilities	$	40.0	$	28.3	$	34.0

Deferred fuel and power—costs and refunds. Gas Utility’s tariffs and Electric Utility’s 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 overcollected costs are classified as a regulatory liability.

Gas Utility uses derivative financial instruments to reduce volatility in the cost of natural gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at June 30, 2013, September 30, 2012 and June 30, 2012 were $(1.4), $5.3 and $0.3, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts do not currently qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the Condensed Consolidated Balance Sheets with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At June 30, 2013, September 30, 2012, and June 30, 2012, the fair values of Electric Utility’s electricity supply contracts were net losses of $6.1, $9.2 and $13.1, 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, realized and unrealized gains or losses on FTRs are included in deferred fuel and power—costs or refunds. Unrealized gains or losses on FTRs at June 30, 2013, September 30, 2012, and June 30, 2012, were not material.

Allentown, Pennsylvania Natural Gas Incident. On October 3, 2012, UGI Utilities and the PUC Bureau of Investigation and Enforcement (“PUC Staff”) submitted a Joint Settlement Petition (“Joint Settlement”) to settle all regulatory compliance issues raised in the PUC Staff's formal complaint, issued on June 11, 2012, pertaining to a natural gas explosion which occurred on February 9, 2011, in Allentown, Pennsylvania and resulted in five deaths, several personal injuries and significant property damage. On February 19, 2013, the PUC entered a final order (the “Final Order”) in which PUC Commissioners adopted the Joint Settlement, with certain modifications. The Final Order requires UGI Utilities to (i) pay a civil penalty amount that increases the amount provided in the Joint Settlement from $0.4 to $0.5; (ii) conduct a pilot new technology leak detection program in Allentown; and (iii) accept new reporting requirements governing its agreed upon 14-year cast iron and 30-year bare steel pipeline replacement program and distribution integrity management program. The Final Order makes no findings that UGI Utilities has violated any regulation or operating procedure. The Company does not believe that the cost of complying with the requirements of the Final Order will have a material impact on UGI Utilities' consolidated financial position, results of operations or cash flows.

Transfers of Assets. On February 1, 2012, CPG filed an application with the PUC for review and approval of the transfer of an 11-mile natural gas pipeline, related facilities and right of way located in Delmar Township, Pennsylvania (“TL-96 line”) to Energy Services.   The PUC approved the transfer and, in April 2013, the TL-96 line was dividended to UGI and subsequently contributed to Energy Services.  The net book value of the TL-96 line is approximately $2.6.

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Partnership Acquisition of Heritage Propane

9 Months Ended

Jun. 30, 2013

Business Combinations [Abstract]

Partnership Acquisition of Heritage Propane

Partnership Acquisition of Heritage Propane

On January 12, 2012, AmeriGas Partners completed the acquisition of Heritage Propane from ETP for total consideration of $2,604.8 comprising $1,472.2 in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of approximately $1,132.6 (the “Heritage Acquisition”). The Heritage Acquisition was consummated pursuant to a Contribution and Redemption Agreement, dated October 15, 2011, as amended (the “Contribution Agreement”), by and among AmeriGas Partners, ETP, Energy Transfer Partners GP, L.P., the general partner of ETP, and Heritage ETC, L.P. For additional information on the Heritage Acquisition, see Note 4 to the Company’s 2012 Annual Financial Statements and Notes.

The following presents unaudited pro forma income statement and earnings per share data as if the Heritage Acquisition had occurred on October 1, 2011:

	Nine Months Ended June 30,
	2013 (As Reported)		2012 Pro Forma
Revenues	$	5,932.6	$	5,885.2
Net income attributable to UGI Corporation	$	289.2	$	211.4
Earnings per common share attributable to UGI Corporation stockholders:
Basic	$	2.54	$	1.88
Diluted	$	2.51	$	1.87

The unaudited pro forma results of operations reflect Heritage Propane’s historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The unaudited pro forma consolidated results of operations are not necessarily indicative of the results that would have occurred had the Heritage Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results.

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Condensed Consolidated Statements of Cash Flows (unaudited) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 481.8	$ 260.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	266.3	227.7
Deferred income taxes, net	35.5	9.9
Provision for uncollectible accounts	23.9	21.3
Net change in realized gains and losses deferred as cash flow hedges	5.0	(11.7)
Loss on extinguishments of debt, net	0	13.3
Other, net	(11.3)	2.6
Net change in:
Accounts receivable and accrued utility revenues	(141.1)	71.2
Inventories	54.1	128.1
Utility deferred fuel costs, net of changes in unsettled derivatives	20.5	8.1
Accounts payable	(26.9)	(132.2)
Other current assets	52.4	22.8
Other current liabilities	(73.8)	(55.5)
Net cash provided by operating activities	686.4	566.2
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(291.6)	(236.0)
Acquisitions of businesses, net of cash acquired	(24.3)	(1,573.7)
(Increase) decrease in restricted cash	(3.0)	9.6
Other, net	2.2	0.1
Net cash used by investing activities	(316.7)	(1,800.0)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(93.4)	(88.7)
Distributions on AmeriGas Partners Common Units	(168.5)	(126.5)
Issuances of debt	0	1,550.4
Repayments of debt	(28.5)	(240.1)
(Decrease) increase in bank loans	(39.0)	54.2
Receivables Facility net borrowings (repayments)	9.5	(4.3)
Issuances of UGI Common Stock	28.5	12.7
Issuance of AmeriGas Partners Common Units	0	276.6
Other	5.4	0.5
Net cash (used) provided by financing activities	(286.0)	1,434.8
EFFECT OF EXCHANGE RATE CHANGES ON CASH	(1.8)	(3.0)
Cash and cash equivalents increase	81.9	198.0
Cash and cash equivalents:
End of period	401.8	436.5
Beginning of period	319.9	238.5
Increase	$ 81.9	$ 198.0

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Fair Value Measurement (Details Textual) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Jun. 30, 2012
Fair Value Disclosures [Abstract]
Carrying value long-term debt	$ 3,493.8	$ 3,561.2
Estimated fair value long-term debt	$ 3,621.0	$ 3,730.7

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Defined Benefit Pension and Other Postretirement Plans (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Pension Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	$ 2.8	$ 2.1	$ 8.5	$ 6.4
Interest cost	5.9	6.1	17.6	18.3
Expected return on assets	(6.9)	(6.4)	(20.7)	(19.2)
Amortization of:
Prior service cost (benefit)	0.1	0.1	0.2	0.2
Actuarial loss	3.7	2.1	11.2	6.3
Net benefit cost	5.6	4.0	16.8	12.0
Change in associated regulatory liabilities	0	0	0	0
Net expense	5.6	4.0	16.8	12.0
Other Postretirement Benefits [Member]
Components of net periodic pension expense and other postretirement benefit costs [Abstract]
Service cost	0.2	0.1	0.5	0.3
Interest cost	0.2	0.2	0.7	0.8
Expected return on assets	(0.1)	(0.1)	(0.4)	(0.4)
Amortization of:
Prior service cost (benefit)	(0.1)	(0.1)	(0.2)	(0.3)
Actuarial loss	0.1	0.1	0.3	0.3
Net benefit cost	0.3	0.2	0.9	0.7
Change in associated regulatory liabilities	0.8	0.8	2.4	2.3
Net expense	$ 1.1	$ 1.0	$ 3.3	$ 3.0

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Inventories (Tables)

9 Months Ended

Jun. 30, 2013

Inventory Disclosure [Abstract]

Inventories

Inventories comprise the following:

	June 30, 2013		September 30, 2012		June 30, 2012
Non-utility LPG and natural gas	$	194.6	$	240.7	$	220.1
Gas Utility natural gas	43.1		57.7		27.8
Materials, supplies and other	66.3		58.5		69.4
Total inventories	$	304.0	$	356.9	$	317.3

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Error in Method of Accounting For Certain Customer Credits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended		3 Months Ended	9 Months Ended
	Jun. 30, 2013 Impact on net income attributable to UGI Corporation [Member]	Jun. 30, 2013 Impact on net income attributable to UGI Corporation [Member]	Sep. 30, 2012 Impact on net income attributable to UGI Corporation [Member] Prior fiscal year impact [Member]	Jun. 30, 2013 Revenues and accounts receivable [Member]	Jun. 30, 2013 Revenues and accounts receivable [Member]
Correction of Error [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Amount	$ 0.6	$ 0.9		$ 3.6	$ 5.1
Impact of Customer Credit Adjustment			$ 0.7

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Commitments and Contingencies

9 Months Ended

Jun. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Environmental Matters

UGI Utilities

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At June 30, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $14.4 and $15.8, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of 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 (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At June 30, 2013, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

From time to time, UGI Utilities is notified of 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 generally investigate the extent of environmental contamination or perform environmental remediation. 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.

Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities predecessor is identified as an owner and operator of the site. The City of Omaha and MUD have requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska, and issued an information request to UGI Utilities. UGI Utilities responded to the EPA’s information request on January 17, 2012. There have been no recent developments in this matter.

AmeriGas Propane

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 communicated the results of its research to DEC in January 2009. There have been no recent developments in this matter. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

Claremont, New Hampshire and Chestertown, Maryland. In connection with the Heritage Acquisition on January 12, 2012, a predecessor of Titan Propane LLC (“Titan LLC”), a former subsidiary acquired in the Heritage Acquisition, is purportedly the beneficial holder of title with respect to two former MGPs discussed below. The Contribution Agreement provides for indemnification from ETP for certain expenses associated with remediation of these sites. By letter dated September 30, 2010, the EPA notified Titan LLC that it may be a potentially responsible party (“PRP”) for cleanup costs associated with contamination at a former MGP in Claremont, New Hampshire. In June 2010, the Maryland Attorney General (“MAG”) identified Titan LLC as a PRP in connection with contamination at a former MGP in Chestertown, Maryland and requested that Titan LLC participate in characterization and remediation activities. Titan LLC has supplied the EPA and MAG with corporate and bankruptcy information for its predecessors to support its claim that it is not liable for any remediation costs at the sites. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

Other Matters

AmeriGas Cylinder Investigation. 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 as a result of the Partnership's decision in 2008 to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds. At that time, the District Attorneys issued an administrative subpoena seeking documents and information relating to those 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 sought additional information and documents regarding AmeriGas OLP's cylinder exchange program and we responded to that subpoena. In connection with this matter, the District Attorneys have alleged potential violations of California's antitrust laws, California's slack-fill law, and California’s principal false advertising statute. We believe we have strong defenses to these allegations.

Federal Trade Commission Investigation of Propane Grill Cylinder Filling Practices. On or about November 4, 2011, the General Partner received notice that the Federal Trade Commission (“FTC”) is conducting an antitrust and consumer protection investigation into certain practices of the Partnership that relate to the filling of portable propane cylinders. On February 2, 2012, the Partnership received a Civil Investigative Demand from the FTC that requests documents and information concerning, among other things, (i) the Partnership’s decision, in 2008, to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds and (ii) cross-filling, related service arrangements and communications regarding the foregoing with competitors. The Partnership believes that it will have good defenses to any claims that may result from this investigation. We are not able to assess the financial impact this investigation or any related claims may have on the Partnership.

Purported Class Action Lawsuit. In 2005, Samuel and Brenda Swiger (the “Swigers”) filed what purports to be a class action lawsuit 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 this 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 Court has not certified the class. 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 OLP 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. Effective June 20, 2013, we entered into a settlement agreement with BP and the lawsuit has been dismissed. The effect of the settlement agreement will not have a material impact on our results of operations or financial condition.

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.

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Energy Services Accounts Receivable Securitization Facility

9 Months Ended

Jun. 30, 2013

Transfers and Servicing of Financial Assets [Abstract]

Energy Services Accounts Receivable Securitization Facility

Energy Services Accounts Receivable Securitization Facility

Energy Services currently has a $100 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper that expires in November 2013. 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. 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.

During the nine months ended June 30, 2013 and 2012, Energy Services transferred trade receivables to ESFC totaling $766.1 and $674.4, respectively. During the nine months ended June 30, 2013 and 2012, ESFC sold an aggregate $224.0 and $266.5, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At June 30, 2013, the outstanding balance of ESFC receivables was $58.2 and there was $9.5 sold to the commercial paper conduit. At June 30, 2012, the outstanding balance of ESFC receivables was $41.0 and there was $10.0 sold to the commercial paper conduit.

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Inventories

9 Months Ended

Jun. 30, 2013

Inventory Disclosure [Abstract]

Inventories

Inventories

Inventories comprise the following:

	June 30, 2013		September 30, 2012		June 30, 2012
Non-utility LPG and natural gas	$	194.6	$	240.7	$	220.1
Gas Utility natural gas	43.1		57.7		27.8
Materials, supplies and other	66.3		58.5		69.4
Total inventories	$	304.0	$	356.9	$	317.3

At June 30, 2013, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”), one of which expires in October 2013 and two of which expire in October 2015. Pursuant to 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.

As of June 30, 2013, UGI Utilities’ principal SCAAs are with Energy Services. The carrying values of natural gas storage inventories released under SCAAs with non-affiliates at September 30, 2012 and June 30, 2012, comprising 3.8 billion cubic feet (“bcf”) and 1.9 bcf of natural gas, were $11.4 and $5.3, respectively.

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Fair Value Measurements

9 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of June 30, 2013, September 30, 2012 and June 30, 2012:

	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
June 30, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	2.2		$	7.4		$	—	$	9.6
Foreign currency contracts	$	—		$	1.0		$	—	$	1.0
Interest rate contracts	$	—		$	8.1		$	—	$	8.1
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(8.0	)	$	(24.1	)	$	—	$	(32.1	)
Foreign currency contracts	$	—		$	(1.7	)	$	—	$	(1.7	)
Interest rate contracts	$	—		$	(46.9	)	$	—	$	(46.9	)
September 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	8.6		$	4.5		$	—	$	13.1
Foreign currency contracts	$	—		$	1.8		$	—	$	1.8
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(7.8	)	$	(53.2	)	$	—	$	(61.0	)
Interest rate contracts	$	—		$	(71.9	)	$	—	$	(71.9	)
June 30, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	5.1		$	12.3		$	—	$	17.4
Foreign currency contracts	$	—		$	7.1		$	—	$	7.1
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(18.0	)	$	(102.0	)	$	—	$	(120.0	)
Interest rate contracts	$	—		$	(67.0	)	$	—	$	(67.0	)

The fair values of our Level 1 exchange-traded commodity futures and option contracts and non exchange-traded commodity futures and forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The remainder of our derivative financial instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 which are 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 our Level 2 interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. There were no transfers between Level 1 and Level 2 during the periods presented.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. At June 30, 2013, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,493.8 and $3,621.0, respectively. At June 30, 2012, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,561.2 and $3,730.7, 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 (Level 2).

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 that extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative financial instruments, see Note 13.

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Document and Entity Information	9 Months Ended
	Jun. 30, 2013	Jul. 31, 2013
Entity Information [Line Items]
Entity Registrant Name	UGI CORP /PA/
Entity Central Index Key	0000884614
Document Type	10-Q
Document Period End Date	Jun. 30, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--09-30
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		114,098,006

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Disclosures About Derivative Instruments and Hedging Activities

9 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Disclosures About Derivative Instruments and Hedging Activities

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 reduce short-term commodity price volatility and to provide market price risk support to some of its wholesale customers which are generally not designated as hedges for accounting purposes.

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, including the cost of financial instruments used to hedge purchased gas costs. 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, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.7 million dekatherms and 13.2 million dekatherms, respectively. At June 30, 2013, 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 GAAP related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 8).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At June 30, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $6.1 and $13.1, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At June 30, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts was 327.4 million kilowatt hours and 654.7 million kilowatt hours, respectively. At June 30, 2013, the maximum period over which these contracts extend is 11 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly 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. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 8). At June 30, 2013 and 2012, the volumes associated with Electric Utility FTRs totaled 260.6 million kilowatt hours and 261.0 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At June 30, 2013 and 2012, the volumes associated with Midstream & Marketing’s FTRs totaled 1,609.2 million kilowatt hours and 1,285.5 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 futures contracts, IntercontinentalExchange (“ICE”) natural gas basis swap contracts, and electricity futures contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. In addition, 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. At June 30, 2013, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 2.7 million dekatherms and 1.8 million gallons, respectively. At June 30, 2012, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 4.1 million dekatherms and 2.2 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, 2013 and 2012, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:

	Volumes
	June 30,
Commodity	2013	2012
LPG (millions of gallons)	236.7	231.9
Natural gas (millions of dekatherms)	19.4	21.2
Electricity forward purchase contracts (millions of kilowatt-hours)	927.2	1688.4
Electricity forward sales contracts (millions of kilowatt-hours)	451.0	131.8

At June 30, 2013, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 19 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 41 months with a weighted average of 10 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 27 months for electricity forward purchase contracts, with a weighted average of 9 months, and 14 months for electricity forward sales contracts, with a weighted average of 3 months. At June 30, 2013, 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 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, 2013, 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 $15.6.

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 its term loans, in each case through the respective scheduled maturity dates. As of June 30, 2013 and 2012, the total notional amount of existing variable-rate debt subject to interest rate swap agreements was €440.5 and €441.9, 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, 2013 and 2012, the total notional amount of unsettled IRPAs was $173. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt forecasted to occur in September 2013.

UGI Utilities reclassified pre-tax losses of $0.7 from AOCI into income during the nine months ended June 30, 2012, as a result of the discontinuance of cash flow hedge accounting for a portion of expected interest payments associated with the issuance of long-term debt originally anticipated to occur in September 2012. Such losses are included in other income, net, on the Condensed Consolidated Statements of Income.

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, 2013, 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 $2.2.

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 forecasted to occur during the heating-season months of October through March. At June 30, 2013 and 2012, we were hedging a total of $170.3 and $75.0 of U.S. dollar-denominated LPG purchases, respectively. At June 30, 2013, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 33 months with a weighted average of 14 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At June 30, 2013, we had no euro-denominated net investment hedges. At June 30, 2012, we were hedging a total of €14.5 of our euro-denominated net investments. From time to time, the Company may enter into foreign currency exchange transactions to economically hedge the local-currency purchase price of anticipated foreign business acquisitions. These transactions do not qualify for hedge accounting treatment and any changes in fair value are recorded in other income, net. At June 30, 2013, the fair values of these foreign currency contracts were not material.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At June 30, 2013, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $1.0. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise 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 contracts generally require cash deposits in margin accounts. At June 30, 2013 and 2012, restricted cash in brokerage accounts totaled $6.0 and $7.6, 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, 2013. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At June 30, 2013, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of June 30, 2013 and 2012:

	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value June 30,				Balance Sheet	Fair Value June 30,
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	7.5	$	4.2	Derivative financial instruments and Other noncurrent liabilities	$	(24.4	)	$	(95.5	)
Foreign currency contracts	Derivative financial instruments and Other assets	1.0		7.1		Other noncurrent liabilities	(0.4		)	—
Interest rate contracts	Derivative financial instruments	8.1		—		Derivative financial instruments and Other noncurrent liabilities	(46.9		)	(67.0		)
Total Derivatives Designated as Hedging Instruments		$	16.6	$	11.3		$	(71.7	)	$	(162.5	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	$	0.1	$	0.6	Derivative financial instruments and Other noncurrent liabilities	$	(7.6	)	$	(13.4	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	$	2.0	$	12.6	Derivative financial instruments	$	(0.1	)	$	(11.1	)
Foreign currency contracts	Derivative financial instruments	—		—		Derivative financial instruments	(1.3		)	—
Total Derivatives		$	18.7	$	24.5		$	(80.7	)	$	(187.0	)

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 months ended June 30, 2013 and 2012:

Three Months Ended June 30,	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2013			2012			2013			2012			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(22.8	)	$	(59.3	)	$	(6.9	)	$	(31.0	)	Cost of sales
Foreign currency contracts	(0.3		)	3.1			—			—			Cost of sales
Interest rate contracts	14.0			(16.6		)	(3.6		)	(3.3		)	Interest expense / other income, net
Total	$	(9.1	)	$	(72.8	)	$	(10.5	)	$	(34.3	)
Net Investment Hedges:
Foreign currency contracts	$	—		$	0.9
	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2013			2012
Commodity contracts	$	2.0		$	(15.9	)							Cost of sales
Commodity contracts	(0.1		)	(0.1		)							Operating expenses / other income, net
Foreign currency contracts	(0.9		)	—									Other income, net
Total	$	1.0		$	(16.0	)

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 nine months ended June 30, 2013 and 2012:

Nine Months Ended June 30,	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2013			2012			2013			2012			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	(28.1	)	$	(166.2	)	$	(64.1	)	$	(94.4	)	Cost of sales
Foreign currency contracts	(1.4		)	2.8			(0.1		)	2.0			Cost of sales
Interest rate contracts	23.0			(29.0		)	(10.6		)	(8.4		)	Interest expense / other income, net
Total	$	(6.5	)	$	(192.4	)	$	(74.8	)	$	(100.8	)
Net Investment Hedges:
Foreign currency contracts	$	—		$	0.9
	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2013			2012
Commodity contracts	$	2.4		$	(12.6	)							Cost of sales
Commodity contracts	—			0.1									Operating expenses / other income, net
Foreign currency contracts	(1.1		)	0.5									Other income, net
Total	$	1.3		$	(12.0	)

The amounts of derivative gains or losses representing ineffectiveness were not material for the three and nine month periods ended June 30, 2013 and 2012.

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 and contracts that 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.