UGI 10-Q Quarterly Report March 31, 2011

UGI CORP /PA/

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10-Q 1 c15609e10vq.htm FORM 10-Q Form 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended March 31, 2011


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

For the transition period from to

Commission file number 1-11071

UGI CORPORATION

(Exact name of registrant as specified in its charter)


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

UGI CORPORATION
460 North Gulph Road, King of Prussia, PA
(Address of principal executive offices)
19406
(Zip Code)
(610) 337-1000
(Registrant’s telephone number, including area code)

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

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

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


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

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

At April 30, 2011, there were 111,653,607 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 March 31, 2011, September 30, 2010 and March 31, 2010		1

Condensed Consolidated Statements of Income for the three and six months ended March 31, 2011 and 2010		2

Condensed Consolidated Statements of Cash Flows for the six months ended March 31, 2011 and 2010		3

Notes to Condensed Consolidated Financial Statements		4 - 32

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		33 - 53

Item 3. Quantitative and Qualitative Disclosures About Market Risk		53 - 56

Item 4. Controls and Procedures		57

Part II Other Information

Item 1. Legal Proceedings		58

Item 1A. Risk Factors		58

Item 6. Exhibits		58 - 60

Signatures		61

Exhibit 10.1
Exhibit 10.2
Exhibit 10.3
Exhibit 10.4
Exhibit 10.5
Exhibit 10.6
Exhibit 31.1
Exhibit 31.2
Exhibit 32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

-i-

UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(Millions of dollars)


	March 31,			September 30,			March 31,
	2011			2010			2010
ASSETS
Current assets:
Cash and cash equivalents	$	298.1		$	260.7		$	270.7
Restricted cash		9.6			34.8			38.9
Accounts receivable (less allowances for doubtful accounts of $46.1, $34.6 and $47.5, respectively)		908.7			467.8			855.9
Accrued utility revenues		43.2			14.0			33.3
Inventories		222.1			314.0			223.9
Deferred income taxes		27.2			32.6			30.9
Derivative financial instruments		15.8			11.3			13.8
Prepaid expenses and other current assets		54.4			84.9			49.5

Total current assets		1,579.1			1,220.1			1,516.9

Property, plant and equipment (less accumulated depreciation and amortization of $2,014.9, $1,916.5 and $1,852.8, respectively)		3,187.2			3,053.2			2,902.9

Goodwill		1,588.4			1,562.7			1,529.7
Intangible assets, net		160.2			150.1			149.3
Other assets		379.5			388.2			220.0

Total assets	$	6,894.4		$	6,374.3		$	6,318.8


LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	38.0		$	573.6		$	607.1
Bank loans		222.1			200.4			147.4
Accounts payable		458.1			372.6			432.6
Derivative financial instruments		15.6			58.0			68.1
Other current liabilities		494.1			470.1			437.3

Total current liabilities		1,227.9			1,674.7			1,692.5

Long-term debt		2,028.0			1,432.2			1,475.2
Deferred income taxes		666.6			601.4			511.9
Deferred investment tax credits		5.1			5.3			5.5
Other noncurrent liabilities		523.7			599.1			542.4

Total liabilities		4,451.3			4,312.7			4,227.5

Commitments and contingencies (note 10)

Equity:
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized — 300,000,000 shares; issued — 115,501,094, 115,400,294 and 115,269,294 shares, respectively)		931.5			906.1			883.9
Retained earnings		1,173.5			966.7			1,016.2
Accumulated other comprehensive income (loss)		63.6			(10.1	)		(71.4	)
Treasury stock, at cost		(29.4	)		(38.2	)		(47.5	)

Total UGI Corporation stockholders’ equity		2,139.2			1,824.5			1,781.2
Noncontrolling interests		303.9			237.1			310.1

Total equity		2,443.1			2,061.6			2,091.3


Total liabilities and equity	$	6,894.4		$	6,374.3		$	6,318.8

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						Six Months Ended
	March 31,						March 31,
	2011			2010			2011			2010
Revenues	$	2,181.0		$	2,120.3		$	3,946.6		$	3,739.1

Costs and expenses:
Cost of sales (excluding depreciation shown below)		1,423.9			1,366.9			2,586.5			2,393.7
Operating and administrative expenses		350.0			328.4			662.1			625.1
Utility taxes other than income taxes		5.4			4.9			9.8			9.4
Depreciation		49.0			46.8			98.2			94.3
Amortization		6.5			5.8			12.6			11.3
Other (income) expense, net		(10.8	)		1.5			(31.9	)		(3.9	)

		1,824.0			1,754.3			3,337.3			3,129.9


Operating income		357.0			366.0			609.3			609.2
Loss from equity investees		(0.4	)		—			(0.6	)		—
Loss on extinguishment of debt		(18.8	)		—			(18.8	)		—
Interest expense		(34.3	)		(34.1	)		(67.6	)		(68.3	)

Income before income taxes		303.5			331.9			522.3			540.9
Income taxes		(87.9	)		(99.1	)		(151.7	)		(162.6	)

Net income		215.6			232.8			370.6			378.3
Less: net income attributable to noncontrolling interests, principally AmeriGas Partners		(66.2	)		(75.7	)		(108.1	)		(122.8	)

Net income attributable to UGI Corporation	$	149.4		$	157.1		$	262.5		$	255.5


Earnings per common share attributable to UGI stockholders:
Basic	$	1.34		$	1.44		$	2.36		$	2.34


Diluted	$	1.32		$	1.43		$	2.33		$	2.32


Average common shares outstanding (thousands):
Basic		111,637			109,232			111,267			109,158


Diluted		113,160			110,086			112,782			110,026


Dividends declared per common share	$	0.25		$	0.20		$	0.50		$	0.40

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)


	Six Months Ended
	March 31,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	370.6		$	378.3
Reconcile to net cash from operating activities:
Depreciation and amortization		110.8			105.6
Deferred income taxes, net		17.9			25.7
Loss on interest rate hedges		—			12.2
Provision for uncollectible accounts		16.4			22.3
Net change in realized gains and losses deferred as cash flow hedges		12.0			30.7
Loss on extinguishment of debt		18.8			—
Other, net		14.1			9.9
Net change in:
Accounts receivable and accrued utility revenues		(449.3	)		(504.7	)
Inventories		104.4			136.1
Utility deferred fuel costs		43.3			(1.1	)
Accounts payable		63.1			118.5
Other current assets		(13.8	)		(8.7	)
Other current liabilities		(16.2	)		(20.5	)

Net cash provided by operating activities		292.1			304.3


CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(167.4	)		(145.8	)
Acquisitions of businesses, net of cash acquired		(44.6	)		(9.7	)
Decrease (increase) in restricted cash		25.2			(31.9	)
Other, net		1.5			(11.5	)

Net cash used by investing activities		(185.3	)		(198.9	)


CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock		(55.7	)		(43.6	)
Distributions on AmeriGas Partners publicly held Common Units		(45.7	)		(43.4	)
Issuances of debt		981.2			—
Repayments of debt		(984.0	)		(7.2	)
Increase (decrease) in bank loans		22.0			(14.4	)
Receivables Facility net repayments		(12.1	)		—
Issuances of UGI Common Stock		21.9			2.1
Other		3.3			—

Net cash used by financing activities		(69.1	)		(106.5	)

EFFECT OF EXCHANGE RATE CHANGES ON CASH		(0.3	)		(8.3	)


Cash and cash equivalents increase (decrease)	$	37.4		$	(9.4	)


Cash and cash equivalents:
End of period	$	298.1		$	270.7
Beginning of period		260.7			280.1

Increase (decrease)	$	37.4		$	(9.4	)

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

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

Nature of Operations

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

We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”), a publicly traded limited partnership, and its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”) and, prior to its October 1, 2010 merger with AmeriGas OLP, AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (together with AmeriGas OLP, the “Operating Partnership”). AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary AmeriGas Propane, Inc. (the “General Partner”) serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At March 31, 2011, the General Partner held a 1% general partner interest and 42.8% limited partner interest in AmeriGas Partners and an effective 44.4% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners Common Units (“Common Units”). The remaining 56.2% interest in AmeriGas Partners comprises 32,433,087 Common Units held by the general public as limited partner interests.

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

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UGI CORPORATION AND SUBSIDIARIES

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

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

Significant Accounting Policies

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

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

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

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

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UGI CORPORATION AND SUBSIDIARIES

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

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


	Three Months Ended				Six Months Ended
	March 31,				March 31,
	2011		2010		2011		2010
Denominator (thousands of shares):
Average common shares outstanding for basic computation		111,637		109,232		111,267		109,158
Incremental shares issuable for stock options and awards		1,523		854		1,515		868

Average common shares outstanding for diluted computation		113,160		110,086		112,782		110,026

Comprehensive Income. The following table presents the components of comprehensive income for the three and six months ended March 31, 2011 and 2010:


	Three Months Ended						Six Months Ended
	March 31,						March 31,
	2011			2010			2011			2010
Net income	$	215.6		$	232.8		$	370.6		$	378.3
Other comprehensive income (loss)		47.3			(57.5	)		77.0			(26.3	)

Comprehensive income (including noncontrolling interests)		262.9			175.3			447.6			352.0
Less: comprehensive income attributable to noncontrolling interests		(64.7	)		(61.8	)		(111.4	)		(129.0	)

Comprehensive income attributable to UGI Corporation	$	198.2		$	113.5		$	336.2		$	223.0

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

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

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

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

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UGI CORPORATION AND SUBSIDIARIES

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

Accounting Changes

Adoption of New Accounting Standard

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

Intangible Assets

The Company’s intangible assets comprise the following:


	March 31,			September 30,			March 31,
	2011			2010			2010
Goodwill (not subject to amortization)	$	1,588.4		$	1,562.7		$	1,529.7


Other intangible assets:
Customer relationships, noncompete agreements and other	$	234.6		$	215.4		$	212.1
Trademarks (not subject to amortization)		50.8			46.3			45.9

Gross carrying amount		285.4			261.7			258.0
Accumulated amortization		(125.2	)		(111.6	)		(108.7	)

Net carrying amount	$	160.2		$	150.1		$	149.3

The increases in goodwill and other intangible assets during the six months ended March 31, 2011 principally reflects the effects of acquisitions and currency translation. Amortization expense of intangible assets was $4.9 and $9.6 for the three and six months ended March 31, 2011, respectively, and $5.0 and $9.9 for the three and six months ended March 31, 2010, respectively. No amortization is included in cost of sales in the Condensed Consolidated Statements of Income. Our expected aggregate amortization expense of intangible assets for the next five fiscal years is as follows: Fiscal 2011 — $19.5; Fiscal 2012 — $20.1; Fiscal 2013 — $19.5; Fiscal 2014 — $18.5; Fiscal 2015 — $15.7.

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UGI CORPORATION AND SUBSIDIARIES

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

Segment Information

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

The accounting policies of our reportable segments are the same as those described in Note 2, “Significant Accounting Policies” in the Company’s 2010 Annual Financial Statements and Notes. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership EBITDA may be different from that used by other companies. We evaluate the performance of our International Propane, Gas Utility, Electric Utility and Midstream & Marketing segments principally based upon their income before income taxes.

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UGI CORPORATION AND SUBSIDIARIES

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

Segment Information (continued)

Three Months Ended March 31, 2011:


							Reportable Segments
																			International Propane
							AmeriGas			Gas			Electric			Energy						Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services			Antargaz			Other			& Other (b)
Revenues	$	2,181.0		$	(92.8)	(c)	$	906.8		$	452.5		$	31.7		$	360.3		$	392.7		$	111.2		$	18.6

Cost of sales	$	1,423.9		$	(91.9)	(c)	$	564.8		$	288.6		$	20.2		$	305.4		$	244.1		$	82.1		$	10.6

Segment profit:
Operating income (loss)	$	357.0		$	0.1		$	154.6		$	100.9		$	3.0		$	40.8		$	60.5		$	1.3		$	(4.2	)
Loss from equity investees		(0.4	)		—			—			—			—			—			(0.4	)		—			—
Loss on extinguishment of debt		(18.8	)		—			(18.8	)		—			—			—			—			—			—
Interest expense		(34.3	)		—			(16.3	)		(10.2	)		(0.6	)		(0.7	)		(5.9	)		(0.4	)		(0.2	)

Income (loss) before income taxes	$	303.5		$	0.1		$	119.5		$	90.7		$	2.4		$	40.1		$	54.2		$	0.9		$	(4.4	)


Partnership EBITDA (a)							$	157.5
Noncontrolling interests’ net income	$	66.2		$	—		$	65.8		$	—		$	—		$	—		$	0.4		$	—		$	—
Depreciation and amortization	$	55.5		$	—		$	23.2		$	12.3		$	1.0		$	1.9		$	12.6		$	4.1		$	0.4
Capital expenditures	$	82.0		$	—		$	19.3		$	17.5		$	2.6		$	28.2		$	10.4		$	3.5		$	0.5
Total assets (at period end)	$	6,894.4		$	(89.3	)	$	1,908.7		$	2,045.2		$	158.3		$	574.5		$	1,757.7		$	380.8		$	158.5
Bank loans (at period end)	$	222.1		$	—		$	194.0		$	—		$	—		$	—		$	—		$	28.1		$	—
Goodwill (at period end)	$	1,588.4		$	—		$	693.9		$	180.1		$	—		$	2.8		$	626.6		$	78.0		$	7.0

Three Months Ended March 31, 2010:


							Reportable Segments
																		International Propane
							AmeriGas			Gas			Electric			Energy					Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other			& Other (b)
Revenues	$	2,120.3		$	(84.8)	(c)	$	886.1		$	445.4		$	31.6		$	438.6	$	340.4		$	46.0		$	17.0

Cost of sales	$	1,366.9		$	(83.1)	(c)	$	539.7		$	291.4		$	20.7		$	382.3	$	177.3		$	30.0		$	8.6

Segment profit:
Operating income (loss)	$	366.0		$	(0.1	)	$	153.3		$	91.1		$	3.1		$	40.8	$	77.8		$	3.0		$	(3.0	)
Income (loss) from equity investees		—			—			—			—			—			—		0.1			(0.1	)		—
Interest expense		(34.1	)		—			(16.7	)		(10.3	)		(0.5	)		—		(5.7	)		(0.7	)		(0.2	)

Income (loss) before income taxes	$	331.9		$	(0.1	)	$	136.6		$	80.8		$	2.6		$	40.8	$	72.2		$	2.2		$	(3.2	)


Partnership EBITDA (a)							$	173.6
Noncontrolling interests’ net income	$	75.7		$	—		$	75.2		$	—		$	—		$	—	$	0.5		$	—		$	—
Depreciation and amortization	$	52.6		$	—		$	21.8		$	12.2		$	1.0		$	1.9	$	12.5		$	2.8		$	0.4
Capital expenditures	$	71.3		$	—		$	18.7		$	11.5		$	0.8		$	27.9	$	9.9		$	1.5		$	1.0
Total assets (at period end)	$	6,318.8		$	(85.1	)	$	1,793.0		$	1,862.6		$	125.6		$	465.8	$	1,748.6		$	253.7		$	154.6
Bank loans (at period end)	$	147.4		$	—		$	23.0		$	33.4		$	3.6		$	—	$	67.6		$	19.8		$	—
Goodwill (at period end)	$	1,529.7		$	(4.0	)	$	670.9		$	180.1		$	—		$	11.8	$	597.2		$	66.6		$	7.1


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


Three months ended March 31,	2011			2010

Partnership EBITDA	$	157.5	(ii)	$	173.6	(iii)
Depreciation and amortization		(23.2	)		(21.8	)
Loss on extinguishment of debt		18.8			—
Noncontrolling interest (i)		1.5			1.5

Operating income	$	154.6		$	153.3

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

(ii)		Includes $18.8 loss associated with the extinguishment of Partnership debt.

(iii)		Includes $12.2 loss associated with the discontinuance of Partnership interest rate protection agreements.


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

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

- 9 -

UGI CORPORATION AND SUBSIDIARIES

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

5. Segment Information (continued)

Six Months Ended March 31, 2011:


							Reportable Segments
																			International Propane
							AmeriGas			Gas			Electric			Energy						Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services			Antargaz			Other			& Other (b)
Revenues	$	3,946.6		$	(132.9)	(c)	$	1,607.0		$	773.6		$	60.6		$	639.9		$	728.7		$	230.1		$	39.6

Cost of sales	$	2,586.5		$	(131.2)	(c)	$	1,000.1		$	483.5		$	38.8		$	545.5		$	458.7		$	169.2		$	21.9

Segment profit:
Operating income (loss)	$	609.3		$	0.2		$	246.2		$	176.0		$	6.6		$	68.3		$	112.4		$	3.4		$	(3.8	)
Loss from equity investees		(0.6	)		—			—			—			—			—			(0.6	)		—			—
Loss on extinguishment of debt		(18.8	)		—			(18.8	)		—			—			—			—			—			—
Interest expense		(67.6	)		—			(31.7	)		(20.3	)		(1.1	)		(1.4	)		(11.4	)		(1.3	)		(0.4	)

Income (loss) before income taxes	$	522.3		$	0.2		$	195.7		$	155.7		$	5.5		$	66.9		$	100.4		$	2.1		$	(4.2	)


Partnership EBITDA (a)							$	270.8
Noncontrolling interests’ net income	$	108.1		$	—		$	107.3		$	—		$	—		$	—		$	0.8		$	—		$	—
Depreciation and amortization	$	110.8		$	—		$	45.9		$	24.5		$	2.0		$	3.6		$	24.9		$	9.0		$	0.9
Capital expenditures	$	167.6		$	—		$	40.6		$	33.6		$	4.1		$	62.8		$	19.8		$	6.0		$	0.7
Total assets (at period end)	$	6,894.4		$	(89.3	)	$	1,908.7		$	2,045.2		$	158.3		$	574.5		$	1,757.7		$	380.8		$	158.5
Bank loans (at period end)	$	222.1		$	—		$	194.0		$	—		$	—		$	—		$	—		$	28.1		$	—
Goodwill (at period end)	$	1,588.4		$	—		$	693.9		$	180.1		$	—		$	2.8		$	626.6		$	78.0		$	7.0

Six Months Ended March 31, 2010:


							Reportable Segments
																		International Propane
							AmeriGas			Gas			Electric			Energy					Flaga &			Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other			& Other (b)
Revenues	$	3,739.1		$	(124.7)	(c)	$	1,542.7		$	773.2		$	65.6		$	750.9	$	604.5		$	88.8		$	38.1

Cost of sales	$	2,393.7		$	(121.6)	(c)	$	929.3		$	501.2		$	42.2		$	653.6	$	312.5		$	56.8		$	19.7

Segment profit:
Operating income (loss)	$	609.2		$	(0.3	)	$	255.9		$	154.8		$	8.5		$	68.5	$	119.1		$	5.6		$	(2.9	)
Income (loss) from equity investees		—			—			—			—			—			—		0.1			(0.1	)		—
Interest expense		(68.3	)		—			(33.2	)		(20.5	)		(0.9	)		—		(11.8	)		(1.6	)		(0.3	)

Income (loss) before income taxes	$	540.9		$	(0.3	)	$	222.7		$	134.3		$	7.6		$	68.5	$	107.4		$	3.9		$	(3.2	)


Partnership EBITDA (a)							$	296.6
Noncontrolling interests’ net income	$	122.8		$	—		$	122.0		$	—		$	—		$	—	$	0.8		$	—		$	—
Depreciation and amortization	$	105.6		$	(0.1	)	$	43.2		$	24.5		$	2.0		$	4.0	$	25.7		$	5.6		$	0.7
Capital expenditures	$	146.3		$	—		$	45.4		$	24.5		$	1.6		$	50.4	$	19.3		$	3.7		$	1.4
Total assets (at period end)	$	6,318.8		$	(85.1	)	$	1,793.0		$	1,862.6		$	125.6		$	465.8	$	1,748.6		$	253.7		$	154.6
Bank loans (at period end)	$	147.4		$	—		$	23.0		$	33.4		$	3.6		$	—	$	67.6		$	19.8		$	—
Goodwill (at period end)	$	1,529.7		$	(4.0	)	$	670.9		$	180.1		$	—		$	11.8	$	597.2		$	66.6		$	7.1


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


Six months ended March 31,	2011			2010

Partnership EBITDA	$	270.8	(ii)	$	296.6	(iii)
Depreciation and amortization		(45.9	)		(43.2	)
Loss on extinguishment of debt		18.8			—
Noncontrolling interest (i)		2.5			2.5

Operating income	$	246.2		$	255.9

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

(ii)		Includes $18.8 loss associated with the extinguishment of Partnership debt.

(iii)		Includes $12.2 loss associated with the discontinuance of Partnership interest rate protection agreements.


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

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

- 10 -

UGI CORPORATION AND SUBSIDIARIES

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

Energy Services Accounts Receivable Securitization Facility

Energy Services has a $200 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in April 2012, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility back-up purchasers.

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

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

During the six months ended March 31, 2011 and 2010, Energy Services transferred trade receivables totaling $687.0 and $714.8, respectively, to ESFC. During the six months ended March 31, 2011 and 2010, ESFC sold an aggregate $68.0 and $225.6, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At March 31, 2011, the balance of ESFC receivables was $86.7 and there was no amount sold to the commercial paper conduit. At March 31, 2010, the outstanding balance of ESFC receivables was $104.8 and there was no amount sold to the commercial paper conduit.

- 11 -

UGI CORPORATION AND SUBSIDIARIES

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

Utility Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 to the Company’s 2010 Annual Financial Statements and Notes. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:


	March 31,		September 30,		March 31,
	2011		2010		2010
Regulatory assets:
Income taxes recoverable	$	89.9	$	82.5	$	81.6
Underfunded pension and postretirement plans		116.0		159.2		10.4
Environmental costs		22.0		22.6		25.3
Deferred fuel and power costs		8.2		36.6		6.7
Other		8.6		5.8		5.9

Total regulatory assets	$	244.7	$	306.7	$	129.9


Regulatory liabilities:
Postretirement benefits	$	11.2	$	10.5	$	9.9
Environmental overcollections		6.8		7.2		8.4
Deferred fuel and power refunds		34.0		8.3		16.8
State tax benefits — distribution system repairs		6.3		6.7		—

Total regulatory liabilities	$	58.3	$	32.7	$	35.1

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

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

Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Unrealized gains (losses) on such contracts at March 31, 2011, September 30, 2010 and March 31, 2010 were $1.5, $(1.4) and $7.6, respectively.

- 12 -

UGI CORPORATION AND SUBSIDIARIES

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

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. As more fully described in Note 13, during Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value, with an associated adjustment to regulatory assets or liabilities in accordance with GAAP relating to rate-regulated entities and Electric Utility’s DS procurement, implementation and contingency plans. At March 31, 2011 and September 30, 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $10.7 and $19.7, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010 through DS rates, realized and unrealized gains or losses on FTRs associated with periods beginning January 1, 2010 are included in deferred fuel and power — costs or refunds. Unrealized gains on FTRs at March 31, 2011, September 30, 2010 and March 31, 2010 were not material.

Other Regulatory Matters

Transfer of CPG Storage Assets. On October 21, 2010, the Federal Energy Regulatory Commission (“FERC”) approved and later affirmed CPG’s application to abandon a storage service and approved the transfer of its Tioga, Meeker and Wharton natural gas storage facilities, along with related assets, to UGI Storage Company, a subsidiary of Energy Services. The PUC approved the transfer subject to, among other things, a reduction in base rates and CPG’s agreement to charge PGC customers, for a period of three years, no more for storage services from the transferred assets than they would have paid before the transfer, to the extent used. On April 1, 2011 the storage facilities were dividended to UGI and subsequently contributed to UGI Storage Company. The net book value of the storage facility assets was $10.9 as of March 31, 2011. The dividend of the storage assets is not expected to have a material impact on the results of operations of Gas Utility. Concurrent with the April 1, 2011 transfer, CPG entered into a firm storage service agreement with UGI Storage Company.

- 13 -

UGI CORPORATION AND SUBSIDIARIES

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

CPG Base Rate Filing. On January 14, 2011, CPG filed a request with the PUC to increase its base operating revenues by $16.5 annually. The increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment. CPG requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the effective date for the rate increase and to allow for investigation and public hearing. Unless a settlement is reached sooner the PUC review process is expected to last approximately nine months which may delay implementation of the new rates until late October 2011.

Defined Benefit Pension and Other Postretirement Plans

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

- 14 -

UGI CORPORATION AND SUBSIDIARIES

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

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


							Other
	Pension Benefits						Postretirement Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2011			2010			2011			2010
Service cost	$	2.1		$	2.2		$	0.1		$	0.1
Interest cost		6.1			5.9			0.3			0.3
Expected return on assets		(6.4	)		(6.5	)		(0.1	)		(0.1	)
Amortization of:
Prior service cost (benefit)		0.1			—			(0.2	)		(0.1	)
Actuarial loss		1.7			1.5			0.1			0.1

Net benefit cost		3.6			3.1			0.2			0.3
Change in associated regulatory liabilities		—			—			0.8			0.7

Net expense	$	3.6		$	3.1		$	1.0		$	1.0


							Other
	Pension Benefits						Postretirement Benefits
	Six Months Ended						Six Months Ended
	March 31,						March 31,
	2011			2010			2011			2010
Service cost	$	4.4		$	4.3		$	0.2		$	0.2
Interest cost		12.0			11.8			0.6			0.6
Expected return on assets		(12.9	)		(12.9	)		(0.3	)		(0.2	)
Amortization of:
Prior service cost (benefit)		0.1			—			(0.3	)		(0.2	)
Actuarial loss		4.0			2.9			0.2			0.1

Net benefit cost		7.6			6.1			0.4			0.5
Change in associated regulatory liabilities		—			—			1.6			1.5

Net expense	$	7.6		$	6.1		$	2.0		$	2.0

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $14.4 to the Pension Plan during the next twelve months. During the six months ended March 31, 2011, the Company made contributions to the Pension Plan of $12.6. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI Gas and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP for postretirement benefits other than pensions. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the six months ended March 31, 2011, nor are they expected to be material for all of Fiscal 2011.

We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans. We recorded pre-tax expense associated with these plans of $0.6 and $1.3 for the three and six months ended March 31, 2011, respectively. We recorded pre-tax expense associated with these plans of $0.6 and $1.2 for the three and six months ended March 31, 2010, respectively.

- 15 -

UGI CORPORATION AND SUBSIDIARIES

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

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

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


	Three Months
	Ended
	December 31,
	2010
Change in benefit obligations:
Benefit obligations — October 1, 2010	$	465.0
Service cost		2.2
Interest cost		5.8
Actuarial gain		(30.6	)
Benefits paid		(4.7	)

Benefit obligations — December 31, 2010	$	437.7


Change in plan assets:
Fair value of plan assets — October 1, 2010	$	287.9
Actual gain on assets		19.3
Employer contributions		1.8
Benefits paid		(4.7	)

Fair value of plan assets — December 31, 2010	$	304.3


Funded status of the merged plan — December 31, 2010	$	(133.4	)

At December 31, 2010:
Liabilities recorded in the balance sheet:
Unfunded liabilities — included in other current liabilities	$	(20.3	)
Unfunded liabilities — included in other noncurrent liabilities		(113.1	)

Net amount recognized	$	(133.4	)

Amounts recorded in regulatory assets and liabilities:
Prior service cost	$	0.3
Net actuarial loss		112.7

Total	$	113.0

Amounts recorded in stockholders’ equity:
Prior service cost	$	0.1
Net actuarial loss		9.8

Total	$	9.9

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

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UGI CORPORATION AND SUBSIDIARIES

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

Debt

AmeriGas Partners Refinancing. During the three months ended March 31, 2011, AmeriGas Partners issued $470 principal amount of 6.50% Senior Notes due 2021. The proceeds from the issuance of the 6.50% Senior Notes were used to repay AmeriGas Partners’ $415 7.25% Senior Notes due May 15, 2015 pursuant to a January 5, 2011 tender offer and subsequent redemption. The 6.50% Senior Notes due 2021 rank pari passu with AmeriGas Partners’ outstanding senior debt. In addition, during the three months ended March 31, 2011, AmeriGas Partners redeemed the outstanding $14.6 principal amount of AmeriGas Partners 8.875% Senior Notes due May 2011. The Partnership incurred a loss of $18.8 on these early extinguishments of debt which amount is reflected on the Consolidated Statements of Income under the caption “Loss on extinguishment of debt.” The loss reduced net income attributable to UGI Corporation by $5.2 during the three and six months ended March 31, 2011.

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

The new agreement consists of (1) a €380 variable-rate term loan and (2) a €40 revolving credit facility. Scheduled maturities under the term loan are €38 due May 2014, €34.2 due May 2015, and €307.8 due March 2016. Antargaz’ term loan and revolving credit facility bear interest at one-, two-, three- or six-month euribor, plus a margin, as defined by the 2011 Senior Facilities Agreement. The margin on the term loan and revolving credit facility borrowings (which ranges from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the 2011 Senior Facilities Agreement. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of 3.71% through the date of the term loan’s final maturity in March 2016. At March 31, 2011, the effective interest rate on Antargaz’ term loan was 4.75%. The 2011 Senior Facilities Agreement is collateralized by substantially all of Antargaz’ shares in its subsidiaries and by substantially all of its accounts receivables. In addition, UGI has guaranteed up to €100 of payments under the 2011 Senior Facilities Agreement.

- 17 -

UGI CORPORATION AND SUBSIDIARIES

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

10.

Commitments and Contingencies

Environmental Matters

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

UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs. At March 31, 2011, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

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

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

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

- 18 -

UGI CORPORATION AND SUBSIDIARIES

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

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

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

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

- 19 -

UGI CORPORATION AND SUBSIDIARIES

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

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

Other Matters

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

AmeriGas Cylinder Investigations . On or about October 21, 2009, the General Partner received a notice that the Offices of the District Attorneys of Santa Clara, Sonoma, Ventura, San Joaquin and Fresno Counties and the City Attorney of San Diego have commenced an investigation into AmeriGas OLP’s cylinder labeling and filling practices in California and issued an administrative subpoena seeking documents and information relating to these practices. We are cooperating with these California governmental investigations but have had no further contact from the District Attorneys since their initial inquiry.

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

- 20 -

UGI CORPORATION AND SUBSIDIARIES

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

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

Antargaz Competition Authority Matter. On July 21, 2009, Antargaz received a Statement of Objections from France’s Autorité de la concurrence (“Competition Authority”) with respect to the investigation of Antargaz by the General Division of Competition, Consumption and Fraud Punishment. The Statement alleged that Antargaz engaged in certain anti-competitive practices in violation of French competition laws related to the cylinder market during the period from 1999 through 2004. On December 17, 2010, the Competition Authority issued its decision dismissing all objections against Antargaz. The appeal period has expired without an appeal having been filed. As a result of the decision, during the three-month period ended December 31, 2010 the Company reversed its previously recorded nontaxable accrual for this matter which increased net income by $9.4. This amount is reflected in other income, net, on the Condensed Consolidated Statement of Income for the six months ended March 31, 2011.

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

- 21 -

UGI CORPORATION AND SUBSIDIARIES

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

11.

Equity

The following table sets forth changes in UGI’s equity and the equity of the noncontrolling interests for the six months ended March 31, 2011 and 2010:


				UGI Shareholders
									Accumulated
									Other
	Non-								Comprehensive
	controlling			Common		Retained			Income			Treasury			Total
	Interests			Stock		Earnings			(Loss)			Stock			Equity

Six Months Ended March 31, 2011:
Balance September 30, 2010	$	237.1		$	906.1	$	966.7		$	(10.1	)	$	(38.2	)	$	2,061.6
Net income		108.1					262.5									370.6
Net gains on derivative instruments		14.1								22.3						36.4
Reclassifications of net (gains) losses on derivative instruments		(10.8	)							24.7						13.9
Benefit plans										2.1						2.1
Foreign currency translation adjustments										24.6						24.6

Comprehensive income		111.4					262.5			73.7						447.6
Dividends and distributions		(45.7	)				(55.7	)								(101.4	)
Equity transactions		0.3			25.4								8.8			34.5
Other		0.8														0.8

Balance March 31, 2011	$	303.9		$	931.5	$	1,173.5		$	63.6		$	(29.4	)	$	2,443.1


Six Months Ended March 31, 2010:
Balance September 30, 2009	$	225.4		$	875.6	$	804.3		$	(38.9	)	$	(49.6	)	$	1,816.8
Net income		122.8					255.5									378.3
Net gains (losses) on derivative instruments		18.1								(12.1	)					6.0
Reclassifications of net (gains) losses on derivative instruments		(11.9	)							22.5						10.6
Benefit plans										1.7						1.7
Foreign currency translation adjustments										(44.6	)					(44.6	)

Comprehensive income		129.0					255.5			(32.5	)					352.0
Dividends and distributions		(43.4	)				(43.6	)								(87.0	)
Equity transactions		0.7			8.3								2.1			11.1
Other		(1.6	)													(1.6	)

Balance, March 31, 2010	$	310.1		$	883.9	$	1,016.2		$	(71.4	)	$	(47.5	)	$	2,091.3

- 22 -

UGI CORPORATION AND SUBSIDIARIES

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

12.

Fair Value Measurement

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of March 31, 2011, September 30, 2010 and March 31, 2010:


	Asset (Liability)
	Quoted Prices
	in Active			Significant
	Markets for			Other
	Identical Assets			Observable			Unobservable
	and Liabilities			Inputs			Inputs
	(Level 1)			(Level 2)			(Level 3)		Total
March 31, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	2.6		$	12.1		$	—	$	14.7
Foreign currency contracts	$	—		$	0.3		$	—	$	0.3
Interest rate contracts	$	—		$	13.0		$	—	$	13.0
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(10.6	)	$	(9.8	)	$	—	$	(20.4	)
Foreign currency contracts	$	—		$	(4.0	)	$	—	$	(4.0	)
Interest rate contracts	$	—		$	(0.2	)	$	—	$	(0.2	)

September 30, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	1.1		$	10.7		$	—	$	11.8
Foreign currency contracts	$	—		$	0.8		$	—	$	0.8
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(49.4	)	$	(20.3	)	$	—	$	(69.7	)
Foreign currency contracts	$	—		$	(2.9	)	$	—	$	(2.9	)
Interest rate contracts	$	—		$	(18.5	)	$	—	$	(18.5	)

March 31, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	0.2		$	5.9		$	—	$	6.1
Foreign currency contracts	$	—		$	5.8		$	—	$	5.8
Interest rate contracts	$	—		$	2.8		$	—	$	2.8
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(44.4	)	$	(0.1	)	$	—	$	(44.5	)
Foreign currency contracts	$	—		$	(0.2	)	$	—	$	(0.2	)
Interest rate contracts	$	—		$	(30.4	)	$	—	$	(30.4	)

- 23 -

UGI CORPORATION AND SUBSIDIARIES

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

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

Other Financial Instruments

The carrying amounts of financial instruments included in current assets and current liabilities (excluding unsettled derivative instruments and current maturities of long-term debt) approximate their fair values because of their short-term nature. The carrying amount and estimated fair value of our long-term debt at March 31, 2011 were $2,066.0 and $2,159.9, respectively. The carrying amount and estimated fair value of our long-term debt at March 31, 2010 were $2,082.3 and $2,156.1, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt.

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

13.

Disclosures About Derivative Instruments and Hedging Activities

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

- 24 -

UGI CORPORATION AND SUBSIDIARIES

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

Commodity Price Risk

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

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At March 31, 2011 the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 21.5 million dekatherms and the maximum period over which Gas Utility is hedging natural gas market price risk is 18 months. At March 31, 2010, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 14.1 million dekatherms. 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 Accounting Standards Codification (“ASC”) No. 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 7).

Beginning January 1, 2010, Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception under GAAP related to derivative financial instruments. The inability of Electric Utility to continue to assert that it would take physical delivery of such power resulted principally from a greater than anticipated number of customers, primarily certain commercial and industrial customers, choosing an alternative electricity supplier. Because these contracts no longer qualify for the normal purchases and normal sales exception under GAAP, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At March 31, 2011, the fair values of Electric Utility’s forward purchase power agreements comprising a loss of $10.7 are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying March 31, 2011 Condensed Consolidated Balance Sheet. In accordance with ASC 980, Electric Utility has recorded equal and offsetting amounts in regulatory assets on the March 31, 2011 Condensed Consolidated Balance Sheet. At March 31, 2011, the volumes under Electric Utility’s forward electricity purchase contracts were 835.5 million kilowatt hours and the maximum period over which these contracts extend is 37 months.

- 25 -

UGI CORPORATION AND SUBSIDIARIES

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

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs associated with certain default service customers, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs commencing January 1, 2010, gains and losses on Electric Utility FTRs associated with periods beginning on or after January 1, 2010 are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 7). Gains and losses associated with periods prior to January 2010 are reflected in cost of sales. At March 31, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 138.2 million kilowatt hours and 477.6 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At March 31, 2011 and 2010, the volumes associated with Midstream & Marketing’s FTRs totaled 257.7 million kilowatt hours and 183.0 million kilowatt hours, respectively.

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

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 March 31, 2011 and 2010, we had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:


	Volumes
	March 31,
Commodity	2011		2010

LPG (millions of gallons)		47.3		74.4
Natural gas (millions of dekatherms)		21.9		22.9
Electricity (millions of kilowatt-hours)		1,516.2		542.2

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UGI CORPORATION AND SUBSIDIARIES

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

At March 31, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 18 months with a weighted average of 3 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 31 months with a weighted average of 9 months; and the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity price risk (excluding Electric Utility) is 23 months with a weighted average of 9 months. At March 31, 2011, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 2 months.

We account for commodity price risk contracts (other than our Gas Utility natural gas futures and option contracts, Electric Utility electricity forward contracts, gasoline futures and swap contracts, and FTRs) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in accumulated other comprehensive income (“AOCI”) and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales on the Condensed Consolidated Statements of Income. At March 31, 2011, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $4.8.

Interest Rate Risk

Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Prior to its repayment in March 2011, Antargaz had effectively fixed the underlying euribor interest rate on its €380 variable-rate debt through the use of pay-fixed, receive-variable interest rate swap agreements. Antargaz refinanced this €380 variable-rate term loan on March 16, 2011 (see Note 9). Antargaz has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on this debt through its scheduled maturity dates ending in 2016. Flaga has also fixed the underlying euribor interest rate on a substantial portion of its two term loans through their scheduled maturity dates ending in 2011 and 2014, respectively, through the use of pay-fixed, receive-variable interest rate swap agreements. As of March 31, 2011 and 2010, the total notional amounts of our variable-rate debt subject to interest rate swap agreements were €399.5 and €406.9, 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 March 31, 2011, the total notional amount of unsettled IRPAs was $106.5. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt forecasted to occur in September 2012 and September 2013.

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UGI CORPORATION AND SUBSIDIARIES

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

As previously disclosed, during the three months ended March 31, 2010, the Partnership’s management determined that it was likely that it would not issue $150 of long-term debt during the summer of 2010. As a result, the Partnership discontinued cash flow hedge accounting treatment for interest rate protection agreements associated with this previously anticipated long-term debt issuance and recorded a $12.2 loss during the three months ended March 31, 2010 which is reflected in other (income) expense, net on the Condensed Consolidated Statements of Income. These interest rate protection agreements were settled in cash in April 2010.

We account for interest rate swaps and IRPAs as cash flow hedges. Changes in the fair values of interest rate swaps and IRPAs are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At March 31, 2011, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $1.7.

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At March 31, 2011 and 2010, we were hedging a total of $69.8 and $60.1 of U.S. dollar-denominated LPG purchases, respectively. At March 31, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 24 months with a weighted average of 12 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our International Propane euro-denominated net investments. At March 31, 2011 and 2010, we were hedging a total of €14.5 and €48.3, respectively, of our euro-denominated net investments. As of March 31, 2011, our foreign currency contracts extend through March 2013.

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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 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 March 31, 2011, the amount of net losses associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $2.7. Gains and losses on net investment hedges remain in AOCI until such foreign operations are liquidated.

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise major energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and option contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. At March 31, 2011 and 2010, restricted cash in these accounts totaled $9.6 and $38.9, respectively. Although we have concentrations of credit risk associated with derivative financial instruments, the maximum amount of loss, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at March 31, 2011. We generally do not have credit-risk-related contingent features in our derivative contracts.

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UGI CORPORATION AND SUBSIDIARIES

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

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of March 31, 2011 and 2010:


	Derivative Assets					Derivative (Liabilities)
		Fair Value					Fair Value
	Balance Sheet	March 31,				Balance Sheet	March 31,
	Location	2011		2010		Location	2011			2010
Derivatives Designated as Hedging Instruments:

Commodity contracts	Derivative financial instruments					Derivative financial instruments
	and Other assets	$	12.3	$	5.1	and Other noncurrent liabilities	$	(9.7	)	$	(36.9	)
Foreign currency contracts
	Derivative financial instruments					Derivative financial instruments
	and Other assets		0.3		5.8	and Other noncurrent liabilities		(4.0	)		(0.2	)
Interest rate contracts
						Derivative financial instruments
	Other assets		13.0		—	and Other noncurrent liabilities		(0.2	)		(13.4	)

Total Derivatives Designated as Hedging Instruments		$	25.6	$	10.9		$	(13.9	)	$	(50.5	)


Derivatives Accounted for under ASC 980:
Commodity contracts	Derivative financial instruments	$	1.6	$	0.3	Derivative financial instruments and Other noncurrent liabilities	$	(10.7	)	$	(7.6	)

Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments
	and Other assets	$	0.8	$	0.7	Derivative financial instruments	$	—		$	—
Interest rate contracts (a)	Derivative financial instruments		—		2.8	Derivative financial instruments		—			(17.0	)


Total Derivatives Not Designated as Hedging Instruments		$	0.8	$	3.5		$	—		$	(17.0	)


Total Derivatives		$	28.0	$	14.7		$	(24.6	)	$	(75.1	)


(a)		Amounts represent fair values of Partnership IRPAs for which cash flow hedge accounting was discontinued in March 2010.

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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 and six months ended March 31, 2011 and 2010:

Three Months Ended March 31,:


	Gain (Loss)						Gain (Loss)						Location of
	Recognized in						Reclassified from						Gain (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2011			2010			2011			2010			Interests into Income
Cash Flow
Hedges:
Commodity contracts	$	6.8		$	(44.3	)	$	(3.0	)	$	11.3		Cost of sales
Foreign currency contracts		(4.4	)		4.7			0.2			0.9		Cost of sales
Interest rate contracts		10.4			(6.1	)		(3.5	)		(16.2	)	Interest expense / other income

Total	$	12.8		$	(45.7	)	$	(6.3	)	$	(4.0	)


Net Investment
Hedges:

Foreign currency contracts	$	(1.0	)	$	4.1


	Gain (Loss)
	Recognized in Income						Location of Gain (Loss)
	2011			2010			Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	0.2		$	—		Operating expenses / other income
Commodity contracts		(0.5	)		(0.1	)	Cost of sales

Total	$	(0.3	)	$	(0.1	)

Six Months Ended March 31,:


	Gain (Loss)						Gain (Loss)						Location of
	Recognized in						Reclassified from						Gain (Loss)
	AOCI and						AOCI and Noncontrolling						Reclassified from
	Noncontrolling Interests						Interests into Income						AOCI and Noncontrolling
	2011			2010			2011			2010			Interests into Income
Cash Flow
Hedges:
Commodity contracts	$	26.7		$	(15.8	)	$	(23.0	)	$	(6.4	)	Cost of sales
Foreign currency contracts		(1.5	)		6.8			(0.8	)		0.6		Cost of sales
Interest rate contracts		24.9			(0.8	)		(7.2	)		(20.5	)	Interest expense /other income

Total	$	50.1		$	(9.8	)	$	(31.0	)	$	(26.3	)


Net Investment
Hedges:

Foreign currency contracts	$	(0.6	)	$	5.1


	Gain (Loss)
	Recognized in Income					Location of Gain (Loss)
	2011			2010		Recognized in Income
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	0.4		$	0.2	Operating expenses / other income
Commodity contracts		(0.6	)		0.4	Cost of sales

Total	$	(0.2	)	$	0.6

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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 amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material for the three and six months ended March 31, 2011 and 2010.

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

14.

Inventories

Inventories comprise the following:


	March 31,		September 30,		March 31,
	2011		2010		2010
Non-utility LPG and natural gas	$	160.9	$	157.9	$	142.8
Gas Utility natural gas		7.9		111.5		31.7
Materials, supplies and other		53.3		44.6		49.4


Total inventories	$	222.1	$	314.0	$	223.9

At March 31, 2011, UGI Utilities is a party to three storage contract administrative agreements (“SCAAs”), two of which expire in October 2012 and one of which expires in October 2013. Pursuant to these and predecessor SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the term of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished), are included in the caption “Gas Utility natural gas” in the table above.

The carrying values of natural gas storage inventories released under SCAAs with non-affiliates at March 31, 2011, September 30, 2010 and March 31, 2010 comprising 0.4 billion cubic feet (“bcf”), 8.0 bcf and 1.7 bcf of natural gas was $1.6, $41.9 and $11.9, respectively.

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UGI CORPORATION AND SUBSIDIARIES


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

Forward-Looking Statements

Information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” “will,” or other similar words. These statements discuss plans, strategies, events or developments that we expect or anticipate will or may occur in the future.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other LPG, oil, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) large customer, counterparty or supplier defaults; (12) liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and LPG; (13) political, regulatory and economic conditions in the United States and in foreign countries, including foreign currency exchange rate fluctuations, particularly the euro; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (15) changes in commodity market prices resulting in significantly higher cash collateral requirements; (16) reduced distributions from subsidiaries; (17) the timing of development of Marcellus Shale gas production; and (18) the timing and success of our acquisitions, commercial initiatives and investments to grow our businesses.

These factors, and those factors set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on our business, financial condition or future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

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UGI CORPORATION AND SUBSIDIARIES

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare our results of operations for the three months ended March 31, 2011 (“2011 three-month period”) with the three months ended March 31, 2010 (“2010 three-month period”) and the six months ended March 31, 2011 (“2011 six-month period”) with the six months ended March 31, 2010 (“2010 six-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 5 to the condensed consolidated financial statements.

Executive Overview

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

We recorded net income attributable to UGI Corporation of $149.4 million for the 2011 three-month period compared to net income attributable to UGI Corporation of $157.1 million in the prior-year three-month period. Results in the 2011 three-month period include a $5.2 million after-tax loss associated with AmeriGas Partners’ early extinguishment of Senior Notes while net income attributable to UGI Corporation in the 2010 three-month period includes a $3.3 million after-tax loss from the Partnership’s discontinuance of interest rate hedges.

Our 2011 three-month period net income attributable to UGI Corporation includes greater net income from our Gas Utility principally reflecting the benefits of colder weather and an improving economy. However, in our International Propane operations, significantly warmer weather and the continuing effects of higher LPG commodity prices on customer usage decreased Antargaz’ volumes sold and total margin. Average temperatures in our AmeriGas Propane service territory during the 2011 three-month period were slightly colder than normal and the prior year. However, lower retail volumes resulting from the effects of significantly warmer weather in our southern regions during February and March and customer conservation reduced AmeriGas Propane’s total margin. Midstream & Marketing’s contribution to net income attributable to UGI Corporation was modestly higher than the prior year as greater contributions from retail power marketing, peaking and asset management activities, and tax benefits associated with solar energy projects were offset in large part by the absence of earnings from Atlantic Energy, LLC’s LPG storage facility, which was sold in July 2010, and lower earnings contribution from our electricity generation assets.

We recorded net income attributable to UGI Corporation of $262.5 million for the 2011 six-month period compared to net income attributable to UGI Corporation of $255.5 million in the prior-year six-month period. As previously mentioned, results in the 2011 six-month period include the $5.2 million after-tax loss associated with AmeriGas Partners’ early extinguishment of Senior Notes while net income attributable to UGI Corporation in the 2010 six-month period includes the $3.3 million after-tax loss from the discontinuance of Partnership interest rate hedges. The current-year six-month period also reflects net income of $9.4 million from the reversal at Antargaz of a nontaxable reserve associated with the French Competition Authority Matter (see Note 9 to condensed consolidated financial statements).

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UGI CORPORATION AND SUBSIDIARIES

Our 2011 six-month period net income attributable to UGI Corporation reflects greater net income from our Gas Utility principally the result of colder 2011-period weather and an improving economy. Weather at Antargaz for the 2011 six-month period was slightly colder than normal and about equal to last year. Although Antargaz’ retail volumes sold were comparable to the prior-year six-month period, Antargaz’ total margin declined reflecting the effects of rapidly rising LPG product costs on unit margins primarily during the first quarter of Fiscal 2011. Temperatures in our AmeriGas Propane service territory during the 2011 six-month period averaged about normal and approximately equal to last year. However, AmeriGas Propane experienced significantly warmer early fall weather and, in our southern regions, significantly warmer late winter weather. The effects of these weather patterns, customer conservation, and the impact on the prior-year volumes of a strong crop-drying season, resulted in lower retail volume sales and lower total margin. Midstream & Marketing’s contribution to net income attributable to UGI Corporation was slightly above the prior-year six-month period as greater contributions from retail power marketing, winter peaking and asset management activities, and tax benefits associated with solar energy projects were largely offset by the absence of earnings from Atlantic Energy and lower contribution from our electricity generation assets.

U.S. dollar to euro exchange rates did not have a significant effect on year-over-year three-month period results. However, the U.S. dollar was stronger versus the euro during the 2011 six-month period. The effects of the stronger dollar during the 2011 six-month period reduced International Propane net income compared to last year by approximately $4.0 million which amount includes the effects of gains and losses on forward currency contracts used to hedge purchases of dollar-denominated LPG.

We believe that each of our business units has sufficient liquidity in the form of revolving credit facilities and, in the case of Energy Services, an accounts receivable securitization facility to fund business operations in Fiscal 2011. Antargaz recently completed the refinancing of its maturing €380 million term loan and entered into a €40 million revolving credit facility which replaces its previous €50 million revolving credit facility. During the remainder of Fiscal 2011, Flaga has €21.7 million of term loan debt maturing substantially all of which we expect to refinance on a long-term basis. Additionally, UGI Utilities, AmeriGas OLP and Flaga expect to renew their credit facilities during the third quarter of Fiscal 2011. In April 2011, Energy Services extended its receivables securitization facility through April 2012.

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UGI CORPORATION AND SUBSIDIARIES

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

Net income attributable to UGI Corporation by Business Unit:


	Three Months Ended												Variance - Favorable
	March 31,												(Unfavorable)
				% of						% of
(Millions of dollars)	2011			Total			2010			Total			Amount			%
AmeriGas Propane (a)	$	32.0			21.4	%	$	36.4			23.2	%	$	(4.4	)		(12.1	)%
International Propane		35.3			23.6	%		48.2			30.7	%		(12.9	)		(26.8	)%
Gas Utility		58.4			39.1	%		49.0			31.2	%		9.4			19.2	%
Electric Utility		1.7			1.1	%		1.6			1.0	%		0.1			6.2	%
Midstream & Marketing		25.5			17.1	%		24.2			15.4	%		1.3			5.4	%
Corporate & Other		(3.5	)		(2.3	)%		(2.3	)		(1.5	)%		(1.2	)		N.M.

Net income attributable to UGI Corporation	$	149.4			100.0	%	$	157.1			100.0	%	$	(7.7	)		(4.9	)%


N.M. — Variance is not meaningful.

(a)		2011 three-month period net income from AmeriGas Propane includes a $5.2 million loss associated with the early extinguishment of debt. 2010 three-month period net income from AmeriGas Propane includes $3.3 million loss associated with the discontinuance of Partnership interest rate hedges.

AmeriGas Propane:


							Increase
For the three months ended March 31,	2011			2010			(Decrease)
(Millions of dollars)
Revenues	$	906.8		$	886.1		$	20.7		2.3	%
Total margin (a)	$	342.0		$	346.4		$	(4.4	)	(1.3	)%
Partnership EBITDA (b)	$	157.5		$	173.6		$	(16.1	)	(9.3	)%
Operating income (b)	$	154.6		$	153.3		$	1.3		0.8	%
Retail gallons sold (millions)		316.3			329.2			(12.9	)	(3.9	)%
Degree days — % colder than normal (c)		1.9	%		0.2	%		—		—


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

(b)		Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 5 to condensed consolidated financial statements). Partnership EBITDA for the three months ended March 31, 2011 includes a pre-tax loss of $18.8 million associated with the early extinguishment of debt. Partnership EBITDA and operating income for the three months ended March 31, 2010 includes a pre-tax loss of $12.2 million associated with the discontinuance of interest rate hedges.

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

Based upon heating degree-day data, average temperatures in the Partnership’s service territories were 1.9% colder than normal during the 2011 three-month period compared with temperatures that were approximately normal in the prior-year period. Although average temperatures were slightly colder than last year, the Partnership experienced significantly warmer weather in its southern regions during February and March 2011. Retail propane gallons sold declined principally due to the effects of the regional weather patterns and customer conservation partially offset by volumes acquired through acquisitions.

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UGI CORPORATION AND SUBSIDIARIES

Retail propane revenues increased $15.1 million during the 2011 three-month period reflecting higher average retail sales prices ($45.8 million) partially offset by lower retail volumes sold ($30.7 million). Wholesale propane revenues were about equal to the prior-year period. Average wholesale propane prices at Mont Belvieu, Texas, a major supply location in the U.S., were approximately 12% higher during the 2011 three-month period compared with average wholesale propane prices during the 2010 three-month period. Other revenues from fee income and ancillary sales and services increased $6.2 million in the 2011 three-month period. Total cost of sales increased $25.1 million, to $564.8 million, reflecting higher 2011 wholesale propane product costs.

Total margin was $4.4 million lower in the 2011 three-month period primarily due to lower total retail margin ($8.3 million) partially resulting primarily from higher employee benefit costs and vehicle expenses offset principally by an increase in margin from fee income. The lower total retail margin reflects the effects of the lower retail volumes sold ($12.3 million) partially offset by the effects of slightly higher average retail unit margins ($4.0 million).

The $16.1 million decrease in Partnership EBITDA during the 2011 three-month period primarily reflects (1) the loss on early extinguishment of Partnership Senior Notes ($18.8 million); (2) slightly higher operating and administrative expenses ($4.4 million) resulting primarily from higher employee benefit costs and vehicle expenses; and (3) the previously mentioned decrease in 2011 three-month total margin ($4.4 million). The effect of these items on the change in Partnership EBITDA was partially offset by the absence of a $12.2 million loss recorded in the prior-year three-month period resulting from the discontinuance of interest rate hedges.

Operating income (which excludes the loss on early extinguishment of debt) increased $1.3 million in the 2011 three-month period principally reflecting the absence of the loss on interest rate hedges recorded in the prior year ($12.2 million) substantially offset by (1) higher operating and administrative and depreciation and amortization expenses ($5.7 million) and (2) the lower total margin ($4.4 million). Partnership interest expense was $0.4 million lower in the 2011 three-month period.

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UGI CORPORATION AND SUBSIDIARIES

International Propane:


							Increase
For the three months ended March 31,	2011			2010			(Decrease)
(Millions of euros) (a)
Revenues	€	362.7		€	278.9		€	83.8		30.0	%
Total margin (b)	€	128.8		€	129.6		€	(0.8	)	(0.6	)%
Operating income	€	46.5		€	58.2		€	(11.7	)	(20.1	)%
Income before income taxes	€	41.6		€	53.7		€	(12.1	)	(22.5	)%

(Millions of dollars) (a)
Revenues	$	503.9		$	386.4		$	117.5		30.4	%
Total margin (b)	$	177.7		$	179.1		$	(1.4	)	(0.8	)%
Operating income	$	61.8		$	80.8		$	(19.0	)	(23.5	)%
Income before income taxes	$	55.1		$	74.4		$	(19.3	)	(25.9	)%

Antargaz retail gallons sold		94.5			106.6			(12.1	)	(11.4	)%
Antargaz degree days — % (warmer) colder than normal (c)		(7.0	)%		10.8	%		—		—
Flaga retail gallons sold		39.1			18.2			20.9		114.8	%
Flaga degree days — % (warmer) colder than normal (c)		(1.5	)%		3.4	%		—		—


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

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

(c)		Deviation from average heating degree days for the 30-year period 1971-2000 at locations in our International Propane service territories.

Based upon heating degree-day data, temperatures in Antargaz’ service territory were approximately 7.0% warmer than normal during the 2011 three-month period compared with temperatures that were approximately 10.8% colder than normal during the prior-year period. Temperatures in Flaga’s service territory were also warmer than normal and warmer than the prior year. The increase in Flaga’s 2011 three-month period retail gallons sold reflects the effects of acquisitions completed in late Fiscal 2010 and early Fiscal 2011. Antargaz’ retail volumes declined principally due to the significantly warmer 2011 three-month period weather and price-induced customer conservation resulting from higher LPG product prices. Based upon posted wholesale LPG prices in Northwest Europe, average wholesale propane costs were approximately 23% higher and average butane costs were approximately 22% higher than in the prior-year three-month period.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. During the 2011 three-month period, the average currency translation rate was $1.37 per euro, comparable to rates during the prior-year three-month period.

International Propane euro base-currency revenues increased €83.8 million or 30.0% reflecting higher revenues from Antargaz (€39.4 million) and Flaga (€44.4 million). The increase in Antargaz revenues principally reflects the effects of (1) higher average retail selling prices (€35.5 million) and (2) higher wholesale revenues (€29.3 million) partially offset by the effects of the lower retail volumes sold (€24.8 million). The higher Flaga revenues reflect the effects of the previously mentioned acquisitions and higher average selling prices. Higher average selling prices at Antargaz and Flaga in the 2011 three-month period resulted from the

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UGI CORPORATION AND SUBSIDIARIES

previously mentioned year-over-year increase in wholesale LPG product costs. In U.S. dollars, revenues increased $117.5 million or 30.4% principally reflecting the previously mentioned higher euro base-currency revenues. International Propane’s euro base-currency total cost of sales increased €84.5 million to €233.9 million in the 2011 three-month period from €149.4 million in the prior year principally reflecting the higher LPG product costs, higher wholesale sales at Antargaz (€29.3 million) and the higher retail sales at Flaga. On a U.S. dollar basis, cost of sales increased to $326.2 million from $207.3 million in the prior-year period principally reflecting the previously mentioned higher euro base-currency per unit commodity costs, higher Antargaz wholesale sales volumes and higher Flaga retail gallons sold.

International Propane euro-denominated total margin was about equal to the prior year as higher margin from Flaga (€9.2 million), principally related to recent acquisitions, was largely offset by lower total margin from Antargaz (€10.0 million). The decrease in Antargaz’ total margin reflects the lower retail LPG volumes sold (€13.4 million) partially offset by the impact of slightly higher average LPG retail unit margins. U.S dollar total margin was equal to the prior-year period.

International Propane euro base-currency operating income decreased €11.7 million principally the result of the lower total margin at Antargaz. Higher total margin at Flaga resulting principally from the recent acquisitions was largely offset by higher euro base-currency operating and depreciation expenses associated with the acquired businesses. On a U.S. dollar basis, operating income decreased $19.0 million principally reflecting the lower operating income at Antargaz. Euro base-currency income before income taxes was €12.1 million lower than in the prior-year period principally reflecting the previously mentioned €11.7 million decrease in base-currency operating income. In U.S. dollars, income before income taxes decreased $19.3 million principally reflecting the previously mentioned lower U.S. dollar-denominated operating income.

Gas Utility:


For the three months ended March 31,	2011			2010			Increase
(Millions of dollars)
Revenues	$	452.5		$	445.4		$	7.1	1.6	%
Total margin (a)	$	163.9		$	154.0		$	9.9	6.4	%
Operating income	$	100.9		$	91.1		$	9.8	10.8	%
Income before income taxes	$	90.7		$	80.8		$	9.9	12.3	%
System throughput — billions of cubic feet (“bcf”)		61.3			54.6			6.7	12.3	%
Degree days — % colder (warmer) than normal (b)		6.6	%		(2.0	)%		—	—


(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 the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

Temperatures in the Gas Utility service territory based upon heating degree days were 6.6% colder than normal in the 2011 three-month period compared with temperatures that were 2.0% warmer than normal in the prior-year period. Total distribution system throughput increased 6.7 bcf (12.3%) principally reflecting the effects of the colder weather on core market customers, higher throughput to certain low-margin interruptible delivery service customers and the benefits of an improving economy. Gas Utility’s core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.

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UGI CORPORATION AND SUBSIDIARIES

Gas Utility revenues increased $7.1 million during the 2011 three-month period principally reflecting a $22.2 million increase in revenues from low-margin off-system sales partially offset by a decline in revenues from core market customers ($15.2 million). The decrease in core market revenues principally reflects lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices ($36.2 million) partially offset by the greater core market volumes. Under Gas Utility’s PGC recovery mechanisms, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $288.6 million in the 2011 three-month period compared with $291.4 million in the prior-year period principally reflecting the lower average PGC rates partially offset by the effects of the higher off-system sales.

Gas Utility total margin increased $9.9 million in the 2011 three-month period. The increase principally reflects a $9.1 million increase in core market margin resulting from the higher core market throughput.

The increases in Gas Utility operating income and income before income taxes during the 2011 three-month period principally reflect (1) the previously mentioned increase in total margin ($9.9 million) and (2) greater other income ($2.0 million). These increases were partially offset by slightly higher operating and administrative and depreciation expenses ($2.1 million).

Electric Utility:


					Increase
For the three months ended March 31,	2011		2010		(Decrease)
(Millions of dollars)
Revenues	$	31.7	$	31.6	$	0.1		0.3	%
Total margin (a)	$	9.7	$	9.1	$	0.6		6.6	%
Operating income	$	3.0	$	3.1	$	(0.1	)	(3.2	)%
Income before income taxes	$	2.4	$	2.6	$	(0.2	)	(7.7	)%
Distribution sales — millions of kilowatt hours (“gwh”)		279.0		262.8		16.2		6.2	%


(a)		Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $1.8 million and $1.7 million during the three-month periods ended March 31, 2011 and 2010, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the condensed consolidated statements of income.

Electric Utility’s kilowatt-hour sales in the 2011 three-month period were 6.2% higher than in the prior year three-month period on heating degree day weather that was 8.5% colder. Notwithstanding the effects on heating-related sales from the colder weather, Electric Utility revenues were about equal to last year principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity generation portion of their service. Electric Utility cost of sales declined to $20.2 million in the 2011 three-month period compared to $20.7 million in the 2010 three-month period principally reflecting the effects of the previously mentioned electricity generation supplier customer switching.

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UGI CORPORATION AND SUBSIDIARIES

Electric Utility total margin increased $0.6 million in the 2011 three-month period principally reflecting the impact of the greater sales.

Notwithstanding the greater total margin, Electric Utility 2011 three-month period operating income and income before income taxes declined $0.1 million and $0.2 million, respectively, principally reflecting higher operating expenses.

Midstream & Marketing:


For the three months ended March 31,	2011		2010		Decrease
(Millions of dollars)
Revenues	$	360.3	$	438.6	$	(78.3	)	(17.9	)%
Total margin (a)	$	54.9	$	56.3	$	(1.4	)	(2.5	)%
Operating income	$	40.8	$	40.8	$	—		0.0	%
Income before income taxes	$	40.1	$	40.8	$	(0.7	)	(1.7	)%


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

Midstream & Marketing total revenues decreased $78.3 million in the 2011 three-month period principally reflecting the absence of revenues from Atlantic Energy, LLC’s (“Atlantic Energy’s”) import and transshipment facility ($50.8 million) and, to a lesser extent, lower total revenues from natural gas marketing activities reflecting lower natural gas prices. As previously reported, Atlantic Energy was sold in July 2010. These decreases in revenues were partially offset by an increase in retail power sales revenues ($10.2 million).

The decrease in total Midstream & Marketing margin principally reflects lower electric generation total margin ($2.6 million) and the absence of margin from Atlantic Energy ($4.6 million). These reductions were substantially offset by combined increases in margin from winter peaking and asset management activities ($6.5 million). The decrease in electric generation total margin principally reflects lower spot prices for electricity and the absence of margin from UGID’s Hunlock Creek coal-fired generating station which ceased operations in May 2010 to transition to a natural gas-fired generating station. Midstream & Marketing’s operating income was equal to last year principally reflecting the previously mentioned decrease in total margin ($1.4 million) substantially offset by the absence in the current year of operating and depreciation expenses associated with the Hunlock Creek generating station and Atlantic Energy. Hunlock Creek’s 125-megawatt natural gas-fired generating station is expected to commence operations during the fourth quarter of Fiscal 2011. The decline in income before income taxes reflects greater interest expense ($0.7 million), the result of the change in accounting for Energy Services’ Receivables Facility, and fees and expenses associated with Energy Services new credit facility (see Notes 3 and 6 to condensed consolidated financial statements).

Interest Expense and Income Taxes. Our consolidated interest expense was slightly higher in the 2011 three-month period principally reflecting higher Energy Services’ interest expense partially offset by lower interest expense on Partnership long-term debt. Our annual estimated effective tax rate was lower in the 2011 three-month period principally reflecting (1) the effects of federal tax credits associated with anticipated solar energy projects and (2) a reduction in UGI Utilities’ income taxes reflecting the regulatory effects of greater state tax depreciation (as further described below under “Financial Condition & Liquidity”).

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UGI CORPORATION AND SUBSIDIARIES

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

Net income attributable to UGI Corporation by Business Unit:


	Six Months Ended												Variance - Favorable
	March 31,												(Unfavorable)
				% of						% of
(Millions of dollars)	2011			Total			2010			Total			Amount			%
AmeriGas Propane (a)	$	52.6			20.0	%	$	59.4			23.2	%	$	(6.8	)		(11.4	)%
International Propane (b)		68.5			26.1	%		74.0			29.0	%		(5.5	)		(7.4	)%
Gas Utility		97.6			37.2	%		81.1			31.7	%		16.5			20.3	%
Electric Utility		3.4			1.3	%		4.5			1.8	%		(1.1	)		(24.4	)%
Midstream & Marketing		43.6			16.6	%		40.6			15.9	%		3.0			7.4	%
Corporate & Other		(3.2	)		(1.2	)%		(4.1	)		(1.6	)%		0.9			N.M.

Net income attributable to UGI Corporation	$	262.5			100.0	%	$	255.5			100.0	%	$	7.0			2.7	%


N.M. — Variance is not meaningful.

(a)		2011 six-month period net income from AmeriGas Propane includes a $5.2 million loss associated with the early extinguishment of debt. 2010 six-month period net income from AmeriGas Propane includes $3.3 million of loss associated with the discontinuance of Partnership interest rate hedges.

(b)		2011 six-month period net income from International Propane includes $9.4 million of income from a nontaxable reserve reversal at Antargaz associated with the French Competition Authority Matter (see Note 10 to condensed consolidated financial statements).

AmeriGas Propane:


							Increase
For the six months ended March 31,	2011			2010			(Decrease)
(Millions of dollars)
Revenues	$	1,607.0		$	1,542.7		$	64.3		4.2	%
Total margin (a)	$	606.9		$	613.4		$	(6.5	)	(1.1	)%
Partnership EBITDA (b)	$	270.8		$	296.6		$	(25.8	)	(8.7	)%
Operating income (b)	$	246.2		$	255.9		$	(9.7	)	(3.8	)%
Retail gallons sold (millions)		572.7			596.6			(23.9	)	(4.0	)%
Degree days — % colder than normal (c)		0.1	%		0.6	%		—		—


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

(b)		Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 5 to condensed consolidated financial statements). Partnership EBITDA for the six months ended March 31, 2011 includes a pre-tax loss of $18.8 million associated with the early extinguishment of debt. Partnership EBITDA and operating income for the six months ended March 31, 2010 includes a pre-tax loss of $12.2 million associated with the discontinuance of interest rate hedges.

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

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UGI CORPORATION AND SUBSIDIARIES

Based upon heating degree-day data, average temperatures in the Partnership’s service territories were near normal for each of the six month periods ended March 31, 2011 and 2010. However, during the 2011 six-month period temperatures in the early fall were significantly warmer than normal and we experienced an early end to the heating season weather in our southern regions. Retail propane gallons sold declined principally due to the effects of these weather patterns, customer conservation and the impact on AmeriGas Propane’s prior-year volumes of a strong crop-drying season partially offset by volumes acquired through acquisitions.

Retail propane revenues increased $58.0 million during the 2011 six-month period reflecting higher average retail sales prices ($111.8 million) partially offset by lower retail volumes sold ($53.8 million). Wholesale propane revenues decreased $4.0 million principally reflecting lower wholesale volumes sold ($16.8 million) partially offset by higher wholesale selling prices ($12.8 million). Average wholesale propane prices at Mont Belvieu, Texas, a major supply location in the U.S., were approximately 14% higher during the 2011 six-month period compared with average wholesale propane prices during the 2010 six-month period. Other revenues from fee income and ancillary sales and services increased $10.3 million in the 2011 six-month period. Total cost of sales increased $70.8 million, to $1,000.1 million, principally reflecting the higher 2011 wholesale propane product costs.

Total margin was $6.5 million lower in the 2011 six-month period primarily due to lower total retail margin ($12.9 million) partially offset principally by an increase in margin from fee income. The lower total retail margin reflects the effects of the lower retail volumes sold ($22.1 million) partially offset by the effects of slightly higher average retail unit margins ($9.2 million).

The $25.8 million decrease in Partnership EBITDA during the 2011 six-month period primarily reflects (1) a loss on the early extinguishment of Partnership Senior Notes ($18.8 million); (2) higher operating and administrative expenses ($14.0 million); and (3) the previously mentioned decrease in 2011 six-month total margin ($6.5 million). The effects of these items on the change in Partnership EBITDA were partially offset by the absence of a $12.2 million loss recorded in the prior-year six-month period resulting from the discontinuance of interest rate hedges.

Operating income (which excludes the loss on early extinguishment of debt) decreased $9.7 million in the 2011 six-month period principally reflecting (1) higher operating and administrative and depreciation and amortization expenses ($16.6 million) and (2) the lower total margin ($6.5 million). These decreases in operating income were partially offset by the absence of the loss on interest rate hedges recorded in the prior year ($12.2 million). Partnership interest expense was $1.5 million lower in the 2011 six-month period principally reflecting lower interest expense on long-term debt outstanding partially offset by higher interest expense on working capital borrowings.

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UGI CORPORATION AND SUBSIDIARIES

International Propane:


							Increase
For the six months ended March 31,	2011			2010			(Decrease)
(Millions of euros) (a)
Revenues	€	698.2		€	487.2		€	211.0		43.3	%
Total margin (b)	€	242.5		€	227.9		€	14.6		6.4	%
Operating income	€	87.4	(c)	€	88.0		€	(0.6	)	(0.7	)%
Income before income taxes	€	77.7	(c)	€	78.9		€	(1.2	)	(1.5	)%

(Millions of dollars) (a)
Revenues	$	958.8		$	693.3		$	265.5		38.3	%
Total margin (b)	$	330.9		$	324.0		$	6.9		2.1	%
Operating income	$	115.8	(c)	$	124.7		$	(8.9	)	(7.1	)%
Income before income taxes	$	102.5	(c)	$	111.3		$	(8.8	)	(7.9	)%

Antargaz retail gallons sold		187.2			188.5			(1.3	)	(0.7	)%
Degree days — % colder than normal (d)		1.6	%		2.0	%		—		—
Flaga retail gallons sold		85.9			36.8			49.1		133.4	%
Flaga degree days — % colder (warmer) than normal (d)		2.8	%		(1.2	)%		—		—


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

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

(c)		Includes €7.1 million ($9.4 million) from a nontaxable reserve reversal at Antargaz associated with the French Competition Authority Matter (see Note 10 to condensed consolidated financial statements).

(d)		Deviation from average heating degree days for the 30-year period 1971-2000 at locations in our International Propane service territories.

Based upon heating degree-day data, temperatures in Antargaz’ service territory were about equal to the prior year while temperatures in Flaga’s service territory were slightly colder than the prior year. Notwithstanding the effects of higher LPG costs on customer conservation, Antargaz’ retail volumes sold were about equal to the prior-year six-month period while the significant increase in Flaga’s 2011 six-month period retail gallons sold reflects the effects of acquisitions made in late Fiscal 2010 and early Fiscal 2011. LPG wholesale product prices rose rapidly principally during the first-half of the 2011 six-month period compared with more gradual price increases during the prior-year six-month period. Based upon posted wholesale LPG prices in Northwest Europe, average propane costs were approximately 34% higher and average butane costs were approximately 30% higher than in the prior-year six-month period.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. During the 2011 six-month period, the average currency translation rate was $1.35 per euro compared to a rate of $1.41 per euro during the prior-year six-month period.

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UGI CORPORATION AND SUBSIDIARIES

International Propane euro base-currency revenues increased €211.0 million or 43.3% principally reflecting higher revenues from Antargaz (€111.3 million) and Flaga (€99.7 million). The increase in Antargaz revenues principally reflects the effects of (1) higher average retail prices (€63.9 million) and (2) higher wholesale revenues (€51.0 million). The higher Flaga revenues reflect the effects of late Fiscal 2010 and early Fiscal 2011 acquisitions and higher average retail prices. The higher average retail prices reflect the previously mentioned year-over-year increase in wholesale LPG product costs. In U.S. dollars, revenues increased $265.5 million or 38.3% principally reflecting the previously mentioned higher euro base-currency revenues. International Propane’s euro base-currency total cost of sales increased to €455.7 million in the 2011 six-month period from €259.3 million in the prior year principally reflecting (1) the higher LPG product costs and (2) the greater Flaga retail volumes sold and higher Antargaz wholesale volumes sold. On a U.S. dollar basis, cost of sales increased to $627.9 million from $369.3 million in the prior-year period principally reflecting the higher euro base-currency per unit commodity costs and the previously mentioned higher Flaga retail and Antargaz wholesale volumes sold.

International Propane euro-denominated total margin increased €14.6 million or 6.4% in the 2011 six-month period principally reflecting higher total margin from Flaga (€21.5 million) partially offset by lower total margin from Antargaz (€6.9 million). The increase in Flaga’s total margin reflects the impact of the acquisition-driven greater retail gallons sold. The decrease in Antargaz’ total margin principally reflects the effects of rapidly rising LPG product costs on unit margins primarily during the first quarter of Fiscal 2011. U.S dollar total margin increased $6.9 million or 2.1% principally reflecting the previously mentioned higher euro base-currency total margin partially offset by the effects of the stronger dollar.

International Propane euro base-currency operating income decreased €0.6 million principally reflecting the previously mentioned lower total margin at Antargaz (€6.9 million) offset by the reversal of the nontaxable reserve at Antargaz associated with the French Competition Authority Matter (€7.1 million). The higher euro base-currency total margin at Flaga (€21.5 million) was largely offset by higher operating, administrative and depreciation expenses (€22.8 million) associated with the acquired businesses. On a U.S. dollar basis, operating income decreased $8.9 million, notwithstanding euro base-currency operating income that was only slightly lower than last year, principally reflecting the effects of the stronger dollar in the 2011 six-month period. The decreases in euro-based and U.S. dollar-based income before income taxes largely reflects the previously mentioned lower operating income.

Gas Utility:


							Increase
For the six months ended March 31,	2011			2010			(Decrease)
(Millions of dollars)
Revenues	$	773.6		$	773.2		$	0.4	0.1	%
Total margin (a)	$	290.1		$	272.0		$	18.1	6.7	%
Operating income	$	176.0		$	154.8		$	21.2	13.7	%
Income before income taxes	$	155.7		$	134.3		$	21.4	15.9	%
System throughput — billions of cubic feet (“bcf”)		110.2			96.9			13.3	13.7	%
Degree days — % colder (warmer) than normal (b)		7.2	%		(0.9	)%		—	—


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

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

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UGI CORPORATION AND SUBSIDIARIES

Temperatures in the Gas Utility service territory based upon heating degree days were 7.2% colder than normal in the 2011 six-month period compared with temperatures that were 0.9% warmer than normal in the prior-year period. Total distribution system throughput increased 13.3 bcf reflecting higher throughput to certain low-margin interruptible delivery service customers, the effects of the colder weather on core market customers and the benefits of an improving economy.

Gas Utility revenues were about equal to the prior-year period principally reflecting a decline in revenues from core market customers ($34.9 million) partially offset by a $33.7 million increase in revenues from low-margin off-system sales. The decrease in core market revenues principally resulted from lower average PGC rates reflecting lower natural gas prices ($68.7 million) partially offset by the greater core market volumes. Gas Utility’s cost of gas was $483.5 million in the 2011 six-month period compared with $501.2 million in the prior-year period principally reflecting the lower average PGC rates offset in part by an increase in retail core-market sales.

Gas Utility total margin increased $18.1 million in the 2011 six-month period. The increase principally reflects a $16.1 million increase in core market margin reflecting the increase in core market throughput.

Gas Utility operating income during the 2011 six-month period increased $21.2 million principally reflecting the previously mentioned increase in total margin ($18.1 million) and higher other income ($2.7 million). The $21.4 million increase in income before income taxes reflects the previously mentioned increase in Gas Utility operating income ($21.2 million).

Electric Utility:


					Increase
For the six months ended March 31,	2011		2010		(Decrease)
(Millions of dollars)
Revenues	$	60.6	$	65.6	$	(5.0	)	(7.6	)%
Total margin (a)	$	18.4	$	19.7	$	(1.3	)	(6.6	)%
Operating income	$	6.6	$	8.5	$	(1.9	)	(22.4	)%
Income before income taxes	$	5.5	$	7.6	$	(2.1	)	(27.6	)%
Distribution sales — millions of kilowatt hours (“gwh”)		529.5		505.2		24.3		4.8	%


(a)		Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $3.4 million and $3.6 million during the six-month periods ended March 31, 2011 and 2010, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the Condensed Consolidated Statements of Income.

Electric Utility’s kilowatt-hour sales in the 2011 six-month period were 4.8% higher than in the prior-year six-month period on heating degree day weather that was 7.2% colder. Notwithstanding the effects of the colder weather, Electric Utility revenues decreased $5.0 million principally as a result of certain commercial and industrial customers switching to an alternate supplier for the electricity generation portion of their service and, to a much lesser extent, lower average default service (“DS”) rates compared to provider of last resort (“POLR”) rates in effect through December 31, 2009. Under DS rates, Electric Utility is no longer subject to electricity price and congestion cost risk as it is permitted to pass these costs through to its customers using a reconcilable cost recovery mechanism. Differences between actual costs and amounts recovered in DS rates are deferred for future recovery from or refund to customers. Beginning January 1, 2010, Electric Utility can no longer recover revenues in excess of actual costs of electricity as was possible under POLR rates. Electric Utility cost of sales declined to $38.8 million in the 2011 six-month period compared to $42.2 million in the 2010 six-month period principally reflecting the effects of the previously mentioned electricity generation supplier customer switching.

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Electric Utility total margin declined $1.3 million in the 2011 six-month period, notwithstanding the greater sales, principally reflecting the absence of margin from electric generation service beginning January 1, 2010.

Electric Utility 2011 six-month period operating income and income before income taxes declined $1.9 million and $2.1 million, respectively, principally reflecting the previously mentioned lower total margin and higher operating and maintenance expenses.

Midstream & Marketing:


For the six months ended March 31,	2011		2010		Decrease
(Millions of dollars)
Revenues	$	639.9	$	750.9	$	(111.0	)	(14.8	)%
Total margin (a)	$	94.4	$	97.3	$	(2.9	)	(3.0	)%
Operating income	$	68.3	$	68.5	$	(0.2	)	(0.3	)%
Income before income taxes	$	66.9	$	68.5	$	(1.6	)	(2.3	)%


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

Midstream & Marketing total revenues decreased $111.0 million in the 2011 six-month period principally reflecting (1) the absence of revenues from Atlantic Energy, LLC’s (“Atlantic Energy’s”) import and transshipment facility ($77.0 million); (2) lower total revenues from natural gas marketing activities ($56.4) reflecting lower natural gas prices; and, to a much lesser extent, (3) the absence of revenues from the Hunlock Creek electric generating station. These decreases in revenues were partially offset principally by an increase in retail power sales revenues ($20.9 million).

Total margin from Midstream & Marketing decreased $2.9 million in the 2011 six-month period principally reflecting lower electric generation total margin ($7.0 million) and the absence of margin from Atlantic Energy ($7.2 million). These reductions were substantially offset by higher winter peaking, retail power and asset management margin which in the aggregate totaled $10.8 million. The decrease in electric generation total margin principally reflects lower spot prices for electricity and the absence of margin from UGID’s Hunlock Creek coal-fired generating station which ceased operations in May 2010. The decrease in Midstream & Marketing’s operating income principally reflects the previously mentioned decrease in total margin ($2.9 million) substantially offset by lower current-year period operating and depreciation expenses of the Hunlock Creek coal-fired generating station and Atlantic Energy. The decline in income before income taxes reflects the decline in operating income ($0.2 million) and greater interest expense ($1.4 million), principally the result of the change in accounting for Energy Services’ Receivables Facility and fees and charges associated with Energy Services’ new credit agreement (see Notes 3 and 6 to condensed consolidated financial statements).

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

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

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

Our cash and cash equivalents, excluding cash in commodity futures brokerage accounts restricted from withdrawal, totaled $298.1 million at March 31, 2011 compared with $260.7 million at September 30, 2010. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at March 31, 2011 and September 30, 2010, UGI had $77.8 million and $111.6 million, respectively, of cash and cash equivalents.

The Company’s debt outstanding at March 31, 2011 totaled $2,288.1 million (including current maturities of long-term debt of $38.0 million and bank loan borrowings of $222.1 million) compared to debt outstanding at September 30, 2010 of $2,206.2 million (including current maturities of long-term debt of $573.6 million and bank loan borrowings of $200.4 million). Total debt outstanding at March 31, 2011 consists of (1) $1,028.9 million of Partnership debt; (2) $606.2 million (€427.7 million) of International Propane debt; (3) $640 million of UGI Utilities’ debt; and (4) $13.0 million of other debt. There was no debt outstanding associated with Midstream & Marketing at March 31, 2011. Long-term debt maturing in the next twelve months principally comprises $31.7 million (€22.4 million) of Flaga term loans.

AmeriGas Partners’ total debt at March 31, 2011 includes $820 million of AmeriGas Partners’ Senior Notes, $194 million of AmeriGas OLP bank loan borrowings and $14.9 million of other long-term debt. During the three months ended March 31, 2011, AmeriGas Partners issued $470 million principal amount of 6.50% Senior Notes due 2021. The proceeds from the issuance of the 6.50% Senior Notes were used to repay AmeriGas Partners’ $415 million 7.25% Senior Notes due May 15, 2015 pursuant to a January 5, 2011 tender offer and subsequent redemption. The 6.50% Senior Notes due 2021 rank pari passu with AmeriGas Partners’ outstanding senior debt. In addition, during the three months ended March 31, 2011, AmeriGas Partners redeemed $14.6 million principal amount of its 8.875% Senior Notes due May 2011. The Partnership incurred a loss on extinguishment of debt associated with these refinancings of $18.8 million, which reduced net income attributable to UGI Corporation by $5.2 million.

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International Propane’s total debt at March 31, 2011 includes $538.6 million (€380 million) outstanding under Antargaz’ Senior Facilities term loan and a combined $36.7 million (€25.9 million) outstanding under Flaga’s two term loans. Total International Propane debt outstanding at March 31, 2011 also includes combined borrowings of $26.2 million (€18.5 million) outstanding under Flaga GmbH’s working capital facilities and $4.7 million (€3.3 million) of other debt.

UGI Utilities’ total debt at March 31, 2011 includes $383 million of Senior Notes and $257 million of Medium-Term Notes. There were no amounts outstanding under UGI Utilities’ Revolving Credit Agreement at March 31, 2011.

AmeriGas Partners. In order to meet its short-term cash needs, AmeriGas OLP has a $200 million unsecured credit agreement (“Credit Agreement”) which expires on October 15, 2011. AmeriGas OLP also has a $75 million unsecured revolving credit facility (“2009 AmeriGas Supplemental Credit Agreement”) which expires on June 30, 2011. AmeriGas OLP expects to refinance these credit agreements during the third quarter of Fiscal 2011. AmeriGas OLP’s Credit Agreement consists of (1) a $125 million Revolving Credit Facility and (2) a $75 million Acquisition Facility. The Revolving Credit Facility may be used for working capital and general purposes of AmeriGas OLP. The Acquisition Facility provides AmeriGas OLP with the ability to borrow up to $75 million to finance the purchase of propane businesses or propane business assets or, to the extent it is not so used, for working capital and general purposes. The 2009 AmeriGas Supplemental Credit Agreement permits AmeriGas OLP to borrow up to $75 million for working capital and general purposes.

At March 31, 2011, there were $140 million of borrowings outstanding under the Credit Agreement and $54 million outstanding under the 2009 AmeriGas Supplemental Credit Agreement. Borrowings under the AmeriGas OLP credit agreements are classified as bank loans. Issued and outstanding letters of credit under the Revolving Credit Facility, which reduce the amount available for borrowings, totaled $35.7 million and $36.1 million at March 31, 2011 and 2010, respectively. AmeriGas OLP’s short-term borrowing needs are seasonal and are typically greatest during the fall and winter heating-season months due to the need to fund higher levels of working capital. The average daily and peak bank loan borrowings outstanding under the AmeriGas OLP credit agreements during the six months ended March 31, 2011 were $153.1 million and $235 million, respectively. The average daily and peak bank loan borrowings outstanding under AmeriGas OLP credit agreements during the three months ended March 31, 2010 were $25.5 million and $75 million, respectively. At March 31, 2011, AmeriGas OLP’s available borrowing capacity under the credit agreements was $45.3 million.

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

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

The 2011 Senior Facilities Agreement consists of (1) a €380 million variable-rate term loan and (2) a €40 million revolving credit facility. Scheduled maturities under the term loan are €38 million due May 2014, €34.2 million due May 2015, and €307.8 million due March 2016. Antargaz’ term loan and revolving credit facility bear interest at one-, two-, three- or six-month euribor, plus a margin, as defined by the 2011 Senior Facilities Agreement. The margin on the term loan and revolving credit facility borrowings (which ranges from 1.75% to 2.50%) is dependent upon the ratio of Antargaz’ total net debt to EBITDA, each as defined in the 2011 Senior Facilities Agreement. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of approximately 3.71% through the date of the term loan’s final maturity in March 2016. At March 31, 2011, the effective interest rate on Antargaz’ term loan was 4.75%.

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

Flaga GmbH currently has four working capital facilities providing for borrowings of up to €36 million. Flaga GmbH has two multi-currency working capital facilities that provide for borrowings and issuances of guarantees totaling €24 million. Flaga GmbH also has two euro-denominated working capital facilities that provide for borrowings and issuances of guarantees totaling €12 million. Total borrowings under these facilities were $26.2 million (€18.5 million) at March 31, 2011. Issued and outstanding guarantees, which reduce available borrowings under the working capital facilities, totaled $18.0 million (€12.7 million) at March 31, 2011. Amounts outstanding under the working capital facilities are classified as bank loans. During the 2011 six-month period, average and peak borrowings under the working capital facilities totaled €17.4 million and €23.4 million, respectively. During the 2010 six-month period, average and peak borrowings under the working capital facilities totaled €11.0 million and €15.7 million, respectively.

Scheduled repayments under Flaga GmbH’s two term loans during the remainder of Fiscal 2011 total €21.7 million ($30.8 million). Flaga expects to refinance its maturing term loans on a long-term basis prior to their maturity in August and September 2011 and to combine and extend its two euro-denominated working capital facilities and its two multi-currency working capital facilities prior to their scheduled expiration in June 2011.

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

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UGI Utilities. UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement which expires in August 2011. At March 31, 2011, there were no amounts outstanding under its Revolving Credit Agreement. Borrowings under the Revolving Credit Agreement are classified as bank loans. During the 2011 and 2010 six-month periods, average daily bank loan borrowings were $35.1 million and $136.8 million, respectively, and peak bank loan borrowings totaled $90 million and $239.8 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January when UGI Utilities’ investment in working capital, principally accounts receivable and inventories, is greatest. UGI Utilities expects to replace its Revolving Credit Agreement during the third quarter of Fiscal 2011 but reduce the available borrowings to $300 million due to decreases in natural gas prices.

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

Midstream & Marketing. Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $170 million (including a $50 million sublimit for letters of credit) which expires in August 2013. There were no borrowings under this facility during the six months ended March 31, 2011.

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

During the six months ended March 31, 2011 and 2010, Energy Services transferred trade receivables totaling $687.0 million and $714.8 million, respectively, to ESFC. During the six months ended March 31, 2011 and 2010, ESFC sold an aggregate $68.0 million and $225.6 million, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At March 31, 2011, the balance of ESFC receivables was $86.7 million and there were no amounts sold to the commercial paper conduit. At March 31, 2010, the outstanding balance of ESFC receivables was $104.8 million and there were no amounts sold to the commercial paper conduit. During the six months ended March 31, 2011 and 2010, peak amounts sold under the Receivables Facility were $31.7 million and $45.7 million, respectively, and average daily amounts sold were $2.1 million and $16.6 million, respectively.

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

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

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

Cash Flows

Due to the seasonal nature of the Company’s businesses, cash flows from operating activities are generally strongest during the second and third fiscal quarters when customers pay for natural gas, LPG, electricity and other energy products consumed during the peak heating season months. Conversely, operating cash flows are generally at their lowest levels during the fourth and first fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest.

Operating Activities. Cash flow provided by operating activities was $292.1 million in the 2011 six-month period compared to $304.3 million in the 2010 six-month period. Cash flow from operating activities before changes in operating working capital was $560.6 million in the 2011 six-month period compared to $584.7 million in the prior-year six-month period. Cash required to fund changes in operating working capital totaled $268.5 million in the 2011 six-month period compared to $280.4 million in the prior-year six-month period. The slightly higher cash required to fund changes in operating working capital reflects, among other things, lower increases in customer accounts receivable and higher cash from Gas Utility deferred fuel recoveries largely offset by the effects of the timing of payments and increased purchase price per gallon of LPG on accounts payable.

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Investing Activities. Cash flow used in investing activities was $185.3 million in the 2011 six-month period compared with $198.9 million of cash used in the prior-year period. Cash used for acquisitions of businesses in the 2011 six-month period was $44.6 million compared with only $9.7 million paid in the prior-year period reflecting payments associated with an acquisition at Flaga and greater Partnership business acquisition expenditures. Changes in restricted cash balances in margin accounts provided $25.2 million of cash in the 2011 six-month period compared with $31.9 million of cash required to fund such margin accounts in the prior-year period.

Financing Activities. Cash flow used in financing activities was $69.1 million in the 2011 six-month period compared with $106.5 million in the prior-year period. As previously mentioned, during the 2011 six-month period AmeriGas Partners redeemed its $415 million 7.25% Senior Notes due 2015 and its $14.6 million 8.875% Senior Notes due 2011 with proceeds from the issuance of $470 million of 6.50% AmeriGas Partners Senior Notes due 2021. In addition, Antargaz repaid its €380 million Senior Facilities Agreement with the proceeds from its new 2011 €380 million Senior Facilities Agreement due March 2016. As a result of the previously mentioned change in accounting for the Energy Services Receivables Facility effective October 1, 2010, net cash repayments of $12.1 million during the 2011 six-month period are reflected in financing activities cash flows.

CPG Base Rate Filing.

On January 14, 2011, CPG filed a request with the PUC to increase its base operating revenues by $16.5 million annually. The increased revenues would fund system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs that would provide rebates and other incentives for customers to install new high-efficiency equipment. CPG requested that the new gas rates become effective March 15, 2011. The PUC entered an Order dated March 17, 2011, suspending the effective date for the rate increase and setting the matter for investigation and public hearing. Unless a settlement is reached sooner, the PUC review process is expected to last approximately nine months which may delay implementation of the new rates until late October 2011.


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

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when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements and over-the-counter derivative commodity instruments including price swap and option contracts. In addition, Antargaz hedges a portion of its future U.S. dollar denominated LPG product purchases through the use of forward foreign exchange contracts as further described below. Antargaz has used over-the-counter derivative commodity instruments and may from time-to-time enter into other derivative contracts, similar to those used by the Partnership. Flaga has used and may use derivative commodity instruments to reduce market risk associated with a portion of its LPG purchases. Over-the-counter derivative commodity instruments used to hedge forecasted purchases of propane are generally settled at expiration of the contract.

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

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

Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at March 31, 2011 was not material.

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

In order to manage market price risk relating to substantially all of Midstream & Marketing’s fixed-price sales contracts for natural gas and electricity, Midstream & Marketing purchases over-the-counter as well as exchange-traded natural gas and electricity futures contracts or enters into fixed-price supply arrangements. Midstream & Marketing’s exchange-traded natural gas and electricity futures contracts are traded on the NYMEX and have nominal credit risk. Although Midstream & Marketing’s fixed-price supply

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

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

The fair value of unsettled commodity price risk sensitive derivative instruments held at March 31, 2011 (excluding those Gas Utility and Electric Utility commodity derivative instruments which are refundable to or recoverable from customers) was an asset of $3.4 million. A hypothetical 10% adverse change in (1) the market price of LPG and gasoline; (2) the market price of natural gas; and (3) the market price of electricity and electricity transmission congestion charges would result in a decrease in such fair value of $24.0 million at March 31, 2011.

Interest Rate Risk

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

Our variable-rate debt at March 31, 2011 includes borrowings under AmeriGas OLP’s credit agreements, Antargaz’ term loan and a substantial portion of Flaga’s debt. These debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has effectively fixed the underlying euribor interest rate on its variable-rate debt, and Flaga has fixed the underlying euribor interest rate on a substantial portion of its term loans, through their scheduled maturity dates through the use of interest rate swaps. At March 31, 2011 combined borrowings outstanding under these variable-rate debt agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled $222.1 million. Flaga expects to refinance its maturing term loans on a long-term basis prior to their maturity in August and September 2011.

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

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The fair value of unsettled interest rate risk sensitive derivative instruments held at March 31, 2011 was a gain of $12.8 million. A hypothetical 10% adverse change in the three-month LIBOR and the three-month euribor would result in a decrease in fair value of $10.0 million.

Foreign Currency Exchange Rate Risk

Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Realized gains or losses on net investment hedges remain in accumulated other comprehensive income until such foreign operations are liquidated. At March 31, 2011, the fair value of unsettled net investment hedges was a gain of $0.3 million. With respect to our net investments in our International Propane operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value by approximately $78.5 million, which amount would be reflected in other comprehensive income.

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

The fair value of unsettled foreign currency exchange rate risk sensitive derivative instruments held at March 31, 2011 was a liability of $3.7 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 $9.4 million.

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

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise major energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts which are guaranteed by the NYMEX generally require cash deposits in margin accounts. Declines in natural gas, LPG and electricity product costs can require our business units to post collateral with counterparties or make margin deposits to brokerage accounts. At March 31, 2011 and 2010, restricted cash in brokerage accounts totaled $9.6 million and $38.9 million, respectively.

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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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PART II OTHER INFORMATION


ITEM 1.		LEGAL PROCEEDINGS

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


ITEM 1A.		RISK FACTORS

In addition to the other information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended September 30, 2010, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.


ITEM 6.		EXHIBITS

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

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UGI CORPORATION AND SUBSIDIARIES

Incorporation by Reference

Exhibit

No.

Exhibit

Registrant

Filing

Exhibit

10.1

Senior Facilities Agreement dated March 16, 2011 by and among AGZ Holding, as Parent and Borrower, Antargaz, as Borrower, BNP Paribas, Caisse Régionale de Crédit Agricole Mutuel de Paris et d’Ile de France, Credit Lyonnais and Natixis, as Mandated Lead Arrangers and Bookrunners, Barclays Bank PLC, Banque Commerciale pour le Marché de l’Entreprise and ING Belgium SA, Succursale en France, as Mandated Lead Arrangers, Natixis, as Facility Agent and Security Agent, Banco Bilbao Vizcaya Argentaria, Crédit du Nord, HSBC France, Crédit Suisse International, Bred Banque Populaire and Banque Palatine, as Arrangers and the Financial Institutions named therein

10.2

Pledge of Financial Instruments Account relating to Financial Instruments held by AGZ Holding in Antargaz, dated March 16, 2011, by and among AGZ Holding, as Pledgor, Natixis, as Security Agent and Bank Account Holder, and the Lenders, as Beneficiaries

10.3

Pledge of Financial Instruments Account relating to Financial Instruments held by Antargaz in certain subsidiary companies, dated March 16, 2011, by and among Antargaz, as Pledgor, Natixis, as Security Agent and Bank Account Holder, and the Lenders, as Beneficiaries

10.4

Master Agreement for Assignment of Receivables dated March 16, 2011 between AGZ Holding, as Assignor, Natixis, as Security Agent, and the Beneficiaries

10.5

Master Agreement for Assignment of Receivables dated March 16, 2011 between Antargaz, as Assignor, Natixis, as Security Agent, and the Beneficiaries

10.6

First Demand Guarantee dated March 16, 2011 by UGI Corporation in favor of Natixis and the Lenders set forth in the Senior Facilities Agreement dated March 16, 2011

10.7

FTS-1 Service Agreement No. 46283 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004 between Columbia Gulf Transmission Company and UGI Utilities, Inc.

UGI Utilities

Form 10-Q (3/31/2011)

10.1

10.8

FTS Service Agreement No. 46284 dated November 1, 1993, as amended by that certain letter agreement dated May 5, 2004, between Columbia Transmission Corporation and UGI Utilities, Inc.

UGI Utilities

Form 10-Q (3/31/2011)

10.2

10.9

Letter Agreement dated May 5, 2004 Amending the FTS-1 Service Agreement No. 46283 and FTS Service Agreement No. 46284, each dated November 1, 1993

UGI Utilities

Form 10-Q (3/31/2011)

10.3

10.10

Amendment No. 10 dated as of April 21, 2011 to Receivables Purchase Agreement, dated as of November 30, 2001(as amended, supplemented or modified from time to time), by and among UGI Energy Services, Inc. as servicer, Energy Services Funding Corporation, as seller, Market Street Funding LLC, as issuer, and PNC Bank, National Association, as administrator.

UGI

Form 8-K (4/21/2011)

10.1

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UGI CORPORATION AND SUBSIDIARIES

Exhibit

No.

Exhibit

Registrant

Filing

Exhibit

10.11

Amendment No. 2, dated as of March 17, 2011, to the Credit Agreement dated as of April 17, 2009, among the Partnership, AmeriGas Propane, Inc., Petrolane Incorporated, Citizens Bank of Pennsylvania, JPMorgan Chase Bank N.A., and Wells Fargo Bank, N.A.

AmeriGas Partners

Form 8-K (3/17/2011)

10.1

10.12

Amendment No. 1, dated as of March 17, 2011, to the Credit Agreement dated as of November 6, 2006, among the Partnership, AmeriGas Propane, Inc., Petrolane Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities Inc and Credit Suisse Securities (USA) LLC., and Wells Fargo Bank, N.A.

AmeriGas Partners

Form 8-K (3/17/2011)

10.2

31.1

Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2011, 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 March 31, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101

The following financial statements from UGI Corporation and Subsidiaries’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets; (ii) the Condensed Consolidated Statements of Income; (iii) the Condensed Consolidated Statements of Cash Flows; and (iv) Notes to Condensed Consolidated Financial Statements, tagged as blocks of text.

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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: May 6, 2011	By:	/s/ Robert C. Flexon
		Robert C. Flexon
		Chief Financial Officer

Date: May 6, 2011	By:	/s/ Davinder Athwal
		Davinder Athwal
		Vice President — Accounting and Financial Control and Chief Risk Officer

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UGI CORPORATION AND SUBSIDIARIES

EXHIBIT INDEX


	10.1			Senior Facilities Agreement dated March 16, 2011 by and among AGZ Holding, Antargaz, BNP Paribas, Caisse Régionale de Crédit Agricole Mutuel de Paris et d’Ile de France, Credit Lyonnais and Natixis, Barclays Bank PLC, Banque Commerciale pour le Marché de l’Entreprise and ING Belgium SA, Succursale en France, Natixis, Banco Bilbao Vizcaya Argentaria, Crédit du Nord, HSBC France, Crédit Suisse International, Bred Banque Populaire and Banque Palatine,

	10.2			Pledge of Financial Instruments Account relating to Financial Instruments held by AGZ Holding in Antargaz, dated March 16, 2011, by and among AGZ Holding, as Pledgor, Natixis, as Security Agent and Bank Account Holder, and the Lenders, as Beneficiaries

	10.3			Pledge of Financial Instruments Account relating to Financial Instruments held by Antargaz in certain subsidiary companies, dated March 16, 2011, by and among Antargaz, as Pledgor, Natixis, as Security Agent and Bank Account Holder, and the Lenders, as Beneficiaries

	10.4			Master Agreement for Assignment of Receivables dated March 16, 2011 between AGZ Holding, as Assignor, Natixis, as Security Agent, and the Beneficiaries

	10.5			Master Agreement for Assignment of Receivables dated March 16, 2011 between Antargaz, as Assignor, Natixis, as Security Agent, and the Beneficiaries

	10.6			First Demand Guarantee dated March 16, 2011 by UGI Corporation in favor of Natixis and the Lenders set forth in the Senior Facilities Agreement dated March 16, 2011

	31.1			Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2011, 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 March 31, 2011, 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 March 31, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	101			The following financial statements from UGI Corporation and Subsidiaries’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, formatted in XBRL (Extensible Business Reporting Language): (i) the Condensed Consolidated Balance Sheets; (ii) the Condensed Consolidated Statements of Income; (iii) the Condensed Consolidated Statements of Cash Flows; and (iv) Notes to Condensed Consolidated Financial Statements, tagged as blocks of text.

TABLE OF CONTENTS

Item 2: Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 6. Exhibits

Exhibits

Exhibit 10.1 Exhibit 10.2 Exhibit 10.3 Exhibit 10.4 Exhibit 10.5 Exhibit 10.6 Exhibit 31.1 Exhibit 31.2 Exhibit 32

UGI 10-Q Quarter ended March 31, 2011

Exhibits