Edgar Filing: UGI CORP /PA/

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, 2009


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 o 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 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, 2009, there were 108,267,638 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, 2009, September 30, 2008 and March 31, 2008		1

Condensed Consolidated Statements of Income for the three and six months ended March 31, 2009 and 2008		2

Condensed Consolidated Statements of Cash Flows for the six months ended March 31, 2009 and 2008		3

Notes to Condensed Consolidated Financial Statements		4 - 33

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		34 - 55

Item 3. Quantitative and Qualitative Disclosures About Market Risk		55 - 58

Item 4. Controls and Procedures		59

Part II Other Information

Item 1. Legal Proceedings		60

Item 1A. Risk Factors		61

Item 4. Submission of Matters to a Vote of Security Holders		61

Item 6. Exhibits		62 - 63

Signatures		64

Exhibit 10.1
Exhibit 10.2
Exhibit 10.3
Exhibit 10.4
Exhibit 10.5
Exhibit 10.6
Exhibit 10.7
Exhibit 10.8
Exhibit 10.12
Exhibit 10.13
Exhibit 10.14
Exhibit 31.1
Exhibit 31.2
Exhibit 32

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Millions of dollars)


	March 31,			September 30,			March 31,
	2009			2008			2008
ASSETS
Current assets
Cash and cash equivalents	$	192.6		$	245.2		$	240.3
Restricted cash		145.9			70.3			1.4
Accounts receivable (less allowances for doubtful accounts of $71.4, $40.8 and $45.5, respectively)		767.6			488.0			1,010.1
Accrued utility revenues		51.4			20.8			63.6
Inventories		173.5			400.8			228.9
Deferred income taxes		56.4			27.5			11.6
Utility regulatory assets		61.0			16.0			—
Collateral deposits		11.9			17.8			—
Derivative financial instruments		7.4			12.7			53.6
Prepaid expenses and other current assets		31.9			39.5			24.8

Total current assets		1,499.6			1,338.6			1,634.3

Property, plant and equipment, at cost (less accumulated depreciation and amortization of $1,696.4, $1,515.1 and $1,457.5, respectively)		2,755.0			2,449.5			2,475.2

Goodwill		1,508.8			1,489.7			1,570.8
Intangible assets (less accumulated amortization of $95.7, $90.1 and $99.3, respectively)		159.5			155.0			178.9
Utility regulatory assets		112.6			91.4			91.2
Investments in equity investees		2.9			63.1			70.9
Other assets		98.4			97.7			106.2

Total assets	$	6,136.8		$	5,685.0		$	6,127.5


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	10.7		$	81.8		$	82.3
UGI Utilities bank loans		178.0			57.0			96.0
AmeriGas Propane bank loans		—			—			56.0
Other bank loans		16.9			79.4			10.3
Accounts payable		428.8			461.8			599.7
Derivative financial instruments		190.5			103.2			22.0
Other current liabilities		458.6			401.0			455.9

Total current liabilities		1,283.5			1,184.2			1,322.2

Long-term debt		2,057.9			1,987.3			2,047.7
Deferred income taxes		426.2			491.0			537.4
Deferred investment tax credits		5.9			6.0			6.2
Other noncurrent liabilities		569.2			439.6			409.9

Total liabilities		4,342.7			4,108.1			4,323.4

Commitments and contingencies (note 8)

Minority interests, principally in AmeriGas Partners		248.1			159.2			253.0

Common stockholders’ equity
Common Stock, without par value (authorized - 300,000,000 shares; issued - 115,261,294, 115,247,694 and 115,152,994 shares, respectively)		867.5			858.3			842.4
Retained earnings		862.3			630.9			663.0
Accumulated other comprehensive (loss) income		(130.2	)		(15.2	)		108.8

		1,599.6			1,474.0			1,614.2
Treasury stock, at cost		(53.6	)		(56.3	)		(63.1	)

Total common stockholders’ equity		1,546.0			1,417.7			1,551.1

Total liabilities and stockholders’ equity	$	6,136.8		$	5,685.0		$	6,127.5

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,
	2009			2008			2009			2008

Revenues	$	2,137.8		$	2,361.5		$	3,916.3		$	4,126.2

Costs and expenses:
Cost of sales (excluding depreciation shown below)		1,380.1			1,690.6			2,551.2			2,932.6
Operating and administrative expenses		335.6			316.7			648.6			603.4
Utility taxes other than income taxes		5.0			4.8			9.6			9.3
Depreciation and amortization		49.8			45.8			97.5			90.7
Other income, net		(7.5	)		(13.8	)		(54.8	)		(23.4	)

		1,763.0			2,044.1			3,252.1			3,612.6


Operating income		374.8			317.4			664.2			513.6
Loss from equity investees		(0.6	)		(0.7	)		(0.8	)		(1.4	)
Interest expense		(35.0	)		(36.1	)		(72.1	)		(72.2	)

Income before income taxes and minority interests		339.2			280.6			591.3			440.0
Income taxes		(97.4	)		(79.1	)		(165.6	)		(127.6	)
Minority interests, principally in AmeriGas Partners		(83.6	)		(75.4	)		(152.6	)		(106.3	)

Net income	$	158.2		$	126.1		$	273.1		$	206.1


Earnings per common share:
Basic	$	1.46		$	1.18		$	2.52		$	1.93


Diluted	$	1.45		$	1.17		$	2.50		$	1.90


Average common shares outstanding (millions):
Basic		108.408			107.116			108.303			107.053


Diluted		109.223			108.254			109.076			108.252


Dividends declared per common share	$	0.193		$	0.185		$	0.385		$	0.370

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,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	273.1		$	206.1
Reconcile to net cash from operating activities:
Depreciation and amortization		97.5			90.7
Minority interests, principally in AmeriGas Partners		152.6			106.3
Gain on sale of California storage facility		(39.9	)		—
Deferred income taxes, net		(16.7	)		(5.6	)
Provision for uncollectible accounts		35.6			22.3
Net change in settled accumulated other comprehensive income		(29.5	)		4.5
Other, net		(4.7	)		5.0
Net change in:
Accounts receivable and accrued utility revenues		(290.8	)		(594.7	)
Inventories		252.6			135.5
Deferred fuel costs		39.0			42.9
Accounts payable		(75.2	)		159.9
Other current assets		19.9			(9.0	)
Other current liabilities		29.1			(0.3	)

Net cash provided by operating activities		442.6			163.6


CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(138.8	)		(98.5	)
Acquisitions of businesses, net of cash acquired		(317.1	)		(0.8	)
Proceeds from sale of California storage facility		42.4			—
Decrease (increase) in restricted cash		(75.6	)		11.4
Other, net		2.5			3.0

Net cash used by investing activities		(486.6	)		(84.9	)


CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock		(41.6	)		(39.5	)
Distributions on AmeriGas Partners publicly held Common Units		(41.5	)		(39.5	)
Issuances of debt		108.1			20.3
Repayments of debt		(75.5	)		(9.4	)
Increase (decrease) in UGI Utilities bank loans		121.0			(94.0	)
Increase in AmeriGas Propane bank loans		—			56.0
Other bank loans (decrease) increase		(74.7	)		0.4
Issuances of UGI Common Stock		2.3			4.6

Net cash used by financing activities		(1.9	)		(101.1	)

EFFECT OF EXCHANGE RATE CHANGES ON CASH		(6.7	)		10.9


Cash and cash equivalents decrease	$	(52.6	)	$	(11.5	)


Cash and cash equivalents:
End of period	$	192.6		$	240.3
Beginning of period		245.2			251.8

Decrease	$	(52.6	)	$	(11.5	)

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)

Basis of Presentation

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

We conduct a national propane distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”) and its principal operating subsidiaries AmeriGas Propane, L.P. (“AmeriGas OLP”) and AmeriGas OLP’s subsidiary, AmeriGas Eagle Propane, L.P. (“Eagle OLP”). AmeriGas Partners, AmeriGas OLP and Eagle 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. AmeriGas OLP and Eagle OLP (collectively referred to as “the Operating Partnerships”) comprise the largest retail propane distribution business in the United States serving residential, commercial, industrial, motor fuel and agricultural customers from locations in 46 states. 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, 2009, the General Partner and its wholly owned subsidiary Petrolane Incorporated (“Petrolane”) collectively held a 1% general partner interest and 42.9% limited partner interest in AmeriGas Partners, and an effective 44.4% ownership interest in AmeriGas OLP and Eagle OLP. Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners Common Units (“Common Units”). The remaining 56.1% interest in AmeriGas Partners comprises 32,355,179 publicly held Common Units representing limited partner interests.

Our wholly owned subsidiary UGI Enterprises, Inc. (“Enterprises”) through subsidiaries (1) conducts an LPG distribution business in France; (2) conducts a wholly owned LPG distribution business and, prior to the purchase of the 50% equity interest it did not already own on January 29, 2009 (see Note 9) participated in an LPG joint-venture business (Zentraleuropa LPG Holding, “ZLH”) in central and eastern Europe (collectively, “Flaga”); and (3) participates in an LPG joint-venture business in the Nantong region of China. Our LPG distribution business in France is conducted through Antargaz, a subsidiary of AGZ Holding (“AGZ”), and its operating subsidiaries (collectively, “Antargaz”). We refer to our foreign operations collectively as “International Propane.”

Our natural gas and electric distribution utility businesses are conducted through our wholly owned subsidiary UGI Utilities, Inc. and its subsidiaries UGI Penn Natural Gas, Inc. (“UGIPNG”) and UGI Central Penn Gas, Inc (“CPG”). UGI Utilities, UGIPNG 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, Inc.’s natural gas distribution utility is referred to herein as “UGI Gas;” UGIPNG’s natural gas distribution utility is referred to herein as “PNG Gas;” and CPG’s natural gas distribution utility, which was acquired on October 1, 2008 (see Note 9), is referred to herein 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.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Through other subsidiaries, Enterprises also conducts an energy marketing business primarily in the eastern United States (collectively, “Energy Services”). Energy Services’ wholly owned subsidiary, UGI Development Company (“UGID”), owns and operates a 48-megawatt coal-fired electric generation station located in northeastern Pennsylvania and owns an approximate 6% interest in a 1,711-megawatt coal-fired electric generation station located in western Pennsylvania. UGID recently completed construction of an 11-megawatt landfill gas powered electricity generation facility in eastern Pennsylvania. In addition, Energy Services’ wholly owned subsidiary UGI Asset Management, Inc., through its subsidiary Atlantic Energy, Inc. (collectively, “Asset Management”), owns a propane storage terminal located in Chesapeake, Virginia. Through other Enterprises’ subsidiaries, we own and operate heating, ventilation, air-conditioning, refrigeration and electrical contracting services businesses in the Middle Atlantic states (“HVAC/R”).

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 interest in a subsidiary of Antargaz as minority 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, 2008 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. 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, 2008 (“Company’s 2008 Annual Report”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

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

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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


	Three Months Ended				Six Months Ended
	March 31,				March 31,
	2009		2008		2009		2008
Denominator (millions of shares):
Average common shares outstanding for basic computation		108.408		107.116		108.303		107.053
Incremental shares issuable for stock options and awards		0.815		1.138		0.773		1.199

Average common shares outstanding for diluted computation		109.223		108.254		109.076		108.252

Comprehensive Income. The following table presents the components of comprehensive income for the three and six months ended March 31, 2009 and 2008:


	Three Months Ended					Six Months Ended
	March 31,					March 31,
	2009			2008		2009			2008
Net income	$	158.2		$	126.1	$	273.1		$	206.1
Other comprehensive (loss) income		(8.5	)		31.6		(115.0	)		51.1

Comprehensive income	$	149.7		$	157.7	$	158.1		$	257.2

Other comprehensive (loss) income principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges principally commodity instruments, interest rate protection agreements, interest rate swaps and foreign currency derivatives, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans; and (3) foreign currency translation adjustments. In addition, effective December 31, 2008, UGI Utilities merged two of the defined benefit pension plans that it sponsors. In accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 87, “Employers’ Accounting for Pensions” (“SFAS 87”), we were required to remeasure the merged plan’s assets and obligations and, in accordance with SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106 and 132(R)” (“SFAS 158”), record the funded status at December 31, 2008 (the “Remeasurement Date”) in our Condensed Consolidated Balance Sheet. The remeasurement resulted in an increase in other comprehensive loss of $38.7 during the three months ended December 31, 2008 (see Note 7). The significant increase in other comprehensive loss for the six months ended March 31, 2009 also reflects the effects of declining LPG and natural gas prices on derivative commodity financial instruments.

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

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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

Newly Adopted Accounting Standards. Effective March 31, 2009, we adopted the provisions of SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS 161”). SFAS 161 requires enhanced disclosures for all derivative instruments and hedging activity accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). SFAS 161 provides greater transparency by requiring disclosure regarding: (1) how and why an entity uses derivatives, (2) how derivatives and related hedged items are accounted for under SFAS 133 and its related interpretations, and (3) how derivatives and related hedged items affect an entity’s financial position, financial performance and cash flows. See Note 11 for disclosures required by SFAS 161.

Effective October 1, 2008, we adopted the provisions of SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. In February 2008, the Financial Accounting Standards Board (“FASB”) issued two FASB Staff Positions (“FSPs”) amending SFAS 157. FSP FAS 157-1 amends SFAS 157 to exclude SFAS No. 13, “Accounting for Leases,” and its related interpretive accounting pronouncements that address leasing transactions. FSP FAS 157-2 delays the effective date of SFAS 157 until fiscal years beginning after November 15, 2008 (Fiscal 2010) for non-financial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a non-recurring basis. The adoption of the initial phase of SFAS 157 did not have a material effect on the Company’s financial statements and the Company does not anticipate that the adoption of the remainder of SFAS 157 will have a material effect on the Company’s consolidated financial statements. In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” which clarifies the application of SFAS 157 to financial assets in a market that is not active. FSP 157-3 did not have an impact on our results of operations or financial condition. See Note 6 for further information on fair value measurements in accordance with SFAS 157.

Effective October 1, 2008, we adopted FSP FIN 39-1, “Amendment of FASB Interpretation No. 39” (“FSP 39-1”). FSP 39-1 permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. In addition, upon the adoption, companies are permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting arrangements. FSP 39-1 requires retrospective application for all periods presented. We have elected to continue our policy of reflecting derivative asset or liability positions, as well as cash collateral, on a gross basis in our Condensed Consolidated Balance Sheets. Accordingly, the adoption of FSP 39-1 did not impact our 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)

Also effective October 1, 2008, we adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). Under SFAS 159, we may elect to report individual financial instruments and certain items at fair value with changes in fair value reported in earnings. Once made, this election is irrevocable for those items. The adoption of SFAS 159 did not impact our financial statements.

Recently Issued Accounting Standards Not Yet Adopted. In April 2009, the FASB issued FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP 157-4”). FSP 157-4 provides additional guidance for estimating fair value in accordance with SFAS 157 when the volume and level of activity for the asset or liability have significantly decreased. FSP 157-4 is effective for interim and annual periods ending after June 15, 2009. We are currently evaluating the provisions of FSP 157-4.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures About Fair Value of Financial Instruments” (“FSP 107-1 and 28-1”). FSP 107-1 and 28-1 amends SFAS No. 107, “Disclosures About Fair Value of Financial Instruments,” to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. FSP 107-1 and 28-1 is effective for interim periods ending after June 15, 2009. We are currently evaluating the provisions of FSP 107-1 and 28-1.

Also in April 2009, the FASB issued FSP FAS 115-2 and 124-2, “Recognition and Presentations of Other-Than-Temporary Impairments” (“FSP 115-2 and 124-2”). FSP 115-2 and 124-2 amends other-than-temporary impairment guidance in U.S. GAAP for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. The FSP does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. FSP 115-2 and 124-2 is effective for interim and annual reporting periods ending after June 15, 2009. We are currently evaluating the provisions of FSP 115-2 and 124-2.

In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” which amends Statement 132(R) to require more detailed disclosures about employers’ plan assets, including employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets, and valuation techniques used to measure the fair value of plan assets. The provisions of this FSP are effective for reporting periods ending after December 15, 2009. We are currently evaluating the provisions of FSP 132(R)-1.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

In April 2008, the FASB issued FSP FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP 142-3”). FSP 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). The intent of FSP 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”), and other applicable accounting literature. FSP 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 (Fiscal 2010) and must be applied prospectively to intangible assets acquired after the effective date. We are currently evaluating the provisions of FSP 142-3.

In December 2007, the FASB issued SFAS 141R, “Business Combinations.” SFAS 141R applies to all transactions or other events in which an entity obtains control of one or more businesses. SFAS 141R establishes, among other things, principles and requirements for how the acquirer (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in a business combination or gain from a bargain purchase; and (3) determines what information with respect to a business combination should be disclosed. SFAS 141R applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008 (Fiscal 2010). Among the more significant changes in accounting for acquisitions are (1) transaction costs will generally be expensed (rather than being included as costs of the acquisition); (2) contingencies, including contingent consideration, will generally be recorded at fair value with subsequent adjustments recognized in operations (rather than as adjustments to the purchase price); and (3) decreases in valuation allowances on acquired deferred tax assets will be recognized in operations (rather than decreases in goodwill). Generally, the effects of SFAS 141R will depend on future acquisitions.

Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS 160”). SFAS 160 is effective for us on October 1, 2009 (Fiscal 2010). This standard will significantly change the accounting and reporting relating to noncontrolling interests in a consolidated subsidiary. After adoption, noncontrolling interests ($248.1, $159.2 and $253.0 at March 31, 2009, September 30, 2008 and March 31, 2008, respectively) will be classified as stockholders’ equity, a change from its current classification as minority interests between liabilities and stockholders’ equity. Earnings attributable to minority interests ($83.6 and $152.6 in the three and six months ended March 31, 2009 and $75.4 and $106.3 in the three and six months ended March 31, 2008, respectively) will be included in net income, although such income will continue to be deducted to measure earnings per share. In addition, changes in a parent’s ownership interest while retaining control will be accounted for as equity transactions and any retained noncontrolling equity investments in a former subsidiary will be initially measured at fair value.

- 9 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Intangible Assets

The Company’s intangible assets comprise the following:


	March 31,			September 30,			March 31,
	2009			2008			2008
Goodwill (not subject to amortization)	$	1,508.8		$	1,489.7		$	1,570.8


Other intangible assets:
Customer relationships, noncompete agreements and other	$	210.1		$	197.3		$	224.6
Trademark (not subject to amortization)		45.1			47.8			53.6

Gross carrying amount		255.2			245.1			278.2
Accumulated amortization		(95.7	)		(90.1	)		(99.3	)

Net carrying amount	$	159.5		$	155.0		$	178.9

The increase in goodwill and other intangible assets during the six months ended March 31, 2009 principally reflects the effects of acquisitions and capital expenditures offset by the effect of the stronger dollar on International Propane balances. Amortization expense of intangible assets was $4.5 and $8.9 for the three and six months ended March 31, 2009, respectively, and $4.7 and $9.3 for the three and six months ended March 31, 2008. 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 2009 — $17.0; Fiscal 2010 — $15.5; Fiscal 2011 — $15.0; Fiscal 2012 — $14.9; Fiscal 2013 — $14.3.

Segment Information

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

The accounting policies of the six segments disclosed are the same as those described in Note 1, “Organization and Significant Accounting Policies,” in the Company’s 2008 Annual Report. Beginning in January 2009 as a result of the purchase of the 50% equity interest in ZLH the Company did not already own, the results of ZLH have been consolidated with those of the Company. Previously, ZLH’s results were accounted for on the equity method. 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) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. We evaluate the performance of our International Propane, Gas Utility, Electric Utility and Energy Services segments principally based upon their income before income taxes.

- 10 -

UGI CORPORATION AND SUBSIDIARIES

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

Segment Information (continued)

Three Months Ended March 31, 2009:


							Reportable Segments
							AmeriGas			Gas			Electric			Energy		International Propane						Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other (a)			& Other (b)
Revenues	$	2,137.8		$	(50.8	)	$	823.3		$	542.8		$	38.1		$	424.6	$	301.0		$	37.6		$	21.2


Cost of sales	$	1,380.1		$	(49.6	)	$	474.0		$	392.9		$	24.2		$	375.2	$	131.4		$	20.1		$	11.9


Segment profit:
Operating income (loss)	$	374.8		$	0.1		$	168.1		$	80.0		$	5.5		$	33.2	$	84.6		$	5.1		$	(1.8	)
Loss from equity investees		(0.6	)		—			—			—			—			—		(0.4	)		(0.2	)		—
Interest expense		(35.0	)		—			(17.8	)		(10.4	)		(0.4	)		—		(5.8	)		(0.6	)		—
Minority interests		(83.6	)		—			(82.9	)		—			—			—		(0.7	)		—			—

Income (loss) before income taxes	$	255.6		$	0.1		$	67.4		$	69.6		$	5.1		$	33.2	$	77.7		$	4.3		$	(1.8	)

Depreciation and amortization	$	49.8		$	(0.1	)	$	20.9		$	11.6		$	0.9		$	2.1	$	11.5		$	2.6		$	0.3
Partnership EBITDA (c)							$	187.3

Segment assets (at period end)	$	6,136.8		$	(381.9	)	$	1,733.9		$	2,020.1		$	124.2		$	362.4	$	1,607.4		$	235.7		$	435.0


Investments in equity investees (at period end)	$	2.9		$	—		$	—		$	—		$	—		$	—	$	—		$	2.9		$	—


Goodwill (at period end)	$	1,508.8		$	(3.9	)	$	665.7		$	177.1		$	—		$	11.8	$	587.3		$	63.9		$	6.9

Three Months Ended March 31, 2008:


							Reportable Segments
							AmeriGas			Gas			Electric			Energy		International Propane						Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other (a)			& Other (b)
Revenues	$	2,361.5		$	(66.6	)	$	1,006.6		$	476.7		$	38.6		$	507.2	$	356.7		$	18.3		$	24.0


Cost of sales	$	1,690.6		$	(62.8	)	$	676.0		$	355.1		$	24.2		$	467.9	$	206.0		$	11.1		$	13.1


Segment profit:
Operating income	$	317.4		$	0.1		$	153.2		$	75.5		$	6.5		$	27.6	$	52.8		$	2.0		$	(0.3	)
Loss from equity investees		(0.7	)		—			—			—			—			—		(0.3	)		(0.4	)		—
Interest expense		(36.1	)		—			(18.7	)		(9.5	)		(0.6	)		—		(6.7	)		(0.6	)		—
Minority interests		(75.4	)		—			(74.7	)		—			—			—		(0.7	)		—			—

Income (loss) before income taxes	$	205.2		$	0.1		$	59.8		$	66.0		$	5.9		$	27.6	$	45.1		$	1.0		$	(0.3	)

Depreciation and amortization	$	45.8		$	0.1		$	20.1		$	9.5		$	0.9		$	1.8	$	12.4		$	1.0		$	—
Partnership EBITDA (c)							$	171.8

Segment assets (at period end)	$	6,127.5		$	(353.4	)	$	1,823.7		$	1,603.7		$	120.4		$	379.2	$	1,906.7		$	221.4		$	425.8


Investments in equity investees (at period end)	$	70.9		$	—		$	—		$	—		$	—		$	—	$	—		$	70.9		$	—


Goodwill (at period end)	$	1,570.8		$	(4.0	)	$	644.5		$	162.3		$	—		$	11.8	$	697.9		$	51.3		$	7.0


(a)		International Propane-Other principally comprises Flaga, including its central and eastern European joint-venture business ZLH prior to its consolidation, and our joint-venture business in China. In January 2009, Flaga purchased the 50% interest in ZLH it did not already own.

(b)		Corporate & Other results principally comprise HVAC/R operations, net expenses of UGI’s captive general liability insurance company and UGI Corporation’s unallocated corporate and general expenses, and interest income. Corporate & Other assets principally comprise cash, short-term investments and an intercompany loan. The intercompany interest associated with the intercompany loan is removed in the segment presentation.

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


Three months ended March 31,	2009			2008

Partnership EBITDA	$	187.3		$	171.8
Depreciation and amortization		(20.9	)		(20.1	)
Minority interests (i)		1.7			1.5

Operating income	$	168.1		$	153.2


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

- 11 -

UGI CORPORATION AND SUBSIDIARIES

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

Segment Information (continued)

Six Months Ended March 31, 2009:


							Reportable Segments
							AmeriGas			Gas			Electric			Energy		International Propane						Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other (a)			& Other (b)
Revenues	$	3,916.3		$	(106.8	)	$	1,550.4		$	953.2		$	74.0		$	783.7	$	565.8		$	49.9		$	46.1


Cost of sales	$	2,551.2		$	(104.3	)	$	919.5		$	685.9		$	47.4		$	701.9	$	248.1		$	26.8		$	25.9


Segment profit:
Operating income (loss)	$	664.2		$	0.1		$	312.8		$	136.9		$	10.5		$	51.4	$	148.0		$	5.8		$	(1.3	)
Loss from equity investees		(0.8	)		—			—			—			—			—		(0.7	)		(0.1	)		—
Interest expense		(72.1	)		—			(36.5	)		(21.4	)		(0.8	)		—		(12.1	)		(1.1	)		(0.2	)
Minority interests		(152.6	)		—			(152.3	)		—			—			—		(0.3	)		—			—

Income (loss) before income taxes	$	438.7		$	0.1		$	124.0		$	115.5		$	9.7		$	51.4	$	134.9		$	4.6		$	(1.5	)

Depreciation and amortization	$	97.5		$	(0.2	)	$	41.7		$	23.1		$	1.9		$	3.9	$	22.9		$	3.5		$	0.7
Partnership EBITDA (c)							$	351.4

Segment assets (at period end)	$	6,136.8		$	(381.9	)	$	1,733.9		$	2,020.1		$	124.2		$	362.4	$	1,607.4		$	235.7		$	435.0


Investments in equity investees (at period end)	$	2.9		$	—		$	—		$	—		$	—		$	—	$	—		$	2.9		$	—


Goodwill (at period end)	$	1,508.8		$	(3.9	)	$	665.7		$	177.1		$	—		$	11.8	$	587.3		$	63.9		$	6.9

Six Months Ended March 31, 2008:


							Reportable Segments
							AmeriGas			Gas			Electric			Energy		International Propane						Corporate
	Total			Elims.			Propane			Utility			Utility			Services		Antargaz			Other (a)			& Other (b)
Revenues	$	4,126.2		$	(125.3	)	$	1,754.8		$	803.4		$	70.5		$	872.5	$	669.8		$	33.6		$	46.9


Cost of sales	$	2,932.6		$	(120.3	)	$	1,182.3		$	591.9		$	41.9		$	799.3	$	392.1		$	19.8		$	25.6


Segment profit:
Operating income	$	513.6		$	(0.1	)	$	227.2		$	125.6		$	13.9		$	51.3	$	90.5		$	3.4		$	1.8
Loss from equity investees		(1.4	)		—			—			—			—			—		(0.5	)		(0.9	)		—
Interest expense		(72.2	)		—			(36.9	)		(19.9	)		(1.1	)		—		(13.0	)		(1.3	)		—
Minority interests		(106.3	)		—			(105.2	)		—			—			—		(1.1	)		—			—

Income before income taxes	$	333.7		$	(0.1	)	$	85.1		$	105.7		$	12.8		$	51.3	$	75.9		$	1.2		$	1.8

Depreciation and amortization	$	90.7		$	—		$	39.9		$	18.8		$	1.8		$	3.5	$	24.3		$	2.0		$	0.4
Partnership EBITDA (c)							$	264.8

Segment assets (at period end)	$	6,127.5		$	(353.4	)	$	1,823.7		$	1,603.7		$	120.4		$	379.2	$	1,906.7		$	221.4		$	425.8


Investments in equity investees (at period end)	$	70.9		$	—		$	—		$	—		$	—		$	—	$	—		$	70.9		$	—


Goodwill (at period end)	$	1,570.8		$	(4.0	)	$	644.5		$	162.3		$	—		$	11.8	$	697.9		$	51.3		$	7.0


(a)		International Propane-Other principally comprises Flaga, including its central and eastern European joint-venture business ZLH prior to its consolidation, and our joint-venture business in China. In January 2009, Flaga purchased the 50% interest in ZLH it did not already own.

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

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


Six months ended March 31,	2009			2008

Partnership EBITDA	$	351.4		$	264.8
Depreciation and amortization		(41.7	)		(39.9	)
Minority interests (i)		3.1			2.3

Operating income	$	312.8		$	227.2


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

- 12 -

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

In April 2009, Energy Services renewed its $200 receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper. The Receivables Facility is currently scheduled to expire in April 2010, although the Receivables Facility may terminate prior to such date due to the termination of commitments of the Receivables Facility back-up purchasers.

During the six months ended March 31, 2009 and 2008, Energy Services sold trade receivables totaling $785.1 and $767.3, respectively, to ESFC. During the six months ended March 31, 2009 and 2008, ESFC sold an aggregate $384.0 and $95.5, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At March 31, 2009, the outstanding balance of ESFC trade receivables was $36.0 which is net of $87.6 that was sold to the commercial paper conduit and removed from the balance sheet. At March 31, 2008, the outstanding balance of ESFC trade receivables was $156.3 and there was no amount sold to the commercial paper conduit.

- 13 -

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 6 to the Company’s 2008 Annual Report. 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,
	2009		2008		2008
Regulatory assets:
Income taxes recoverable	$	75.6	$	73.7	$	73.1
Postretirement benefits		3.6		4.3		4.5
Recoverable costs — CPG Gas postretirement benefit plans		5.5		—		—
Environmental costs		20.7		9.0		9.0
Deferred fuel costs		61.0		16.0		—
Other		7.2		4.4		4.6

Total regulatory assets	$	173.6	$	107.4	$	91.2

Regulatory liabilities:
Postretirement benefits	$	9.6	$	8.9	$	8.1
Environmental overcollections		9.7		—		—
Deferred fuel refunds		4.7		—		68.2

Total regulatory liabilities	$	24.0	$	8.9	$	76.3

Deferred fuel costs and refunds. Gas Utility’s tariffs contain clauses which permit recovery of certain purchased gas costs through the application of purchased gas cost (“PGC”) rates. The clauses provide for periodic adjustments to PGC rates for differences between the total amount of purchased gas costs collected from customers and recoverable costs incurred. Net undercollected gas costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability. Gas Utility uses derivative financial instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel refunds or costs. Unrealized (losses) gains on such contracts at March 31, 2009, September 30, 2008 and March 31, 2008 were $(81.9), $(23.3) and $39.5, respectively.

Recoverable costs — CPG Gas postretirement benefit plans. This regulatory asset represents the portion of prior service cost and net actuarial losses that will be recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with SFAS 158. These costs are amortized over the average remaining life expectancy of the plan participants.

Environmental overcollections. Environmental overcollections represents the difference between the amounts recovered in rates and actual costs incurred (net of insurance proceeds) associated with the terms of a consent order agreement between CPG Gas and the Pennsylvania Department of Environmental Protection to remediate certain gas plant sites.

UGI Utilities does not recover a rate of return on its regulatory assets.

- 14 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Other Regulatory Matters

Electric Utility. As a result of Pennsylvania’s Electricity Generation Customer Choice and Competition Act that became effective January 1, 1997, all of Electric Utility’s customers are permitted to acquire their electricity from entities other than Electric Utility. Electric Utility remains the provider of last resort (“POLR”) for its customers that are not served by an alternate electric generation provider. The terms and conditions under which Electric Utility provides POLR service, and rules governing the rates that may be charged for such service through December 31, 2009, were established in a series of PUC approved settlements (collectively, the “POLR Settlement”), the latest of which became effective June 23, 2006.

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

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

UGIPNG and CPG Base Rate Filings. On January 28, 2009, UGIPNG and CPG filed separate requests with the PUC to increase base rates for natural gas delivery service by $38.1 annually for UGIPNG and $19.6 annually for CPG. The increased rates would fund system improvements and operations necessary to maintain safe and reliable natural gas service. The increase would also fund additional energy assistance for low income customers as well as energy conservation programs for all customers. The PUC has suspended the effective date for the base rate increases to allow for investigation and public hearings. Unless a settlement is reached sooner, the PUC review process will last until late October 2009. As a condition to the PUC’s approval of the acquisition of CPG by UGI Utilities, CPG agreed not to place new base rates into effect prior to August 21, 2009.

Fair Value Measurement

As described in Note 1, the Company adopted SFAS 157 effective October 1, 2008. SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. SFAS 157 clarifies that the fair value should be based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. SFAS 157 requires fair value measurements to assume that the transaction occurs in the principal market for the asset or liability or in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We apply fair value measurements to certain assets and liabilities principally commodity, foreign currency and interest rate derivative instruments. We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

- 15 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

In accordance with SFAS 157, we maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based upon actively-quoted market prices, if available. In the absence of actively-quoted market prices, we seek price information from external sources, including counterparty quotes and prices for similar instruments in active markets. If pricing information from external sources is not available, or if we believe that observable pricing is not indicative of fair value, judgment is required to develop estimates of fair value.

For derivative contracts where observable pricing information is not available from external sources for the specific commodity or location, we may determine fair value using a different commodity or delivery location and adjust such prices using spread approximation models, or we may use recent market price indicators and adjust such prices using historical price movements.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

•

Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Instruments categorized in Level 1 consist of our exchange-traded commodity futures contracts.

•

Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over the counter commodity price swaps, interest rate swaps and interest rate protection agreements, foreign currency forward contracts and financial transmission rights (“FTRs”).

•

Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. The Company did not have any derivative financial instruments categorized as Level 3 at March 31, 2009.

- 16 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

SFAS 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy. The following table presents our assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions as of March 31, 2009:


	Level 1			Level 2			Level 3		Total
Derivative financial instruments:
Assets	$	0.8		$	11.9		$	—	$	12.7
Liabilities	$	(131.3	)	$	(105.9	)	$	—	$	(237.2	)

Defined Benefit Pension and Other Postretirement Plans

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

- 17 -

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,
	2009			2008			2009			2008
Service cost	$	1.8		$	1.5		$	0.1		$	0.1
Interest cost		5.8			4.9			0.2			0.2
Expected return on assets		(6.4	)		(6.2	)		(0.1	)		(0.1	)
Amortization of:
Transition obligation		—			—			0.1			—
Prior service (benefit) cost		—			—			(0.1	)		0.1
Actuarial loss (gain)		1.3			0.1			(0.1	)		(0.1	)

Net benefit cost		2.5			0.3			0.1			0.2
Change in associated regulatory liabilities		—			—			0.8			0.7

Net expense	$	2.5		$	0.3		$	0.9		$	0.9


							Other
	Pension Benefits						Postretirement Benefits
	Six Months Ended						Six Months Ended
	March 31,						March 31,
	2009			2008			2009			2008
Service cost	$	3.4		$	3.0		$	0.2		$	0.2
Interest cost		11.8			9.8			0.5			0.5
Expected return on assets		(12.9	)		(12.3	)		(0.3	)		(0.3	)
Amortization of:
Transition obligation		—			—			0.1			0.2
Prior service benefit		—			—			(0.2	)		(0.2	)
Actuarial loss		1.5			0.1			—			—

Net benefit cost		3.8			0.6			0.3			0.4
Change in associated regulatory liabilities		—			—			1.6			1.5

Net expense	$	3.8		$	0.6		$	1.9		$	1.9

Pension Plans assets are held in trust and consist principally of equity and fixed income mutual funds. The Company does not believe it will be required to make any material contributions to the Pension Plans during Fiscal 2009 for ERISA funding purposes.

During the six months ended March 31, 2009, Antargaz made a €4.1 contribution to one of its defined benefit pension plans. Antargaz does not expect to make any additional material contributions to fund its pension or other postretirement benefits during Fiscal 2009.

Pursuant to orders previously issued by the PUC, UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to fund and pay UGI Gas and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” The difference between the annual amount calculated and the amount included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the six months ended March 31, 2009, nor are they expected to be material for all of Fiscal 2009.

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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 also sponsor unfunded and non-qualified defined benefit supplemental executive retirement income plans. We recorded pre-tax expense associated with these plans of $0.6 and $1.6 for the three and six months ended March 31, 2009, respectively. We recorded pre-tax expense for these plans of $1.2 and $1.8 for the three and six months ended March 31, 2008, respectively.

Effective December 31, 2008, the Company merged two of its domestic defined benefit pension plans. The merged plan will maintain separate benefit formulas and specific rights and features of each predecessor plan. As a result of the merger, in accordance with SFAS 87 the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2008 and in accordance with SFAS 158 recorded an after-tax charge to accumulated other comprehensive loss of $38.7.

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 the Remeasurement Date:


	Three Months
	Ended
	December 31, 2008
Change in benefit obligations:
Benefit obligations — October 1, 2008	$	300.6
Service cost		1.3
Interest cost		5.1
Actuarial loss		35.4
Benefits paid		(3.7	)

Benefit obligations — December 31, 2008	$	338.7


Change in plan assets:
Fair value of plan assets — October 1, 2008	$	241.0
Actual loss on assets		(27.3	)
Benefits paid		(3.7	)

Fair value of plan assets — December 31, 2008	$	210.0


Funded status of the merged plan — December 31, 2008	$	(128.7	)


Liabilities recorded in the balance sheet:
Unfunded liabilities (included in other noncurrent liabilities)	$	(128.7	)

Amounts recorded in stockholders’ equity — December 31, 2008:
Prior service cost	$	0.3
Net actuarial loss		132.9

Total	$	133.2

The accumulated benefit obligation (“ABO”) of the merged plan at the Remeasurement Date is $301.5. Actuarial assumptions for the merged plan as of the Remeasurement Date are as follows: discount rate — 5.9%; 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)

Commitments and Contingencies

On August 21, 2001, AmeriGas Partners, through AmeriGas OLP, acquired the propane distribution businesses of Columbia Energy Group (the “2001 Acquisition”) pursuant to the terms of a purchase agreement (the “2001 Acquisition Agreement”) by and among Columbia Energy Group (“CEG”), Columbia Propane Corporation (“Columbia Propane”), Columbia Propane, L.P. (“CPLP”), CP Holdings, Inc. (“CPH,” and together with Columbia Propane and CPLP, the “Company Parties”), AmeriGas Partners, AmeriGas OLP and the General Partner (together with AmeriGas Partners and AmeriGas OLP, the “Buyer Parties”). As a result of the 2001 Acquisition, AmeriGas OLP acquired all of the stock of Columbia Propane and CPH and substantially all of the partnership interests of CPLP. Under the terms of an earlier acquisition agreement (the “1999 Acquisition Agreement”), the Company Parties agreed to indemnify the former general partners of National Propane Partners, L.P. (a predecessor company of the Columbia Propane businesses) and an affiliate (collectively, “National General Partners”) against certain income tax and other losses that they may sustain as a result of the 1999 acquisition by CPLP of National Propane Partners, L.P. (the “1999 Acquisition”) or the operation of the business after the 1999 Acquisition (“National Claims”). At March 31, 2009, the potential amount payable under this indemnity by the Company Parties was approximately $58.0. These indemnity obligations will expire on the date that CPH acquires the remaining outstanding partnership interest of CPLP, which is expected to occur on or after July 19, 2009. Under the terms of the 2001 Acquisition Agreement, CEG agreed to indemnify the Buyer Parties and the Company Parties against any losses that they sustain under the 1999 Acquisition Agreement and related agreements (“Losses”), including National Claims, to the extent such claims are based on acts or omissions of CEG or the Company Parties prior to the 2001 Acquisition. The Buyer Parties agreed to indemnify CEG against Losses, including National Claims, to the extent such claims are based on acts or omissions of the Buyer Parties or the Company Parties after the 2001 Acquisition. CEG and the Buyer Parties have agreed to apportion certain losses resulting from National Claims to the extent such losses result from the 2001 Acquisition itself. We believe that liability under such indemnity agreement is remote.

Samuel and Brenda Swiger and their son (the “Swigers”) sustained personal injuries and property damage as a result of a fire that occurred when propane that leaked from an underground line ignited. In July 1998, the Swigers filed a class action lawsuit against AmeriGas Propane, L.P. (named incorrectly as “UGI/AmeriGas, Inc.”), in the Circuit Court of Monongalia County, West Virginia, in which they sought to recover an unspecified amount of compensatory and punitive damages and attorney’s fees, for themselves and on behalf of persons in West Virginia for whom the defendants had installed propane gas lines, resulting from the defendants’ alleged failure to install underground propane lines at depths required by applicable safety standards. In 2003, AmeriGas OLP settled the individual personal injury and property damage claims of the Swigers. In 2004, the court granted the plaintiffs’ motion to include customers acquired from Columbia Propane in August 2001 as additional potential class members and the plaintiffs amended their complaint to name additional parties pursuant to such ruling. Subsequently, in March 2005, AmeriGas OLP filed a crossclaim against CEG, former owner of Columbia Propane, seeking indemnification for conduct undertaken by Columbia Propane prior to AmeriGas OLP’s acquisition. Class counsel has indicated that the class is seeking compensatory damages in excess of $12 plus punitive damages, civil penalties and attorneys’ fees.

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

- 20 -

UGI CORPORATION AND SUBSIDIARIES

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

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 manufactured gas plant (“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 and the possible existence of other potentially responsible parties. The Partnership continues to seek additional information about the site. Because of the preliminary nature of available environmental information, the amount of expected clean up costs cannot be reasonably estimated. When such expected clean up costs can be reasonably estimated, it is possible that the amount could be material to the Partnership’s results of operations.

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

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. In accordance with the terms of the PNG Gas base rate case order which became effective December 2, 2006, site-specific environmental investigation and remediation costs associated with PNG Gas incurred prior to December 2, 2006 are amortized as removal costs over five-year periods. Such costs incurred after December 1, 2006 are expensed as incurred.

- 21 -

UGI CORPORATION AND SUBSIDIARIES

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

PNG Gas is a party to a Multi-Site Remediation Consent Order and Agreement with the Pennsylvania Department of Environmental Protection dated March 31, 2004 (“Multi-Site Agreement”). The Multi-Site Agreement requires PNG Gas to perform annually a specified level of activities associated with environmental investigation and remediation work at 11 currently owned properties on which MGP-related facilities were operated (“Properties”). Under the Multi-Site Agreement, environmental expenditures, including costs to perform work on the Properties, are capped at $1.1 in any calendar year. The Multi-Site Agreement terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date. At March 31, 2009, our accrued liability for environmental investigation and remediation costs related to the Multi-Site Agreement was $8.3.

CPG is party to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection dated February 15, 2005 (“CPG-COA”), requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP-related facilities were operated (“MGP Properties”) and to plug a minimum of 16 non-producing natural gas wells per year. CPG has closed all but 8 of the MGP Properties and has plugged all but approximately 78 wells. Under the CPG-COA, environmental expenditures relating to the MGP Properties are capped at $1.8 in any calendar year. The CPG-COA terminates at the end of 2011 for the MGP Properties and at the end of 2013 for well plugging activities. In addition, CPG is responsible for remediation of an MGP Property in Georgetown, Delaware. The costs associated with remediation of the Georgetown MGP Property are not expected to be material. At March 31, 2009, our accrued liability for environmental investigation and remediation costs related to the CPG-COA was $10.8.

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

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

- 22 -

UGI CORPORATION AND SUBSIDIARIES

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

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.

City of Bangor, Maine v. Frontier Communications Corporation, f/k/a Citizens Communications Company. In April 2003, Citizens Communications Company, now known as Frontier Communications Corporation (“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 plaintiff, City of Bangor, Maine (“City”) sued Frontier to recover environmental response costs associated with MGP wastes generated at a plant allegedly operated by Frontier’s predecessors at a site on the Penobscot River. Frontier subsequently joined UGI Utilities and ten other third-party defendants alleging that the third-party defendants are responsible for an equitable share of costs Frontier may be required to pay to the City for cleaning up tar deposits in the Penobscot River. Frontier alleges that through ownership and control of a subsidiary, Bangor Gas Light Company, UGI Utilities and its predecessors owned and operated the plant from 1901 to 1928. Studies conducted by the City and Frontier suggest that it could cost up to $18 to clean up the river. Frontier’s third-party claims were stayed pending trial of the City’s suit against Frontier, which took place in September 2005. On June 27, 2006, the court issued an order finding Frontier responsible for 60% of the cleanup costs. On February 14, 2007, Frontier and the City entered into a settlement agreement pursuant to which Frontier agreed to pay $7.6 in exchange for a release of its and all predecessors’ liabilities. Separately, the Maine Department of Environmental Protection has disclaimed its previously announced intention to pursue third-party defendants, including UGI Utilities, for costs incurred by the State of Maine related to contaminants at this site. UGI Utilities believes that it has good defenses to all Frontier’s claims.

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

- 23 -

UGI CORPORATION AND SUBSIDIARIES

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

Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of its subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs for all of the sites would total approximately $215 and asserted that UGI Utilities is responsible for approximately $103 of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23. A trial to determine whether UGI Utilities is responsible for remediation costs concluded on May 1, 2009 and the court’s decision is pending. If necessary, the court will determine the amount of UGI Utilities’ share of those costs in a second trial.

Antargaz Competition Authority Matter. In June 2005, officials from France’s General Division of Competition, Consumption and Fraud Punishment (“DGCCRF”) conducted an unannounced inspection of, and obtained documents from, Antargaz’ headquarters building. Management believes that the DGCCRF performed similar unannounced inspections and document seizures at the locations of other distributors of LPG in France, as well as the industry association, Comite Francais du Butane et du Propane (“CFBP”). The DGCCRF apparently sought evidence of unlawful anti-competitive activities affecting the packaged LPG (i.e., cylinder) business in northern France.

Antargaz did not have any further contact with the DGCCRF regarding this matter until February 2007, when it received a letter from the DGCCRF requesting documents and information relating to Antargaz’ pricing policies and practices. In March 2007, and again in August 2007, the DGCCRF requested additional information from Antargaz and three joint ventures in which it participates. Based on these requests, it appears that the DGCCRF has expanded the scope of its investigation to include both bulk and cylinder markets throughout France. In July 2008, France’s Conseil de la Concurrence (“Competition Council,” and renamed, Autorité de la concurrence, “Competition Authority”) interviewed Mr. Varagne, as President of Antargaz and President of the CFBP, about competitive practices in the LPG cylinder market in France. During the fiscal quarter ended December 31, 2008, Antargaz responded to additional requests for information about the Company and Antargaz from the Competition Authority.

The Competition Authority is conducting a related investigation regarding alleged concerted behavior among certain distributors of LPG in France. We believe one of the companies under investigation has applied for leniency, pursuant to the French law that allows a company to offer evidence of anti-competitive behavior in exchange for partial or total amnesty from financial sanctions. A company seeking leniency may present testimony or other evidence of anti-competitive activities adverse to Antargaz’ interests. As part of any investigation, the Competition Authority and the DGCCRF may uncover information from other sources, including customers, suppliers or employees of Antargaz and other LPG companies, that may be adverse to Antargaz’ interests.

- 24 -

UGI CORPORATION AND SUBSIDIARIES

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

The Company believes the DGCCRF and the Competition Authority have substantially completed their investigations and the Competition Authority could issue a “Statement of Objections” during the current fiscal year. The Statement of Objections could allege that Antargaz and other major LPG distributors in France engaged in anti-competitive practices in violation of French civil competition laws, for which a fine may be assessed. When Antargaz receives a Statement of Objections, it will have an opportunity to review the evidence supporting the allegations contained therein and to present its defenses. While the Company cannot predict the likelihood of an adverse finding against Antargaz or the amount of the fine that may be assessed, it is reasonably possible that a fine could be assessed in an amount that would have a material adverse effect on the Company’s results of operations. In the event a claim is made against Antargaz and it is found to have violated the competition laws in France, it would be subject to civil penalties up to a maximum of 10% of the total annual consolidated revenues of the Company. The Company will continue to cooperate with the DGCCRF and the Competition Authority investigations.

In addition to these matters, there are other pending claims and legal actions arising in the normal course of our businesses. We cannot predict with certainty the final results of environmental and other matters. 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.

Acquisitions and Divestitures

On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL Gas Utilities Corporation (now named UGI Central Penn Gas, Inc., “CPG”), the natural gas distribution utility of PPL Corporation (the “CPG Acquisition”), for cash consideration of $267.6 plus estimated working capital of $35.4. Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central Penn Propane, LLC, “CPP”), its retail propane distributor, sold its assets to AmeriGas OLP for cash consideration of $32 plus estimated working capital of $1.6. CPG distributes natural gas to approximately 76,000 customers in eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in portions of one Maryland county. CPP sold propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition at closing with a combination of $120 cash contributed by UGI on September 25, 2008, proceeds from the issuance on October 1, 2008 of $108 principal amount of 6.375% Senior Notes due 2013 and approximately $75.0 of borrowings under UGI Utilities’ Revolving Credit Agreement. AmeriGas OLP funded its acquisition of the assets of CPP with borrowings under the AmeriGas Credit Agreement, and UGI Utilities used the $33.6 of cash proceeds from the sale of the assets of CPP to reduce its revolving credit agreement borrowings.

The assets and liabilities resulting from the CPG Acquisition are included in our Condensed Consolidated Balance Sheet at March 31, 2009. The purchase price allocation has been finalized except for the fair values of utility regulatory assets which are subject to a pending base rate proceeding of CPG (see Note 5). Pursuant to the CPG Acquisition purchase agreement, the purchase price was subject to adjustment for the difference between the estimated $35.4 and the actual working capital as of the closing date agreed to by both UGI Utilities and PPL Corporation (“PPL”). In February 2009, UGI Utilities and PPL reached an agreement on the working capital adjustment pursuant to which PPL paid UGI Utilities $3.7 in cash plus interest. UGI Utilities will receive an additional approximately $7.5 in cash from PPL associated with certain income tax assets later in Fiscal 2009. Also during the three months ended March 31, 2009, UGI Utilities and AmeriGas OLP reached an agreement on the working capital adjustment associated with UGI Utilities’ sale of the assets of CPP to AmeriGas OLP pursuant to which UGI Utilities paid AmeriGas OLP $1.4.

- 25 -

UGI CORPORATION AND SUBSIDIARIES

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

The purchase price of the CPG Acquisition, including transaction fees and expenses and incurred liabilities totaling approximately $2.9, has been preliminarily allocated to the assets acquired and liabilities assumed as follows:


Working capital	$	22.2
Property, plant and equipment		236.1
Goodwill		33.6
Utility regulatory assets		22.5
Other assets		12.5
Noncurrent liabilities		(32.1	)

Total	$	294.8

Substantially all of the goodwill is deductible for income tax purposes over a fifteen-year period.

The operating results of CPG and CPP are included in our consolidated results beginning October 1, 2008. The following table presents pro forma income statement and basic and diluted per share data for the three and six months ended March 31, 2008 as if the CPG Acquisition had occurred as of October 1, 2007:


	Three Months Ended		Six Months Ended
	March 31, 2008		March 31, 2008
	(pro forma)		(pro forma)
Revenues	$	2,455.2	$	4,277.0
Net income	$	132.6	$	217.5

Earnings per share:
Basic	$	1.24	$	2.03
Diluted	$	1.22	$	2.00

The pro forma results of operations reflect CPG’s and CPP’s historical operating results after giving effect to adjustments directly attributable to the transaction that are expected to have a continuing effect. The pro forma amounts are not necessarily indicative of the operating results that would have occurred had the CPG Acquisition been completed as of the date indicated, nor are they necessarily indicative of future operating results.

- 26 -

UGI CORPORATION AND SUBSIDIARIES

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

On November 13, 2008, AmeriGas OLP sold its 600,000 barrel refrigerated above-ground LPG storage facility located on leased property in California for net cash proceeds of $42.4. The Partnership recorded a $39.9 pre-tax gain on the sale which amount is included in “other income” on the Condensed Consolidated Statement of Income for the six months ended March 31, 2009. The sale increased net income by $10.4 or $0.10 per diluted share.

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

10.

Financing Activities

As a result of greater cash needed to fund counterparty collateral requirements resulting from rapid and precipitous declines in propane commodity prices during the three months ended December 31, 2008, on November 14, 2008, AmeriGas OLP entered into a revolving credit agreement with two major banks (“Supplemental Credit Agreement”). The Supplemental Credit Agreement was scheduled to expire on May 14, 2009 but was voluntarily terminated on April 17, 2009 concurrent with the signing of a new $75 revolving credit facility (as further described below). The Supplemental Credit Agreement permitted AmeriGas OLP to borrow up to $50 for working capital and general purposes. Except for more restrictive covenants regarding the incurrence of additional indebtedness by AmeriGas OLP, the Supplemental Credit Agreement had restrictive covenants similar to AmeriGas OLP’s $200 credit agreement expiring October 15, 2011 (“Credit Agreement”).

In order to increase liquidity, on April 17, 2009, AmeriGas OLP entered into a new $75 unsecured revolving credit facility (“2009 Supplemental Credit Agreement”) with three major banks. The 2009 Supplemental Credit Agreement expires on July 1, 2010 and permits AmeriGas OLP to borrow up to $75 for working capital and general purposes. Except for more restrictive covenants regarding the incurrence of additional indebtedness by AmeriGas OLP, the 2009 Supplemental Credit Agreement has restrictive covenants substantially similar to AmeriGas OLP’s Credit Agreement.

On October 1, 2008, UGI Utilities issued $108 face value of 6.375% Senior Notes due October 2013. The proceeds from the issuance of the Notes were used by UGI Utilities to fund a portion of the CPG Acquisition.

11.

Disclosures About Derivative Instruments and Hedging Activities

The Company is exposed to certain market risks related to its 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 derivative, hedging 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, generally qualify as hedges under SFAS 133, 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.

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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 heating season months of October through March, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. Certain other domestic business units and our International Propane operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases.

Gas Utility’s tariffs contain clauses that permit recovery of substantially all of the prudently incurred costs of natural gas it sells to retail core-market customers. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At March 31, 2009, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures contracts totaled 16.4 million dekatherms and the maximum period over which we are hedging natural gas market risk is six months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual PJM Interconnection (“PJM”) allocation process and by purchases of FTRs at monthly PJM auctions. Energy Services purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states.

In order to reduce operating expense volatility, our Gas Utility and Electric Utility from time to time enter into NYMEX gasoline futures contracts for a portion of gasoline volumes expected to be used in the operation of their vehicles and equipment. The volumes of gasoline under these contracts, the associated fair values and the effect on net income were not material for all periods presented.

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.

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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, 2009, the Company had the following outstanding derivative commodity instruments volumes that qualify for hedge accounting treatment:


Commodity	Volumes
LPG (millions of gallons)		160.2
Natural gas (millions of dekatherms)		46.6
Electricity (millions of kilowatt-hours)		423.0

The maximum period over which we are currently hedging our exposure to the variability in cash flows associated with commodity price risk is 21 months. The volume of electricity congestion that is subject to FTRs at March 31, 2009 totaled 1,337.2 million kilowatt-hours and the maximum period over which we are currently hedging electricity congestion with FTRs is 26 months.

We account for commodity price risk contracts (other than our Gas Utility natural gas futures contracts, FTRs and gasoline futures contracts) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in accumulated other comprehensive income (“AOCI”) and, with respect to the Partnership, minority interest, to the extent effective in offsetting changes in the underlying commodity price risk, until earnings are affected by the hedged item. With respect to natural gas futures contracts associated with our Gas Utility, gains and losses on unsettled natural gas futures contracts are recorded in deferred fuel costs on the Condensed Consolidated Balance Sheet in accordance with SFAS No. 71 and reflected in cost of sales through the PGC mechanism. At March 31, 2009, Gas Utility had recorded a current liability of $81.9, representing the fair value of unsettled natural gas futures contracts as of that date, and a regulatory asset of $81.9 within deferred fuel costs. Because Electric Utility is entitled to fully recover its default service costs commencing January 1, 2010 pursuant to a January 22, 2009 settlement of its default service rate filing with the PUC (see Note 5), changes in the fair value of Electric Utility FTRs associated with periods after January 1, 2010 will not affect net income. Electric Utility FTRs associated with periods prior to January 2010 are recorded at fair value with changes in fair value reflected in cost of sales. Energy Services’ FTRs are recorded at fair value with changes in fair value reflected in cost of sales.

Interest Rate Risk

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). As of March 31, 2009, the total notional amount of the Company’s unsettled IRPAs was $150. Our current unsettled IRPA contracts hedge forecasted interest payments associated with issuances of debt forecasted to occur through July 2010.

Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has effectively fixed the underlying euribor interest rate on its variable-rate debt through March 2011 and Flaga has fixed the underlying euribor interest rate on a substantial portion of its term loan through September 2011 through the use of pay-fixed, receive-variable interest rate swap agreements. As of March 31, 2009, the total notional amount of our interest rate swaps was €406.6.

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UGI CORPORATION AND SUBSIDIARIES

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

We account for IRPAs and interest rate swaps as cash flow hedges. Changes in the fair values of IRPAs and interest rate swaps are recorded in AOCI and, with respect to the Partnership, minority interest, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense.

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 volume of such contracts are equal to approximately 20% of dollar-denominated purchases of LPG estimated to occur during the heating-season months of October through March. At March 31, 2009, we were hedging a total of $101.7 of U.S. dollar denominated LPG purchases. The Company also enters into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of its International Propane euro-denominated net investment. At March 31, 2009, we were hedging a total of €30.8 of our euro-denominated net investments. As of March 31, 2009, our foreign currency contracts extend through October 2011.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.

Credit Risk Concentration

We are exposed to credit loss in the event of nonperformance by counterparties to derivative financial and commodity instruments. Our counterparties principally consist of major energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. We generally do not have credit-risk-related contingent features in our derivative contracts.

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UGI CORPORATION AND SUBSIDIARIES

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

The following table provides information regarding the balance sheet location and fair value of derivative assets and liabilities existing as of March 31, 2009:


	Derivative Assets			Derivative (Liabilities)
	Balance Sheet	Fair		Balance Sheet	Fair
As of March 31, 2009	Location	Value		Location	Value
Derivatives Designated as Hedging Instruments:

Commodity contracts:
LPG contracts	Derivative financial instruments and Other assets	$	0.4	Derivative financial instruments and Other noncurrent liabilities	$	(65.0	)

Natural gas contracts	Derivative financial instruments and Other assets		0.8	Derivative financial instruments and Other noncurrent liabilities		(125.3	)

Electricity contracts				Derivative financial instruments and Other noncurrent liabilities		(5.6	)

Foreign currency contracts	Derivative financial instruments and Other assets		9.8

Interest rate contracts	Other assets		0.2	Derivative financial instruments and Other noncurrent liabilities		(40.9	)


Total Derivatives Designated as Hedging Instruments		$	11.2		$	(236.8	)


Derivatives Not Designated as Hedging Instruments:

FTRs	Derivative financial instruments and Other assets	$	1.5

Gasoline contracts				Derivative financial instruments	$	(0.4	)

Total Derivatives Not Designated as Hedging instruments		$	1.5		$	(0.4	)


Total Derivatives		$	12.7		$	(237.2	)

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UGI CORPORATION AND SUBSIDIARIES

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

The following tables provide information on the effects of derivative instruments on the consolidated statement of income and changes in AOCI and minority interest for the three and six months ended March 31, 2009:



Three Months Ended March 31, 2009				Location of	Gain or (Loss)
	Gain or (Loss)			Gain or (Loss)	Reclassified
	Recognized in			Reclassified from	from
	AOCI and			AOCI and Minority	AOCI and Minority
	Minority Interest			Interest into Income	Interest into Income

Cash Flow Hedges:
Commodity contracts:
LPG	$	(3.1	)	Cost of sales	$	(90.5	)
Natural gas		(44.3	)	Cost of sales		(32.7	)
Electricity		(3.0	)	Cost of sales		(0.9	)
Foreign currency contracts		6.0		Cost of sales		2.5
Interest rate contracts		(7.4	)	Interest expense /other income		(3.1	)

Total	$	(51.8	)		$	(124.7	)


Net Investment Hedges:

Foreign currency contracts	$	1.7

Location of Gain

Gain

Recognized in

Income

Derivatives Not Designated as Hedging Instruments:

FTRs

Cost of sales

0.8

Gasoline contracts

Operating

expenses/other

income

0.1

Total

0.9

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UGI CORPORATION AND SUBSIDIARIES

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



Six Months Ended March 31, 2009				Location of	Gain or (Loss)
	Gain or (Loss)			Gain or (Loss)	Reclassified
	Recognized in			Reclassified from	from
	AOCI and			AOCI and Minority	AOCI and Minority
	Minority Interest			Interest into Income	Interest into Income

Cash Flow Hedges:
Commodity contracts
LPG	$	(174.1	)	Cost of sales	$	(152.3	)
Natural gas		(88.6	)	Cost of sales		(51.0	)
Electricity		(5.0	)	Cost of sales		(1.3	)
Foreign currency contracts		9.1		Cost of sales		4.8
Interest rate contracts		(47.5	)	Interest expense / other income		(1.0	)

Total	$	(306.1	)		$	(200.8	)


Net Investment Hedges:

Foreign currency contracts	$	2.1

Location of (Loss)

(Loss)

Recognized in

Income

Derivatives Not Designated as Hedging Instruments:

FTRs

Cost of sales

(0.1

)

Gasoline

Operating

expenses/other

income

(0.9

)

Total

(1.0

)

The amounts of derivative gain or loss representing ineffectiveness and the amounts of gain or loss recognized in income as a result of excluding from ineffectiveness testing were not material for the three and six months ended March 31, 2009, respectively. The Company reclassified losses of $1.7 into income during the three and six months ended March 31, 2009 as a result of the discontinuance of cash flow hedges. The amount of net losses associated with cash flow hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $152.3.

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UGI CORPORATION AND SUBSIDIARIES

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

Forward-Looking Statements

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

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other LPG, oil, electricity and natural gas and the capacity to transport product to our market areas; (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, propane and other LPG; (13) political, regulatory and economic conditions in the United States and in foreign countries, including foreign currency rate fluctuations, particularly in the euro; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (15) changes in commodity market prices resulting in significantly higher cash collateral requirements; (16) reduced distributions from subsidiaries; and (17) the timing and success of the Company’s efforts to develop new business opportunities.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on 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, 2009 (“2009 three-month period”) with the three months ended March 31, 2008 (“2008 three-month period”) and the six months ended March 31, 2009 (“2009 six-month period”) with the six months ended March 31, 2008 (“2008 six-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 3 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 November through March. As a result, our earnings are generally higher in the first and second fiscal quarters.

Our net income for the 2009 three-month period increased to $158.2 million from $126.1 million in the prior-year three-month period. The increase principally reflects greater net income from our International Propane operations and, to a much lesser extent, greater net income from AmeriGas Propane, Energy Services and Gas Utility. Temperatures in our International Propane operations were colder than normal in the 2009 three-month period and colder than in the prior year. International Propane volumes increased as a result of significantly colder weather while our AmeriGas Propane volumes were lower than in the prior year principally as a result of the effects of recessionary economic conditions, customer conservation and slightly warmer weather. Our International Propane and AmeriGas Propane 2009 three-month period results benefited from higher average retail unit margins resulting from significantly lower and less volatile LPG product costs following a rapid and precipitous decline in wholesale LPG product costs during the first quarter of Fiscal 2009. We expect unit margins in these businesses to return to more normal levels over the remainder of Fiscal 2009. Our higher Gas Utility results include the operations of CPG subsequent to its acquisition on October 1, 2008. Energy Services net income improved as greater natural gas unit margins and higher peaking services and asset management income were offset, in part, by lower electric generation net income.

Our net income for the 2009 six-month period increased to $273.1 million from net income of $206.1 million in the prior-year six-month period principally reflecting greater net income from International Propane and AmeriGas Propane and, to a much lesser extent, greater net income from Gas Utility. International Propane LPG volumes increased as a result of colder weather while our AmeriGas Propane volumes were lower than in the prior year due to the effects on volumes sold of recessionary economic conditions and customer conservation. As was the case in the 2009 three-month period, our International Propane and AmeriGas Propane results benefited from higher average retail unit margins resulting from significantly lower LPG product costs as a result of a rapid and precipitous decline in wholesale LPG commodity prices during the first quarter of Fiscal 2009. Our Gas Utility six-month period results include the results of CPG subsequent to its acquisition on October 1, 2008. Energy Services net income was equal to the prior-year period as greater natural gas unit margins and higher peaking services and asset management income were offset, in large part, by lower electric generation net income.

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UGI CORPORATION AND SUBSIDIARIES

The U.S. dollar was stronger versus the euro in the 2009 three and six-month periods compared with such periods in Fiscal 2008. However, the adverse effects of the stronger dollar on reported International Propane net income were substantially offset by the effects of gains on forward currency contracts used to hedge purchases of dollar-denominated LPG.

Net income (loss) by business unit:


	Three Months Ended						Six Months Ended
	March 31,						March 31,
	2009			2008			2009			2008
	(Millions of dollars)						(Millions of dollars)
Net income (loss):
AmeriGas Propane (a)	$	40.2		$	36.0		$	74.5	(b)	$	51.0
International Propane		54.5			32.7			94.7			55.1
Gas Utility		41.8			39.8			70.1			63.8
Electric Utility		2.8			3.5			5.6			7.5
Energy Services		19.6			16.4			30.3			30.3
Corporate & Other		(0.7	)		(2.3	)		(2.1	)		(1.6	)

Total net income	$	158.2		$	126.1		$	273.1		$	206.1


(a)		Amounts are net of minority interests in AmeriGas Partners, L.P.

(b)		Includes net income of $10.4 million from sale of the Partnership’s California LPG storage facility.

2009 three-month period compared to the 2008 three-month period

AmeriGas Propane:


							Increase
For the three months ended March 31,	2009			2008			(Decrease)
(Millions of dollars)
Revenues	$	823.3		$	1,006.6		$	(183.3	)	(18.2	)%
Total margin (a)	$	349.3		$	330.6		$	18.7		5.7	%
Partnership EBITDA (b)	$	187.3		$	171.8		$	15.5		9.0	%
Operating income	$	168.1		$	153.2		$	14.9		9.7	%
Retail gallons sold (millions)		342.9			368.5			(25.6	)	(6.9	)%
Degree days — % (warmer) than normal (c)		(2.3	)%		(1.0	)%		—		—


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

(b)		Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 3 to condensed consolidated financial statements).

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

Based upon heating degree-day data, average temperatures in our service territories were 2.3% warmer than normal during the 2009 three-month period compared with temperatures in the prior-year period that were 1.0% warmer than normal. Notwithstanding the benefit of the October 1, 2008 acquisition of the net assets of CPP, retail gallons sold were less than the prior-year period reflecting, among other things, the adverse effects of the significant deterioration in general economic activity which has occurred over the last year, continued customer conservation and the slightly warmer weather.

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UGI CORPORATION AND SUBSIDIARIES

Retail propane revenues declined $154.9 million during the 2009 three-month period reflecting a $92.7 million decrease due to lower average selling prices and a $62.2 million decrease as a result of the lower retail volumes sold. Wholesale propane revenues declined $25.3 million reflecting a decrease in year-over-year wholesale selling prices. Wholesale propane commodity prices at Mont Belvieu, Texas, one of the major supply points in the U.S., generally stabilized during the three months ended March 31, 2009 following a more than 50% decline in prices during the first quarter of Fiscal 2009. Wholesale prices at Mont Belvieu during the 2009 three-month period were more than 50% lower than such prices a year ago. Total cost of sales decreased $202.0 million to $474.0 million principally reflecting the effects of the lower propane product costs.

Total margin was $18.7 million greater in the 2009 three-month period reflecting the beneficial impact of higher than normal retail unit margins resulting from the previously mentioned significantly lower and less volatile propane product costs. We expect unit margins to return to more normal levels over the remainder of Fiscal 2009.

EBITDA during the 2009 three-month period was $187.3 million compared with EBITDA of $171.8 million in the 2008 three-month period. The greater 2009 three-month period EBITDA reflects the previously mentioned $18.7 million increase in total margin partially offset by lower other income and slightly higher operating and administrative expenses. The higher operating and administrative expenses reflect greater compensation and benefits expenses, including incremental expenses resulting from the purchase of the CPP net assets, offset in large part by lower vehicle fuel expense.

Operating income increased $14.9 million reflecting the $15.5 million increase in EBITDA and slightly higher depreciation and amortization expense associated with acquisitions and plant and equipment expenditures made since the prior year.

International Propane:


							Increase
For the three months ended March 31,	2009			2008			(Decrease)
(Millions of euros)
Revenues	€	259.2		€	249.6		€	9.6		3.8	%
Total margin (a)	€	143.1		€	105.1		€	38.0		36.2	%
Operating income	€	68.1		€	37.0		€	31.1		84.1	%
Income before income taxes	€	62.4		€	31.5		€	30.9		98.1	%

(Millions of dollars)
Revenues	$	338.6		$	375.0		$	(36.4	)	(9.7	)%
Total margin (a)	$	187.1		$	157.9		$	29.2		18.5	%
Operating income	$	89.7		$	54.8		$	34.9		63.7	%
Income before income taxes	$	82.0		$	46.1		$	35.9		77.9	%

Antargaz retail gallons sold		103.1			97.0			6.1		6.3	%
Degree days — % colder (warmer) than normal (b)		5.4	%		(10.3	)%		—		—


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

(b)		Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30 locations in our French service territory.

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UGI CORPORATION AND SUBSIDIARIES

Based upon heating degree day data, temperatures in Antargaz’ service territory were approximately 5.4% colder than normal during the 2009 three-month period compared with temperatures that were approximately 10.3% warmer than normal during the prior-year period. Temperatures in Flaga’s service territory were colder than normal in the 2009 three-month period compared with weather that was warmer than normal in the prior-year period. Wholesale propane product costs were significantly lower during the 2009 three-month period following significant declines during the first quarter of Fiscal 2009. The average wholesale commodity price for propane in northwest Europe during the 2009 three-month period was approximately 44% lower than such price during the same period last year. Wholesale butane prices were also significantly lower in the 2009 three-month period. Antargaz’ 2009 three-month period retail propane volumes were higher than in the prior-year period principally as a result of the colder weather partially offset by continued customer conservation, the effects of competition from alternate energy sources and the deterioration of general economic conditions in France.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. During the 2009 three-month period, the average currency translation rate was $1.30 per euro compared to a rate of $1.51 per euro during the prior-year three-month period. Although the stronger dollar resulted in lower translated International Propane operating results, the effects of the stronger dollar on reported International Propane net income were substantially offset by the effects of gains on forward currency contracts used to hedge purchases of dollar-denominated LPG.

International Propane euro-based revenues increased €9.6 million or 3.8% reflecting the higher retail gallons sold partially offset by lower average selling prices. The lower average selling prices reflect the effects of the previously mentioned year-over-year decrease in wholesale LPG product costs. In U.S. dollars, revenues declined $36.4 million or 9.7% as the previously mentioned higher euro-based revenues were more than offset by the effects of the stronger U.S. dollar. International Propane’s total cost of sales decreased to €116.1 million in the 2009 three-month period from €144.6 million in the prior year reflecting the lower per-unit LPG commodity costs and the effects of gains on forward currency contracts used to hedge purchases of dollar-denominated LPG.

International Propane total margin increased €38.0 million or 36.2% in the 2009 three-month period largely reflecting the beneficial impact of higher than normal retail unit margins resulting from lower and less volatile LPG product costs following a rapid and sharp decline in LPG product costs earlier in the 2009 Fiscal Year. We presently expect unit margins to return to more normal levels over the remainder of Fiscal 2009. Antargaz was adversely affected by lower unit margins in the prior-year period as a result of the rapid increase in LPG product costs which occurred last year. In U.S. dollars, total margin increased $29.2 million or 18.5% reflecting the effects of the stronger dollar on translated euro base-currency revenues and cost of sales.

International Propane euro-based operating income increased €31.1 million or 84.1% principally reflecting the previously mentioned increase in total margin and slightly higher operating and administrative costs principally resulting from the consolidation of the operations of ZLH effective in January 2009. On a U.S. dollar basis, operating income increased $34.9 million or 63.7% reflecting the previously-mentioned increase in U.S. dollar-denominated total margin and lower U.S. dollar-denominated operating expenses and depreciation and amortization principally as a result of the stronger U.S. dollar. Euro-based income before income taxes was €30.9 million or 98.1% greater than in the prior year principally reflecting the higher operating income. In U.S. dollars, income before income taxes increased $35.9 million or 77.9% reflecting the benefit of the higher dollar-denominated operating income and the effects of the stronger dollar on translated interest expense.

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UGI CORPORATION AND SUBSIDIARIES

Gas Utility:


For the three months ended March 31,	2009			2008			Increase
(Millions of dollars)
Revenues	$	542.8		$	476.7		$	66.1	13.9	%
Total margin (a)	$	149.9		$	121.6		$	28.3	23.3	%
Operating income	$	80.0		$	75.5		$	4.5	6.0	%
Income before income taxes	$	69.6		$	66.0		$	3.6	5.5	%
System throughput — billions of cubic feet (“bcf”)		56.5			49.6			6.9	13.9	%
Degree days — % colder (warmer) than normal (b)		4.1	%		(1.7	)%		—	—


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

(b)		Deviation from average heating degree days for the 15-year period 1990-2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

Temperatures in the Gas Utility service territory based upon heating degree days were 4.1% colder than normal in the 2009 three-month period compared with temperatures that were 1.7% warmer than normal in the prior-year period. In Fiscal 2009, Gas Utility began calculating normal degree days using the 15-year period 1990-2004. Previously, normal degree days were based upon recent 30-year periods. For comparability purposes, the prior-year period weather variance has been recalculated using the new 15-year period. Total distribution system throughput increased 6.9 bcf in the 2009 three-month period reflecting the effects of the CPG Acquisition and increases in firm- residential, commercial and industrial (“retail core-market”) and retail delivery service (collectively, “core market”) volumes resulting from the colder 2009 three-month period weather and year-over-year customer growth. These increases in system throughput were partially offset by the effects on volumes sold and transported from lower demand from commercial and industrial customers due to the deterioration in general economic activity which has occurred over the last year.

Gas Utility revenues increased $66.1 million principally reflecting $85.5 million in incremental revenues from CPG partially offset by a decline in low-margin off-system sales revenues. Changes in average purchased gas cost (“PGC”) rates did not have a significant effect on period-over-period revenues. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Deferred fuel costs included on the Condensed Consolidated Balance Sheet at March 31, 2009 principally reflect the effects of significantly higher unrealized losses on natural gas futures contracts due to recent declines in wholesale natural gas prices. Gas Utility’s cost of gas was $392.9 million in the 2009 three-month period compared with $355.1 million in the prior-year period principally reflecting incremental cost of sales of $60.4 million associated with CPG partially offset by the effects on cost of sales of the lower off-system sales.

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UGI CORPORATION AND SUBSIDIARIES

Gas Utility total margin increased $28.3 million principally reflecting incremental margin from CPG and higher total retail core-market margin resulting from the higher retail core-market volumes sold.

The increase in Gas Utility operating income during the 2009 three-month period principally reflects the previously mentioned greater total margin partially offset by higher operating, administrative and depreciation expenses, including incremental expenses associated with CPG, and, to a lesser extent, higher provisions for bad debts, environmental matters, pension expense and distribution system maintenance expenses. The increase in income before income taxes reflects the previously mentioned higher operating income partially offset by higher interest expense associated with the $108 million face value of 6.375% Senior Notes issued to finance a portion of the CPG acquisition.

Electric Utility:


For the three months ended March 31,	2009		2008		Decrease
(Millions of dollars)
Revenues	$	38.1	$	38.6	$	(0.5	)	(1.3	)%
Total margin (a)	$	11.9	$	12.2	$	(0.3	)	(2.5	)%
Operating income	$	5.5	$	6.5	$	(1.0	)	(15.4	)%
Income before income taxes	$	5.1	$	5.9	$	(0.8	)	(13.6	)%
Distribution sales — millions of kilowatt hours (“gwh”)		273.1		279.1		(6.0	)	(2.1	)%


(a)		Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $2.0 million and $2.2 million during the three-month periods ended March 31, 2009 and 2008, 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 2009 three-month period were lower than in the prior year. Temperatures based upon heating degree days were approximately 2.2% colder than last year resulting in greater sales to residential heating customers. These greater sales were more than offset however by lower sales to commercial and industrial customers as a result of the deterioration in general economic activity. Electric Utility revenues decreased $0.5 million principally as a result of the lower sales partially offset by higher Provider of Last Resort (“POLR”) rates. In accordance with the terms of its June 2006 POLR Settlement, Electric Utility increased its POLR rates effective January 1, 2009. This increase raised the average cost to a residential heating customer by approximately 1.5% over costs in effect during calendar year 2008. Electric Utility cost of sales were $24.2 million in both the 2009 three-month period and the 2008 three-month period principally reflecting the effects of the lower sales and slightly lower per-unit purchased power costs offset by greater electricity transmission costs.

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UGI CORPORATION AND SUBSIDIARIES

Notwithstanding the increase in POLR rates, Electric Utility total margin decreased $0.3 million during the 2009 three-month period principally reflecting the effects of the lower sales and greater electricity transmission costs.

Electric Utility operating income and income before income taxes in the 2009 three-month period were $1.0 million and $0.8 million lower than such amounts in the prior-year period, respectively, reflecting the previously mentioned lower total margin and higher operating and administrative costs including greater provisions for bad debts and higher pension expense.

Energy Services:


					Increase
For the three months ended March 31,	2009		2008		(Decrease)
(Millions of dollars)
Revenues	$	424.6	$	507.2	$	(82.6	)	(16.3	)%
Total margin (a)	$	49.4	$	39.3	$	10.1		25.7	%
Operating income	$	33.2	$	27.6	$	5.6		20.3	%
Income before income taxes	$	33.2	$	27.6	$	5.6		20.3	%


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

Although retail gas volumes sold in the 2009 three-month period were about equal to the prior-year period, Energy Services total revenues declined $82.6 million principally reflecting the effects on revenues of lower average unit prices for natural gas and propane.

Total margin from Energy Services increased $10.1 million in the 2009 three-month period reflecting greater total margin from peaking supply services, sales of natural gas and asset management activities partially offset by lower electric generation total margin. The decrease in electric generation total margin reflects lower volumes generated and lower spot-market prices. The increase in Energy Services’ operating income and income before income taxes largely reflects the previously mentioned increase in total margin partially offset by higher electric generation operating and maintenance costs, higher asset management fees and higher provisions for bad debts and compensation expenses. The lower operating income also reflects greater borrowing costs associated with Energy Services’ receivables securitization facility as a result of higher borrowings to fund margin calls resulting from declines in natural gas prices.

2009 six-month period compared to the 2008 six-month period

AmeriGas Propane:


							Increase
For the six months ended March 31,	2009			2008			(Decrease)
(Millions of dollars)
Revenues	$	1,550.4		$	1,754.8		$	(204.4	)	(11.6	)%
Total margin (a)	$	630.9		$	572.5		$	58.4		10.2	%
Partnership EBITDA (b)	$	351.4		$	264.8		$	86.6		32.7	%
Operating income	$	312.8		$	227.2		$	85.6		37.7	%
Retail gallons sold (millions)		621.1			647.6			(26.5	)	(4.1	)%
Degree days — % (warmer) than normal (c)		(1.7	)%		(3.7	)%		—		—


(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 3 to condensed consolidated financial statements).

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

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UGI CORPORATION AND SUBSIDIARIES

Based upon heating degree-day data, average temperatures in our service territories were 1.7% warmer than normal during the 2009 six-month period compared with temperatures in the prior-year period that were 3.7% warmer than normal. Notwithstanding the colder 2009 six-month period weather and the benefit of the acquisition of the net assets of CPP on October 1, 2008, retail gallons sold were lower than the prior-year period reflecting, among other things, the adverse effects of the significant deterioration in general economic activity which has occurred over the last year and continued customer conservation.

Retail propane revenues declined $167.6 million during the 2009 six-month period reflecting a $104.5 million decrease due to lower average selling prices and a $63.1 million decrease as a result of the lower retail volumes sold. Wholesale propane revenues declined $33.6 million reflecting a $49.6 million decrease from lower wholesale selling prices partially offset by a $16.0 million increase from higher wholesale volumes sold. From the beginning to the end of the first quarter of Fiscal 2009, wholesale propane commodity prices at Mont Belvieu, Texas declined more than 50% and generally remained at these lower price levels during the second half of the 2009 six-month period. Average wholesale propane prices in the 2009 six-month period were approximately 50% below average prices in the previous-year period. Total cost of sales decreased $262.8 million to $919.5 million principally reflecting the effects of the lower propane product costs.

Total margin was $58.4 million greater in the 2009 six-month period reflecting the beneficial impact of higher than normal retail unit margins resulting from a rapid and sharp decline in propane product costs during the first half of the 2009 six-month period. We expect unit margins to return to more normal levels over the remainder of Fiscal 2009.

EBITDA during the 2009 six-month period was $351.4 million compared with EBITDA of $264.8 million in the 2008 six-month period. The 2009 six-month period EBITDA includes a $39.9 million pre-tax gain from the sale of the Partnership’s California LPG storage facility. In addition to the gain from the sale of the California LPG storage facility, the 2009 six-month period EBITDA reflects the previously mentioned $58.4 million increase in total margin partially offset by slightly higher operating and administrative expenses and lower other income. The slightly higher operating and administrative expenses reflect in large part higher provisions for bad debts, greater general insurance expenses and incremental expenses from the CPP business partially offset by, among other things, lower vehicle fuel expenses.

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UGI CORPORATION AND SUBSIDIARIES

Operating income increased $85.6 million reflecting the $86.6 million increase in EBITDA and slightly higher depreciation and amortization expense associated with acquisitions and plant and equipment expenditures made since the prior year.

International Propane:


							Increase
For the six months ended March 31,	2009			2008			(Decrease)
(Millions of euros)
Revenues	€	469.7		€	475.5		€	(5.8	)	(1.2	)%
Total margin (a)	€	260.0		€	197.0		€	63.0		32.0	%
Operating income	€	116.4		€	63.7		€	52.7		82.7	%
Income before income taxes	€	105.9		€	52.9		€	53.0		100.2	%

(Millions of dollars)
Revenues	$	615.7		$	703.4		$	(87.7	)	(12.5	)%
Total margin (a)	$	340.8		$	291.5		$	49.3		16.9	%
Operating income	$	153.8		$	93.9		$	59.9		63.8	%
Income before income taxes	$	139.5		$	77.1		$	62.4		80.9	%

Antargaz retail gallons sold		199.3			195.0			4.3		2.2	%
Degree days — % colder (warmer) than normal (b)		5.2	%		(3.0	)%		—		—


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

(b)		Deviation from average heating degree days for the 30-year period 1971-2000 at more than 30 locations in our French service territory.

Based upon heating degree day data, temperatures in Antargaz’ service territory were approximately 5.2% colder than normal during the 2009 six-month period compared with temperatures that were approximately 3.0% warmer than normal during the prior-year period. Temperatures in Flaga’s service territory were colder than in the prior-year period. Wholesale propane product costs declined significantly principally during the first half of the 2009 six-month period. The average wholesale commodity price for propane in northwest Europe in the 2009 six-month period was approximately 47% lower than such price in the same period last year. Similar declines in wholesale butane prices were experienced in the 2009 six-month period. Antargaz’ 2009 six-month period retail propane volumes were slightly higher than in the prior-year period principally as a result of the colder weather partially offset by continued customer conservation, the effects of competition from alternate energy sources and the deterioration of general economic conditions in France.

Our International Propane base-currency results are translated into U.S dollars based upon exchange rates experienced during each of the reporting periods. During the 2009 six-month period, the average currency translation rate was $1.31 per euro compared to a rate of $1.48 per euro during the prior-year six-month period. Although the stronger dollar resulted in lower translated International Propane operating results, the effects of the stronger dollar on reported International Propane net income were substantially offset by the effects of gains on forward currency contracts used to hedge purchases of dollar-denominated LPG.

Notwithstanding the greater retail gallons sold, International Propane euro-based revenues decreased €5.8 million or 1.2% reflecting lower average selling prices during the 2009 six-month period. The lower average selling prices reflect the previously mentioned year-over-year decrease in wholesale LPG product costs. In U.S. dollars, revenues declined $87.7 million or 12.5% reflecting the lower euro-based revenues and the effects of the stronger U.S. dollar. International Propane’s total cost of sales decreased to €209.7 million in the 2009 six-month period from €278.5 million in the prior year reflecting the lower per-unit LPG commodity costs and the stronger U.S. dollar.

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UGI CORPORATION AND SUBSIDIARIES

International Propane total margin increased €63.0 million or 32.0% in the 2009 six-month period largely reflecting the beneficial impact of higher than normal retail unit margins resulting from a rapid and sharp decline in LPG product costs principally during the first half of the 2009 six-month period. We presently expect unit margins to return to more normal levels over the remainder of Fiscal 2009. Antargaz was adversely affected by lower unit margins in the prior-year period as a result of the rapid increase in LPG product costs which occurred last year. In U.S. dollars, total margin increased $49.3 million or 16.9% reflecting the effects of the stronger dollar on translated euro base-currency revenues and cost of sales.

International Propane operating income increased €52.7 million or 82.7% principally reflecting the previously mentioned increase in total margin and slightly higher operating and administrative costs. On a U.S. dollar basis, operating income increased $59.9 million or 63.8% reflecting the previously-mentioned increase in U.S. dollar-denominated total margin and lower U.S. dollar-denominated operating and administrative expenses and depreciation and amortization principally as a result of the stronger U.S. dollar. Euro-based income before income taxes was €53.0 million or 100.2% greater than in the prior year principally reflecting the higher operating income. In U.S. dollars, income before income taxes increased $62.4 million or 80.9% reflecting the benefit of the higher dollar-denominated operating income and the effects of the stronger dollar on translated interest expense.

Gas Utility:


For the six months ended March 31,	2009			2008			Increase
(Millions of dollars)
Revenues	$	953.2		$	803.4		$	149.8	18.6	%
Total margin (a)	$	267.3		$	211.5		$	55.8	26.4	%
Operating income	$	136.9		$	125.6		$	11.3	9.0	%
Income before income taxes	$	115.5		$	105.7		$	9.8	9.3	%
System throughput — billions of cubic feet (“bcf”)		100.5			89.1			11.4	12.8	%
Degree days — % colder (warmer) than normal (b)		5.4	%		(2.7	)%		—	—


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

(b)		Deviation from average heating degree days for the 15-year period 1990-2004 based upon weather statistics provided by the National Oceanic and Atmospheric Administration (“NOAA”) for airports located within Gas Utility’s service territory.

Temperatures in the Gas Utility service territory based upon heating degree days were 5.4% colder than normal in the 2009 six-month period compared with temperatures that were 2.7% warmer than normal in the prior-year period. Total distribution throughput increased 11.4 bcf in the 2009 six-month period principally reflecting the effects of the CPG Acquisition on October 1, 2008 and increases in core market volumes resulting from the colder 2009 six-month period weather and year-over-year customer growth. These increases in system throughput were partially offset by the effects on volumes sold and transported from lower demand from commercial and industrial customers due to the deterioration in general economic activity which has occurred over the last year.

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UGI CORPORATION AND SUBSIDIARIES

Gas Utility revenues increased $149.8 million in the 2009 six-month period principally reflecting $138.9 million in incremental revenues from CPG and the effects of higher volume sales and slightly higher average retail core-market PGC rates. These increases were partially offset by lower off-system sales revenues. Gas Utility’s cost of gas was $685.9 million in the 2009 six-month period compared with $591.9 million in the prior-year period principally reflecting incremental cost of sales of $92.6 million associated with CPG and the effects of the previously mentioned higher average PGC rates partially offset by the lower off-system sales.

Gas Utility total margin increased $55.8 million principally reflecting incremental margin from CPG and higher total retail core-market margin resulting from the higher retail core-market volumes sold.

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

Electric Utility:


					Increase
For the six months ended March 31,	2009		2008		(Decrease)
(Millions of dollars)
Revenues	$	74.0	$	70.5	$	3.5		5.0	%
Total margin (a)	$	22.6	$	24.6	$	(2.0	)	(8.1	)%
Operating income	$	10.5	$	13.9	$	(3.4	)	(24.5	)%
Income before income taxes	$	9.7	$	12.8	$	(3.1	)	(24.2	)%
Distribution sales — millions of kilowatt hours (“gwh”)		525.9		533.5		(7.6	)	(1.4	)%


(a)		Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $4.1 million and $4.0 million during the six-month periods ended March 31, 2009 and 2008, 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 2009 six-month period were slightly lower than in the prior year. Temperatures based upon heating degree days were approximately 5.9% colder than last year resulting in greater sales to residential heating customers. These greater sales were more than offset however by slightly lower sales to commercial and industrial customers as a result of the deterioration in general economic activity. Notwithstanding the slightly lower total sales, Electric Utility revenues increased $3.5 million principally as a result of higher POLR rates and greater revenues from spot market sales of electricity. Electric Utility cost of sales increased to $47.4 million in the 2009 six-month period from $41.9 million in the prior year principally reflecting higher per-unit purchased power costs and greater electricity transmission costs.

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UGI CORPORATION AND SUBSIDIARIES

Notwithstanding the increase in POLR rates, Electric Utility total margin decreased $2.0 million during the 2009 six-month period principally reflecting the higher per-unit purchased power and electricity transmission costs and the lower kilowatt-hour sales.

Electric Utility operating income and income before income taxes in the 2009 six-month period were $3.4 million and $3.1 million lower than the prior year, respectively, reflecting the previously mentioned lower total margin and higher operating and administrative costs including greater provisions for bad debts and pension expense.

Energy Services:


					Increase
For the six months ended March 31,	2009		2008		(Decrease)
(Millions of dollars)
Revenues	$	783.7	$	872.5	$	(88.8	)	(10.2	)%
Total margin (a)	$	81.8	$	73.2	$	8.6		11.7	%
Operating income	$	51.4	$	51.3	$	0.1		0.2	%
Income before income taxes	$	51.4	$	51.3	$	0.1		0.2	%


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

Although retail gas volumes sold in the 2009 six-month period were about equal to the prior-year period, Energy Services total revenues declined $88.8 million principally reflecting the effects on revenues of lower unit prices for natural gas and propane.

Total margin from Energy Services increased $8.6 million in the 2009 six-month period reflecting greater total margin from peaking supply services, sales of natural gas and asset management activities partially offset by lower electric generation total margin. The decrease in electric generation total margin reflects lower volumes generated as a result of electricity production facility outages principally during the first quarter of Fiscal 2009 and lower spot-market prices. The increase in Energy Services’ operating income and income before income taxes largely reflects the previously mentioned increase in total margin partially offset by higher electric generation operating and maintenance costs, higher asset management fees and higher provisions for bad debts and compensation expense. Operating income also reflects greater borrowing costs associated with Energy Services’ receivables securitization facility as a result of higher borrowings to fund margin calls resulting from declines in natural gas prices.

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

Our cash and cash equivalents totaled $192.6 million at March 31, 2009 compared with $245.2 million at September 30, 2008. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at March 31, 2009 we had $59.0 million of cash and cash equivalents that was not restricted. At September 30, 2008, excluding cash and cash equivalents at UGI’s operating subsidiaries of $148.0 million, and excluding the $120 million cash contribution made to UGI Utilities on September 25, 2008 in conjunction with the CPG Acquisition, UGI had $97.2 million of cash and cash equivalents that was not restricted.

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UGI CORPORATION AND SUBSIDIARIES

The Company’s debt outstanding at March 31, 2009 totaled $2,263.5 million (including current maturities of long-term debt of $10.7 million) compared to $2,205.5 million of debt outstanding (including current maturities of long-term debt of $81.8 million) at September 30, 2008. Total debt outstanding at March 31, 2009 reflects the issuance of $108 million of UGI Utilities Senior Notes in conjunction with the CPG Acquisition. Total debt outstanding at March 31, 2009 principally consists of $862.7 million of Partnership debt, $568.9 million (€428.2 million) of International Propane debt, $818 million of UGI Utilities’ debt, and $13.9 million of other debt.

AmeriGas Partners’ total debt at March 31, 2009 includes long-term debt comprising $779.7 million of AmeriGas Partners’ Senior Notes, $80.0 million of AmeriGas OLP First Mortgage Notes and $3.0 million of other long-term debt. At March 31, 2009, there were no borrowings outstanding under AmeriGas OLP’s revolving credit agreements. In March 2009, AmeriGas OLP repaid $70 million of maturing First Mortgage Notes with cash from operations.

International Propane’s total debt at March 31, 2009 includes long-term debt principally comprising $504.9 million (€380 million) outstanding under Antargaz’ Senior Facilities term loan and $43.8 million (€33.0 million) outstanding under Flaga’s term loan. Total International Propane debt outstanding at March 31, 2009 also includes combined borrowings of $16.9 million (€12.7 million) outstanding under Flaga’s and ZLH’s working capital facilities and $3.3 million (€2.5 million) of other long-term debt.

UGI Utilities’ total debt at March 31, 2009 includes long-term debt comprising $383 million of Senior Notes and $257 million of Medium-Term Notes. Total debt outstanding at March 31, 2009 also includes $178 million outstanding under UGI Utilities’ Revolving Credit Agreement. In connection with the CPG Acquisition, on October 1, 2008, UGI Utilities issued $108 million face amount of 6.375% Senior Notes due 2013.

AmeriGas Partners. 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. In addition, a rapid and precipitous decline in commodity propane prices in late Fiscal 2008 which continued into Fiscal 2009 resulted in greater cash needed by the Partnership to fund counterparty collateral requirements primarily during the three months ended December 31, 2008. These collateral requirements are associated with derivative financial instruments used by the Partnership to manage market price risk associated with fixed sales price commitments to customers principally during the heating-season months of October through March. At March 31, 2009, the Partnership had outstanding collateral deposits of $11.8 million associated with these derivative financial instruments.

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UGI CORPORATION AND SUBSIDIARIES

In order to meet its short-term cash needs, AmeriGas OLP has a $200 million credit agreement (“Credit Agreement”) which expires on October 15, 2011. In addition, on November 14, 2008, AmeriGas OLP entered into a $50 million revolving credit agreement with two major banks (“Supplemental Credit Agreement”) which was terminated on April 17, 2009 in conjunction with the signing of a new $75 million revolving credit facility described below. 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, subject to restrictions in the AmeriGas OLP First Mortgage Notes. The Supplemental Credit Agreement permitted AmeriGas OLP to borrow up to $50 million for working capital and general purposes.

On April 17, 2009, AmeriGas OLP voluntarily terminated its Supplemental Credit Agreement and entered into a new $75 million unsecured revolving credit facility (“2009 Supplemental Credit Agreement”) with three major banks. The 2009 Supplemental Credit Agreement expires on July 1, 2010 and permits AmeriGas OLP to borrow up to $75 million for working capital and general purposes. Except for more restrictive covenants regarding the incurrence of additional indebtedness by AmeriGas OLP, the 2009 Supplemental Credit Agreement has restrictive covenants substantially similar to AmeriGas OLP’s Credit Agreement.

There were no borrowings outstanding under the credit agreements at March 31, 2009. Issued and outstanding letters of credit under the Revolving Credit Facility, which reduce the amount available for borrowings, totaled $77.5 million at March 31, 2009. During the 2009 six-month period, the average daily and peak borrowings outstanding under the credit agreements were $83.8 million and $184.5 million, respectively. During the 2008 six-month period, the average daily and peak borrowings outstanding under the Credit Agreement were $50.1 million and $101 million, respectively. At March 31, 2009, the Partnership’s available borrowing capacity under the credit agreements was $172.5 million.

In order to reduce cash collateral payment obligations and to provide the Partnership with greater borrowing flexibility and a more cost effective use of its credit agreements, UGI has agreed to provide guarantees of up to $50 million to AmeriGas OLP’s propane suppliers through September 30, 2009. At March 31, 2009, the Partnership had $25 million of unused UGI guarantees.

Based on existing cash balances, cash expected to be generated from operations, and borrowings available under AmeriGas OLP’s Credit Agreement and 2009 Supplemental Credit Agreement, the Partnership’s management believes that the Partnership will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2009.

International Propane. Antargaz has a Senior Facilities Agreement that expires on March 31, 2011. The Senior Facilities Agreement consists of (1) a €380 million variable-rate term loan and (2) a €50 million revolving credit facility. Antargaz has executed interest rate swap agreements to fix the underlying euribor or libor rate for the duration of the term loan. Antargaz had no amounts outstanding under the revolving credit facility at March 31, 2009.

Flaga has a working capital facility that provides for borrowings and issuances of guarantees totaling €8.0 million of which borrowings totaling €3.0 million ($4.0 million) were outstanding at March 31, 2009. Flaga’s wholly owned subsidiary ZLH has multi-currency working capital facilities that provide for borrowings of up to €16 million. The ZLH multi-currency facilities are scheduled to expire in June 2009 but management expects to extend or replace the ZLH facilities prior to their expiration. At March 31, 2009, the total amount outstanding under the ZLH facilities was €9.7 million ($12.9 million).

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UGI CORPORATION AND SUBSIDIARIES

UGI Utilities. UGI Utilities may borrow up to a total of $350 million under its Revolving Credit Agreement. This agreement expires in August 2011. At March 31, 2009, UGI Utilities had $178 million in borrowings outstanding under its Revolving Credit Agreement. Borrowings under its Revolving Credit Agreement are classified as bank loans on the Condensed Consolidated Balance Sheets. During the 2009 and 2008 six-month periods, average daily bank loan borrowings were $239.8 million and $190.1 million, respectively, and peak bank loan borrowings totaled $312 million and $267 million, respectively. Peak bank loan borrowings typically occur during the peak heating season months of December and January. During the six months ended March 31, 2009, peak and average daily bank loan borrowings were higher than the prior year due in large part to increases in margin deposits associated with natural gas futures accounts resulting from a decline in wholesale natural gas prices.

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

Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold, and subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a commercial paper conduit of a major bank. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. This two-step transaction is accounted for as a sale of receivables following the provisions of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” Energy Services continues to service, administer and collect trade receivables on behalf of the commercial paper issuer and ESFC. During the six months ended March 31, 2009 and 2008, Energy Services sold trade receivables totaling $785.1 million and $767.3 million, respectively, to ESFC. During the six months ended March 31, 2009 and 2008, ESFC sold an aggregate $384.0 million and $95.5 million, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At March 31, 2009, the outstanding balance of ESFC receivables was $36.0 million which is net of $87.6 million that was sold to the commercial paper conduit and removed from the balance sheet. At March 31, 2008, the outstanding balance of ESFC receivables was $156.3 million of which no amounts were sold to the commercial paper conduit. During the six months ended March 31, 2009, sales of receivables by ESFC to the commercial paper conduit were higher due in large part to the need to fund greater levels of margin deposits in natural gas futures accounts resulting from a decline in wholesale natural gas prices.

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UGI CORPORATION AND SUBSIDIARIES

Dividends and Distributions. On April 29, 2009, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.20 per common share or $0.80 per common share on an annual basis. This quarterly dividend reflects an approximate 4% increase from the previous quarterly dividend rate of $0.1925. The new quarterly dividend rate is effective with the dividend payable on July 1, 2009 to shareholders of record on June 15, 2009. On April 28, 2009, the General Partner’s Board of Directors approved a distribution of $0.67 per Common Unit equal to an annual rate of $2.68 per Common Unit. This quarterly distribution reflects an increase of approximately 5% from the previous quarterly distribution rate of $0.64 per Common Unit. The new quarterly rate is effective with the distribution payable on May 18, 2009 to unitholders of record on May 8, 2009.

Merger of Defined Benefit Pension Plans

Effective December 31, 2008, UGI Utilities merged two of the defined benefit pension plans that it sponsors. The merged plan will maintain separate benefit formulas and specific rights and features of each predecessor plan. As a result of the merger, the Company remeasured the combined plan’s assets and benefit obligations as of December 31, 2008 (the “Remeasurement Date”) and in accordance with SFAS No. 158, “Employers Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R),” recorded an after-tax charge to accumulated other comprehensive loss of $38.7 million. In addition, as a result of the remeasurement, Fiscal 2009 pension expense will increase by approximately $4.2 million for the period subsequent to the Remeasurement Date. For additional information on the merged plan, see Note 7 to condensed consolidated financial statements.

Effect of Recent Market Conditions

The recent unprecedented volatility in credit and capital markets may create additional risks to our businesses in the future. We are exposed to financial market risk resulting from, among other things, changes in interest rates, foreign currency exchange rates and conditions in the credit and capital markets. Recent developments in the credit markets increase our possible exposure to the liquidity and credit risks of our suppliers, counterparties associated with derivative financial instruments and our customers.

We believe that each of our business units has sufficient liquidity in the form of revolving credit facilities, letters of credit and guarantee arrangements to fund business operations including the cash collateral and margin deposit requirements of our product cost management activities. Additionally, we do not have significant amounts of long-term debt maturing or revolving credit agreements terminating in the next two fiscal years. Accordingly, we do not believe that recent conditions in the credit and capital markets will have a significant impact on our liquidity. Although we believe that recent financial market conditions will not have a significant impact on our ability to fund our existing operations, such market conditions could restrict our ability to make a significant acquisition or limit the scope of major capital projects if access to credit and capital markets is limited and could adversely affect our operating results.

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UGI CORPORATION AND SUBSIDIARIES

We are subject to credit risk relating to the ability of counterparties to meet their contractual payment obligations or the potential non-performance of counterparties to deliver contracted commodities or services at contract prices. We monitor our counterparty credit risk exposure in order to minimize credit risk with any one supplier or financial instrument counterparty. Our business units generally have diverse customer bases that span broad geographic, economic and demographic constituencies. No single customer in any of our business units represents more than ten percent of our revenues or operating income. Notwithstanding this diverse customer profile, current economic conditions and conditions in the credit markets could affect the ability of some of our customers to pay timely or result in increased customer bankruptcies which may lead to increased bad debts.

We sponsor funded defined benefit pension plans and other postretirement benefit plans. We believe that the oversight of the plans’ investments is rigorous and that our investment strategies are prudent. During Fiscal 2008 and continuing into Fiscal 2009, actual returns on the pension plans’ investments were significantly below the expected rate of return due to adverse conditions in the financial markets. We do not expect that we will be required to make significant contributions to the pension plans in Fiscal 2009 but, based upon current funding levels, we expect that we will be required to make contributions to the pension plans in Fiscal 2010, although we do not believe such contributions will have a material impact on our liquidity. Furthermore, continued actual returns below the expected rate of return and continued lower interest rates could accelerate the timing and increase the amount of future contributions to these plans in Fiscal 2010 and beyond. Additionally, the reduced benefit plan assets would likely result in increased benefit expense in future years.

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 $442.6 million in the 2009 six-month period compared to $163.6 million in the 2008 six-month period. Cash flow from operating activities before changes in operating working capital was $468.0 million in the 2009 six-month period compared to $429.3 million of such cash flow in the prior-year six-month period. Changes in operating working capital used $25.4 million of operating cash flow in the 2009 six-month period compared to $265.7 million of cash flow used for changes in operating working capital in the 2008 six-month period. The lower 2009 six-month period cash used for changes in accounts receivable reflects the effects on net cash receipts from customers resulting from the lower LPG and natural gas prices and greater sales of receivables by ESFC under its Receivables Facility. Cash provided from changes in inventories was greater in the 2009 six-month period reflecting the effects of lower commodity prices for natural gas and LPG. Cash flow associated with changes in accounts payable used $75.2 million of cash in the 2009 six-month period compared with $159.9 million of cash provided in the prior-year period principally due to the effects of the timing of payments and lower purchased price per gallon of natural gas and LPG.

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UGI CORPORATION AND SUBSIDIARIES

Investing Activities. Net cash flow used in investing activities was $486.6 million in the 2009 six-month period compared with $84.9 million of cash used in the prior-year period. The significant increase in cash used in investing activities principally reflects the net cash used for acquisitions including the CPG Acquisition and the acquisition of the 50% equity interest in ZLH we did not already own. As a result of significant declines in natural gas prices in the 2009 six-month period, restricted cash in our commodity futures brokerage accounts increased $75.6 million compared with a decrease in restricted cash of $11.4 million in the prior-year period. Cash flows from investing activities also include $42.4 million of cash proceeds from the sale of the Partnership’s California LPG storage facility. Capital expenditures were greater in the 2009 six-month period compared with the prior-year period due in large part to higher Energy Services and Antargaz capital expenditures, higher Gas Utility capital expenditures including expenditures of CPG, and greater Partnership capital expenditures including expenditures associated with a system software replacement.

Financing Activities. Cash flow used by financing activities was $1.9 million in the 2009 six-month period compared with $101.1 million in the prior-year period. Cash flow from financing activities in the 2009 six-month period principally reflects the previously mentioned issuance of $108 million of Senior Notes of UGI Utilities to fund a portion of the CPG Acquisition and increases in UGI Utilities bank loans principally to fund a portion of the CPG Acquisition and natural gas brokerage accounts margin deposits. In October 2008, Antargaz repaid its €50 million revolving credit facility loan borrowed in September 2008. In March 2009, Flaga repaid €3 million of maturing term loan debt and AmeriGas OLP repaid $70 million of maturing First Mortgage Notes.

Acquisitions and Divestitures

On October 1, 2008, UGI Utilities acquired all of the issued and outstanding stock of PPL Gas Utilities Corporation (now named UGI Central Penn Gas, Inc., “CPG”), the natural gas distribution utility of PPL Corporation (the “CPG Acquisition”), for cash consideration of $267.6 million plus estimated working capital of $35.4 million. Immediately after the closing of the CPG Acquisition, CPG’s wholly owned subsidiary Penn Fuel Propane, LLC (now named UGI Central Penn, LLC, “CPP”), its retail propane distributor, sold its assets to AmeriGas OLP for cash consideration of $32 million plus estimated working capital of $1.6 million (the “Penn Fuels Acquisition”). CPG distributes natural gas to approximately 76,000 customers in eastern and central Pennsylvania, and also distributes natural gas to several hundred customers in portions of one Maryland county. CPP sold propane to customers principally in eastern Pennsylvania. UGI Utilities funded the CPG Acquisition with a combination of $120 million cash contributed by UGI on September 25, 2008, proceeds from the issuance of $108 million principal amount of 6.375% Senior Notes due 2013 and approximately $75.0 million of borrowings under UGI Utilities’ Revolving Credit Agreement. AmeriGas OLP funded the acquisition of the assets of CPP with borrowings under the AmeriGas Credit Agreement, and UGI Utilities used the $33.6 million of cash proceeds from the sale of the assets of CPP to reduce its revolving credit agreement borrowings.

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UGI CORPORATION AND SUBSIDIARIES

Pursuant to the CPG Acquisition purchase agreement, the purchase price was subject to adjustment for the difference between the estimated $35.4 million and the actual working capital as of the closing date agreed to by both UGI Utilities and PPL Corporation (“PPL”). In February 2009, UGI Utilities and PPL reached an agreement on the working capital adjustment pursuant to which PPL paid UGI Utilities $3.7 million in cash plus interest. UGI Utilities will receive an additional approximately $7.5 million in cash from PPL associated with certain income tax assets later in Fiscal 2009. For additional information on the CPG Acquisition, see Note 9 to condensed consolidated financial statements.

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

Utility Regulatory Matters

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UGI CORPORATION AND SUBSIDIARIES

UGIPNG and CPG Base Rate Filings. On January 28, 2009, UGIPNG and CPG filed separate requests with the PUC to increase base rates for natural gas delivery service by $38.1 million annually for UGIPNG and $19.6 million annually for CPG. The increased rates would fund system improvements and operations necessary to maintain safe and reliable natural gas service. The increase would also fund additional energy assistance for low income customers as well as energy conservation programs for all customers. The PUC has suspended the effective date for the base rate increases to allow for investigation and public hearings. Unless a settlement is reached sooner, the PUC review process will last until late October 2009. As a condition to the PUC’s approval of the acquisition of CPG by UGI Utilities, CPG agreed not to place new base rates into effect prior to August 21, 2009.

Antargaz Competition Authority Matter

In June 2005, officials from France’s General Division of Competition, Consumption and Fraud Punishment (“DGCCRF”) conducted an unannounced inspection of, and obtained documents from, Antargaz’ headquarters building. Management believes that the DGCCRF performed similar unannounced inspections and document seizures at the locations of other distributors of LPG in France, as well as the industry association, Comite Francais du Butane et du Propane (“CFBP”). The DGCCRF apparently sought evidence of unlawful anti-competitive activities affecting the packaged LPG (i.e., cylinder) business in northern France.

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UGI CORPORATION AND SUBSIDIARIES

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our primary market risk exposures are (1) market prices for propane and other LPG, natural gas and electricity; (2) changes in interest rates; and (3) foreign currency exchange rates.

The risk associated with fluctuations in the prices the Partnership and our International Propane operations pay for LPG is principally a result of market forces reflecting changes in supply and demand for propane and other energy commodities. Their profitability is sensitive to changes in LPG supply costs. Increases in supply costs are generally passed on to customers. The Partnership and International Propane may not, however, always be able to pass through product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements, and over-the-counter derivative commodity instruments including price swap and option contracts. In addition, Antargaz hedges a portion of its future U.S. dollar denominated LPG product purchases through the use of forward foreign exchange contracts. Antargaz may also enter into other contracts, similar to those used by the Partnership. Flaga has used and may use derivative commodity instruments to reduce market risk associated with a portion of its LPG purchases. Currently, Flaga’s hedging activities are not material to the Company’s financial position or results of operations. Over-the-counter derivative commodity instruments utilized to hedge forecasted purchases of propane are generally settled at expiration of the contract. These derivative financial instruments contain collateral provisions. As previously mentioned, precipitous declines in propane commodity prices late in Fiscal 2008 which continued into Fiscal 2009 resulted in greater collateral requirements by the Partnership’s derivative instrument counterparties. In order to minimize credit risk associated with its derivative commodity contracts, we monitor established credit limits with the contract counterparties. Although we use derivative financial and commodity instruments to reduce market price risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes.

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UGI CORPORATION AND SUBSIDIARIES

Gas Utility’s tariffs contain clauses that permit recovery of substantially all of the prudently incurred costs of natural gas it sells to its customers. The recovery clauses provide for a periodic adjustment for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments comprising futures contracts traded on the New York Mercantile Exchange (“NYMEX”) to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility’s PGC recovery mechanism. Changes in market value of these contracts may require cash deposits in margin accounts with brokers. At March 31, 2009, Gas Utility had $92.6 million of restricted cash principally associated with natural gas futures accounts with brokers.

Electric Utility purchases its electric power needs from electricity suppliers under fixed-price energy and capacity contracts and, to a much lesser extent, on the spot market. Wholesale prices for electricity can be volatile especially during periods of high demand or tight supply. As previously mentioned and in accordance with POLR settlements approved by the PUC, Electric Utility may increase its POLR rates up to certain limits through December 31, 2009. Electric Utility’s fixed-price contracts with electricity suppliers mitigate most risks associated with the POLR service rate limits in effect through December 2009. With respect to its existing fixed-price power contracts, should any of the counterparties fail to provide electric power under the terms of such contracts, any increases in the cost of replacement power could negatively impact Electric Utility results. In order to reduce this nonperformance risk, Electric Utility has diversified its purchases across several suppliers and entered into bilateral collateral arrangements with certain of them. Changes in prices for electricity could require Electric Utility to provide cash collateral to its supply counterparties.

As previously mentioned, on January 22, 2009, the PUC approved a settlement of a rate filing that provides for Electric Utility to fully recover its default service costs. Under applicable statutory standards, Electric Utility is entitled to fully recover its default service costs. Because Electric Utility will be assured the recovery of prudently incurred costs during the Settlement Term, beginning January 1, 2010, Electric Utility will no longer be subject to the risk that actual costs for purchased power will exceed POLR revenues.

In order to manage market price risk relating to substantially all of Energy Services’ fixed-price sales contracts for natural gas, Energy Services purchases exchange-traded and over-the-counter natural gas futures contracts or enters into fixed-price supply arrangements. Energy Services’ exchange-traded natural gas and electricity futures contracts are traded on the NYMEX and have nominal credit risk. The change in market value of these contracts generally requires daily cash deposits in margin accounts with brokers. At March 31, 2009, Energy Services had $53.3 million of restricted cash on deposit in such margin accounts. Although Energy Services’ fixed-price supply arrangements mitigate most risks associated with its fixed-price sales contracts, should any of the natural gas suppliers under these arrangements fail to perform, increases, if any, in the cost of replacement natural gas would adversely impact Energy Services’ results. In order to reduce this risk of supplier nonperformance, Energy Services has diversified its purchases across a number of suppliers.

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UGI CORPORATION AND SUBSIDIARIES

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

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

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

Asset Management has entered 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, Asset Management enters into price swap and option contracts.

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

Our variable-rate debt includes borrowings under AmeriGas OLP’s Credit Agreement and Supplemental Credit Agreement, UGI Utilities’ Revolving Credit Agreement and a substantial portion of Antargaz’ and Flaga’s debt. These debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has effectively fixed the underlying euribor interest rate on its variable-rate debt through March 2011 and Flaga has fixed the underlying euribor interest rate on a substantial portion of its term loan through September 2011 through the use of interest rate swaps. At March 31, 2009, combined borrowings outstanding under these agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled approximately $196.2 million. Our long-term debt associated with our domestic businesses is typically issued at fixed rates of interest based upon market rates for debt having similar terms and credit ratings. As these long-term debt issues mature, we may refinance such debt with new debt having interest rates reflecting then-current market conditions. This debt may have an interest rate that is more or less than the refinanced debt. In order to reduce interest rate risk associated with near to medium term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements.

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UGI CORPORATION AND SUBSIDIARIES

Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign-denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Realized gains or losses remain in accumulated other comprehensive income until such foreign operations are liquidated. At March 31, 2009, the fair value of unsettled net investment hedges was a gain of $3.9 million, which is included in foreign currency exchange rate risk in the table below. With respect to our net investments in Flaga and Antargaz, a 10% decline in the value of the euro versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value by approximately $59.6 million, which amount would be reflected in other comprehensive income.

The following table summarizes the fair values of unsettled market risk sensitive derivative instruments assets and (liabilities) held at March 31, 2009. Fair values reflect the estimated amounts that we would receive or (pay) to terminate the contracts at the reporting date based upon quoted market prices or the fair value of comparable contracts at March 31, 2009. The table also includes the changes in fair value that would result if there were a 10% adverse change in (1) the market price of LPG; (2) the market price of natural gas; (3) the market price of electricity and electricity transmission congestion; (4) the three-month LIBOR and the three- and six-month Euribor and; (5) the value of the euro versus the U.S. dollar. The fair value of Gas Utility’s exchange-traded natural gas futures contracts comprising losses of $81.9 million at March 31, 2009 are excluded from the table below because any associated net gains or losses are included in Gas Utility’s PGC recovery mechanism.


	Asset (Liability)
				Change in
(Millions of dollars)	Fair Value			Fair Value
March 31, 2009:
LPG commodity price risk	$	(64.6	)	$	(10.9	)
FTRs		1.6			(0.2	)
Natural gas commodity price risk		(42.6	)		(15.7	)
Gasoline commodity price risk		(0.4	)		—
Electricity commodity price risk		(5.6	)		(1.8	)
Interest rate risk		(40.8	)		(6.2	)
Foreign currency exchange rate risk		9.8			(13.7	)

Because our derivative instruments, other than FTRs and gasoline futures contracts, generally qualify as hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” 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.

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UGI CORPORATION AND SUBSIDIARIES

ITEM 4. CONTROLS AND PROCEDURES

(a)

Evaluation of Disclosure Controls and Procedures

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

(b)

Change in Internal Control over Financial Reporting

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

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UGI CORPORATION AND SUBSIDIARIES

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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 million in remediation costs and paid $26 million 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 million. Trial took place in March 2009 and the court’s decision is pending.

Yankee Gas Services Company and Connecticut Light and Power Company v. UGI Utilities, Inc. On September 11, 2006, UGI Utilities received a complaint filed by Yankee Gas Services Company and Connecticut Light and Power Company, subsidiaries of Northeast Utilities (together the “Northeast Companies”), in the United States District Court for the District of Connecticut seeking contribution from UGI Utilities for past and future remediation costs related to MGP operations on thirteen sites owned by the Northeast Companies in nine cities in the State of Connecticut. The Northeast Companies allege that UGI Utilities controlled operations of the plants from 1883 to 1941 through control of its subsidiaries that owned the MGPs. The Northeast Companies estimated that remediation costs for all of the sites would total approximately $215 million and asserted that UGI Utilities is responsible for approximately $103 million of this amount. Based on information supplied by the Northeast Companies and UGI Utilities’ own investigation, UGI Utilities believes that it may have operated one of the sites, Waterbury North, under lease for a portion of its operating history. UGI Utilities is reviewing the Northeast Companies’ estimate that remediation costs at Waterbury North could total $23 million. A trial to determine whether UGI Utilities is responsible for remediation costs concluded on May 1, 2009 and the court’s decision is pending. If necessary, the court will determine the amount of UGI Utilities’ share of those costs in a second trial.

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UGI CORPORATION AND SUBSIDIARIES

ITEM 1A. RISK FACTORS

In addition to the information presented below and the other information set forth 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, 2008, which could materially affect our business, financial condition or future results. The risks described below and 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.

Unforeseen difficulties with the implementation or operation of the Partnership’s information systems could adversely affect our business.

We contracted with third-party consultants to assist us with the design and implementation of an information system that supports the Partnership’s Order-to-Cash business processes. The efficient execution of the Partnership’s business is dependent upon the proper functioning of its internal systems. Any significant failure or malfunction of the Partnership’s information system may result in disruptions of its operations. Our results of operations could be adversely affected if the Partnership encounters unforeseen problems with respect to the operation of this system.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On January 27, 2009, the Annual Meeting of Shareholders of UGI was held. The Shareholders (i) elected all nine nominees to the Board of Directors and (ii) ratified the appointment of PricewaterhouseCoopers LLP as independent registered public accountants.

The number of votes cast for and withheld from election of each director nominee is set forth below. There were no abstentions or broker non-votes in the election of directors.


DIRECTOR NOMINEES	FOR		WITHHELD
Stephen D. Ban		99,228,131		1,507,787
Richard C. Gozon		93,303,203		7,432,715
Lon R. Greenberg		99,004,810		1,731,108
Ernest E. Jones		98,426,982		2,308,936
Anne Pol		98,349,503		2,386,415
M. Shawn Puccio		99,745,368		990,550
Marvin O. Schlanger		97,735,176		3,000,742
Roger B. Vincent		99,651,707		1,084,211
John L. Walsh		99,248,098		1,487,820

The number of votes cast for and against, the number of abstentions and the number of broker non-votes in the ratification of the appointment of PricewaterhouseCoopers LLP is as follows:

For: 99,218,336; Against: 1,309,466; Abstain: 208,116; Broker Non-Voted: 0.

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UGI CORPORATION AND SUBSIDIARIES

ITEM 6. EXHIBITS

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

Incorporation by Reference

Exhibit No.

Exhibit

Registrant

Filing

Exhibit

10.1

UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Employees, dated January 1, 2009.

10.2

UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2009.

10.3

UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for AmeriGas Employees, dated January 1, 2009.

10.4

UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 1, 2009.

10.5

UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2009.

10.6

UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Utilities Employees, dated January 1, 2009.

10.7

UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for Non Employee Directors, dated January 1, 2009.

10.8

UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant for UGI Employees, dated January 1, 2009.

10.9

AmeriGas Propane, Inc. 2000 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., as amended and restated effective January 1, 2005, Restricted Unit Grant Letter dated as of January 1, 2009.

AmeriGas Partners, L.P.

Form 10-Q (3/31/09)

10.2

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UGI CORPORATION AND SUBSIDIARIES

Exhibit No.

Exhibit

Registrant

Filing

Exhibit

10.10

FSS Service Agreement No. 80935, dated as of October 29, 2004, by and between Columbia Gas Transmission, LLC and UGI Central Penn Gas, Inc.

UGI Utilities, Inc.

Form 10-Q (3/31/09)

10.3

10.11

SST Service Agreement No. 80934, dated as of October 29, 2004, by and between Columbia Gas Transmission, LLC and UGI Central Penn Gas, Inc.

UGI Utilities, Inc.

Form 10-Q (3/31/09)

10.4

10.12

Amendment No. 7, dated April 23, 2009, 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.

10.13

Receivables Purchase Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 7 thereto dated April 23, 2009, 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.

10.14

Purchase and Sale Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 2 thereto dated September 5, 2006, by and between UGI Energy Services, Inc. and Energy Services Funding Corporation.

10.15

Credit Agreement, dated as of April 17, 2009, among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as Guarantor, Petrolane Incorporated, as Guarantor, Citizens Bank of Pennsylvania, as Syndication Agent, JPMorgan Chase, N.A., as Documentation Agent and Wachovia Bank, National Association, as Administrative Agent.

AmeriGas Partners, L.P.

Form 8-K (4/17/09)

10.1

31.1

Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2009, 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, 2009, 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, 2009, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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UGI CORPORATION AND SUBSIDIARIES

SIGNATURES

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


	UGI Corporation (Registrant)
Date: May 8, 2009	By:	/s/ Peter Kelly
		Peter Kelly
		Vice President — Finance and Chief Financial Officer

Date: May 8, 2009	By:	/s/ Davinder Athwal
		Davinder Athwal
		Vice President — Accounting and Financial Control and Chief Risk Officer

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UGI CORPORATION AND SUBSIDIARIES

EXHIBIT INDEX


	10.1			UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Employees, dated January 1, 2009.

	10.2			UGI Corporation 2004 Omnibus Equity Compensation Plan Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2009.

	10.3			UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for AmeriGas Employees, dated January 1, 2009.

	10.4			UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 1, 2009.

	10.5			UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2009.

	10.6			UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Utilities Employees, dated January 1, 2009.

	10.7			UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant Letter for Non Employee Directors, dated January 1, 2009.

	10.8			UGI Corporation 2004 Omnibus Equity Compensation Plan Stock Unit Grant for UGI Employees, dated January 1, 2009.

	10.12			Amendment No. 7, dated April 23, 2009, 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.

	10.13			Receivables Purchase Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 7 thereto dated April 23, 2009, 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.

	10.14			Purchase and Sale Agreement, dated as of November 30, 2001, as amended through and including Amendment No. 2 thereto dated September 5, 2006, by and between UGI Energy Services, Inc. and Energy Services Funding Corporation.

	31.1			Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2009, 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, 2009, 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, 2009, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.