UGI (UGI) 10-Q 2012 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended December 31, 2011

OR

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

For the transition period from            to            

Commission file number 1-11071

UGI CORPORATION

(Exact name of registrant as specified in its charter)

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

(610) 337-7000

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	¨

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

At January 31, 2012, there were 112,126,376 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 December 31, 2011, September 30, 2011 and December 31, 2010		1
Condensed Consolidated Statements of Income for the three months ended December 31, 2011 and 2010		2
Condensed Consolidated Statements of Comprehensive Income for the three months ended December 31, 2011 and 2010		3
Condensed Consolidated Statements of Cash Flows for the three months ended December 31, 2011 and 2010		4
Notes to Condensed Consolidated Financial Statements		5 - 29
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		30 - 43
Item 3. Quantitative and Qualitative Disclosures About Market Risk		44 - 47
Item 4. Controls and Procedures		48
Part II Other Information
Item 1. Legal Proceedings		49
Item 1A. Risk Factors		49
Item 6. Exhibits		49 - 51
Signatures		52
Exhibit 31.1
Exhibit 31.2
Exhibit 32
Exhibit 101

i

UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Millions of dollars)

		September 30,			September 30,			September 30,
	December  31, 2011			September  30, 2011			December  31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	229.0		$	238.5		$	139.4
Restricted cash		22.3			17.2			19.4
Accounts receivable (less allowances for doubtful accounts of $38.4, $36.8 and $37.5, respectively)		842.9			546.7			906.9
Accrued utility revenues		53.8			14.8			75.3
Inventories		390.7			363.0			387.3
Deferred income taxes		66.5			44.9			41.1
Utility regulatory assets		8.1			8.6			10.6
Derivative financial instruments		13.4			10.2			23.1
Prepaid expenses and other current assets		41.3			62.2			32.0
Total current assets		1,668.0			1,306.1			1,635.1
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,113.8, $2,080.0 and $1,966.0, respectively)		3,273.8			3,204.5			3,096.8
Goodwill		1,624.7			1,562.2			1,564.7
Intangible assets, net		159.7			147.8			150.1
Other assets		427.7			442.7			361.1
Total assets	$	7,153.9		$	6,663.3		$	6,807.8
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	46.8		$	47.4		$	548.3
Bank loans		421.9			138.7			273.6
Accounts payable		507.4			399.6			668.3
Derivative financial instruments		77.1			49.7			27.7
Other current liabilities		511.6			442.5			506.2
Total current liabilities		1,564.8			1,077.9			2,024.1
Long-term debt		2,115.7			2,110.3			1,448.4
Deferred income taxes		693.6			709.2			601.7
Deferred investment tax credits		4.9			5.0			5.2
Other noncurrent liabilities		575.2			569.8			518.6
Total liabilities		4,954.2			4,472.2			4,598.0
Commitments and contingencies (note 10)
Equity:
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized—300,000,000 shares; issued - 115,507,094, 115,507,094 and 115,434,694 shares, respectively)		939.1			937.4			916.3
Retained earnings		1,143.6			1,085.8			1,052.0
Accumulated other comprehensive (loss) income		(61.8	)		(17.7	)		14.8
Treasury stock, at cost		(26.7	)		(27.8	)		(34.3	)
Total UGI Corporation stockholders’ equity		1,994.2			1,977.7			1,948.8
Noncontrolling interests, principally in AmeriGas Partners		205.5			213.4			261.0
Total equity		2,199.7			2,191.1			2,209.8
Total liabilities and equity	$	7,153.9		$	6,663.3		$	6,807.8

See accompanying notes to condensed consolidated financial statements.

1

UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Millions of dollars, except per share amounts)

		September 30,			September 30,
	Three Months Ended December 31,
	2011			2010
Revenues	$	1,688.8		$	1,765.6
Costs and expenses:
Cost of sales		1,101.8			1,162.6
Operating and administrative expenses		342.4			312.1
Utility taxes other than income taxes		4.1			4.4
Depreciation		52.8			49.2
Amortization		7.5			6.1
Other income, net		(8.1	)		(21.1	)
		1,500.5			1,513.3
Operating income		188.3			252.3
Loss from equity investees		(0.1	)		(0.2	)
Interest expense		(36.0	)		(33.3	)
Income before income taxes		152.2			218.8
Income taxes		(42.1	)		(63.8	)
Net income		110.1			155.0
Less: net income attributable to noncontrolling interests, principally in AmeriGas Partners		(23.1	)		(41.9	)
Net income attributable to UGI Corporation	$	87.0		$	113.1
Earnings per common share attributable to UGI stockholders:
Basic	$	0.78		$	1.02
Diluted	$	0.77		$	1.01
Average common shares outstanding (thousands):
Basic		112,240			110,894
Diluted		113,152			112,416
Dividends declared per common share	$	0.26		$	0.25

See accompanying notes to condensed consolidated financial statements.

2

UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(Millions of dollars)

		September 30,			September 30,
	Three Months Ended December 31,
	2011			2010
Net income	$	110.1		$	155.0
Net (losses) gains on derivative instruments (net of tax of $23.1 and ($11.8), respectively)		(41.3	)		25.9
Reclassifications of net losses on derivative instruments (net of tax of ($8.0) and ($10.9), respectively)		12.5			13.7
Foreign currency adjustments (net of tax of $6.5 and $3.3, respectively)		(22.2	)		(12.1	)
Benefit plans (net of tax of $(0.1) and ($1.5), respectively)		0.1			2.2
Comprehensive income		59.2			184.7
Less: comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners		(16.3	)		(46.7	)
Comprehensive income attributable to UGI Corporation	$	42.9		$	138.0

See accompanying notes to condensed consolidated financial statements.

3

UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Millions of dollars)

		September 30,			September 30,
	Three Months Ended December 31,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	110.1		$	155.0
Reconcile to net cash from operating activities:
Depreciation and amortization		60.3			55.3
Deferred income taxes, net		(16.9	)		(20.7	)
Provision for uncollectible accounts		5.9			7.2
Net change in realized gains and losses deferred as cash flow hedges		(14.1	)		5.4
Other, net		8.1			1.1
Net change in:
Accounts receivable and accrued utility revenues		(283.7	)		(485.8	)
Inventories		(25.3	)		(66.9	)
Utility deferred fuel costs		1.6			15.5
Accounts payable		63.7			280.3
Other current assets		23.3			6.9
Other current liabilities		44.6			10.7
Net cash used by operating activities		(22.4	)		(36.0	)
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(87.4	)		(85.6	)
Acquisitions of businesses, net of cash acquired		(152.8	)		(37.8	)
(Increase) decrease in restricted cash		(5.1	)		15.4
Other		1.9			3.9
Net cash used by investing activities		(243.4	)		(104.1	)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock		(29.2	)		(27.8	)
Distributions on AmeriGas Partners publicly held Common Units		(24.0	)		(22.8	)
Issuances of debt		25.6			—
Repayments of debt		(3.1	)		(3.0	)
Increase in bank loans		265.0			74.9
Receivables Facility net borrowings (repayments)		18.9			(12.1	)
Issuances of UGI Common Stock		3.1			11.6
Other		0.4			1.4
Net cash provided by financing activities		256.7			22.2
EFFECT OF EXCHANGE RATE CHANGES ON CASH		(0.4	)		(3.4	)
Cash and cash equivalents decrease	$	(9.5	)	$	(121.3	)
Cash and cash equivalents:
End of period	$	229.0		$	139.4
Beginning of period		238.5			260.7
Decrease	$	(9.5	)	$	(121.3	)

See accompanying notes to condensed consolidated financial statements.

4

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

1. Nature of Operations

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

We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”), a publicly traded limited partnership, and its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP” or “the Operating Partnership”). AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the “General Partner”), serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as “the Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At December 31, 2011, the General Partner held a 1% general partner interest and 42.8% limited partner interest in AmeriGas Partners and an effective 44.4% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 24,691,209 AmeriGas Partners Common Units (“Common Units”). The remaining 56.2% interest in AmeriGas Partners comprises 32,436,587 Common Units held by the general public as limited partner interests (see Note 15).

Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries (1) conducts LPG distribution businesses in France and, subsequent to the Shell Acquisition described below, in Belgium, the Netherlands and Luxembourg (collectively “Antargaz”); (2) conducts LPG distribution businesses in 11 central and eastern European countries including, subsequent to the Shell Acquisition, in Norway, Sweden and Finland (collectively referred to as “Flaga”); (3) subsequent to the Shell Acquisition conducts an LPG distribution business in the United Kingdom; and (4) conducts an LPG distribution business in the Nantong region of China. On October 14, 2011, UGI, through subsidiaries, acquired Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden for approximately €130 in cash subject to working capital adjustments (the “Shell Acquisition”). We refer to our foreign LPG operations collectively as “International Propane.” Enterprises, through UGI Energy Services, Inc. (“Energy Services”) and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage and energy services business primarily in the Mid-Atlantic region of the United States. In addition, Energy Services’ wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electric generation facilities located in Pennsylvania. The businesses of Energy Services and its subsidiaries, including UGID, are referred to herein collectively as “Midstream & Marketing.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries.

5

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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

2. Significant Accounting Policies

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

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments which we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2011 condensed consolidated balance sheet data were derived from audited financial statements but do not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”). These financial statements should be read in conjunction with the financial statements and related notes included in our Annual Report on Form 10-K for the year ended September 30, 2011 (“Company’s 2011 Annual Financial Statements and Notes”). Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

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

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

6

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:

		September 30,		September 30,
	Three Months Ended December 31,
	2011		2010
Denominator (thousands of shares):
Average common shares outstanding for basic computation		112,240		110,894
Incremental shares issuable for stock options and awards		912		1,522
Average common shares outstanding for diluted computation		113,152		112,416

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

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

Income Taxes.During the three months ended December 31, 2011, the Company changed the U.S. tax status of a foreign entity. As a result of the change in tax status, we now believe it is more likely than not that a portion of our foreign tax credits will be utilized and, accordingly, adjusted our foreign tax credit valuation allowance which reduced income tax expense by $5.5 for the three months ended December 31, 2011.

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

3. Accounting Changes

Adoption of New Accounting Standard

Goodwill Impairment. In September 2011, the Financial Accounting Standards Board (“FASB”) issued guidance on testing goodwill for impairment. The new guidance permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test in GAAP. The more-likely-than-not threshold is deemed as having a likelihood of more than 50 percent. Previous guidance required an

7

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

entity to test goodwill for impairment at least annually by comparing the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit is less than the carrying amount, then the second step of the test must be performed to measure the amount of the impairment loss, if any. Under the new guidance, an entity is not required to calculate fair value of a reporting unit unless the entity determines that it is more likely than not that its fair value is less than its carrying amount. The new guidance does not change how goodwill is calculated or assigned to reporting units, nor does it revise the requirements to test goodwill annually for impairment. The new guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011 with early adoption permitted. We adopted the new guidance for Fiscal 2012.

New Accounting Standard Not Yet Adopted

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

4. Goodwill and Intangible Assets

The Company’s intangible assets comprise the following:

		September 30,			September 30,			September 30,
	December 31, 2011			September 30, 2011			December 31, 2010
Goodwill (not subject to amortization)	$	1,624.7		$	1,562.2		$	1,564.7
Other intangible assets:
Customer relationships, noncompete agreements and other	$	248.8		$	232.1		$	219.8
Trademarks (not subject to amortization)		46.4			47.9			45.4
Gross carrying amount		295.2			280.0			265.2
Accumulated amortization		(135.5	)		(132.2	)		(115.1	)
Net carrying amount	$	159.7		$	147.8		$	150.1

The increases in goodwill and other intangible assets during the three months ended December 31, 2011 principally reflect the effects of acquisitions. Amortization expense of intangible assets was $5.8 and $5.5 for the three months ended December 31, 2011 and 2010, respectively. No amortization is included in cost of sales in the Condensed

8

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Consolidated Statements of Income. As of December 31, 2011 and excluding the impact of the Heritage Acquisition (see Note 15), our expected aggregate amortization expense of intangible assets for the remainder of Fiscal 2012 and the next four fiscal years is as follows: remainder of Fiscal 2012 — $16.8; Fiscal 2013 — $22.0; Fiscal 2014 — $21.0; Fiscal 2015 — $19.0; Fiscal 2016 — $17.1.

5. Segment Information

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

The accounting policies of our reportable segments are the same as those described in Note 2, “Significant Accounting Policies” in the Company’s 2011 Annual Financial Statements and Notes. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership EBITDA may be different from that used by other companies. We evaluate the performance of our International Propane, Gas Utility, Electric Utility and Midstream & Marketing segments principally based upon their income before income taxes.

9

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

5. Segment Information (continued)

Three Months Ended December 31, 2011:

							Reportable Segments
																			International Propane
	Total			Elims.			AmeriGas Propane			Gas Utility			Electric Utility			Midstream & Marketing			Antargaz			Flaga & Other (b)			Corporate & Other (c)
Revenues	$	1,688.8		$	(53.3	)  (d)	$	683.8		$	255.0		$	25.2		$	238.8		$	301.6		$	216.7		$	21.0
Cost of sales	$	1,101.8		$	(52.3	)  (d)	$	443.8		$	141.7		$	15.2		$	198.8		$	175.7		$	168.1		$	10.8
Segment profit:
Operating income (loss)	$	188.3		$	—		$	60.1		$	61.2		$	3.2		$	23.9		$	37.3		$	4.4		$	(1.8	)
Loss from equity investees		(0.1	)		—			—			—			—			—			(0.1	)		—			—
Interest expense		(36.0	)		—			(16.5	)		(10.1	)		(0.5	)		(1.1	)		(6.5	)		(1.0	)		(0.3	)
Income (loss) before income taxes	$	152.2		$	—		$	43.6		$	51.1		$	2.7		$	22.8		$	30.7		$	3.4		$	(2.1	)
Partnership EBITDA (a)							$	83.7
Noncontrolling interests’ net income	$	23.1		$	—		$	23.0		$	—		$	—		$	—		$	0.1		$	—		$	—
Depreciation and amortization	$	60.3		$	—		$	24.2		$	12.1		$	0.9		$	2.8		$	14.1		$	5.5		$	0.7
Capital expenditures	$	88.7		$	—		$	21.6		$	21.8		$	1.0		$	28.1		$	11.1		$	4.8		$	0.3
Total assets (at period end)	$	7,153.9		$	(85.4	)	$	1,975.7		$	2,088.7		$	149.7		$	658.3		$	1,693.7		$	528.9		$	144.3
Bank loans (at period end)	$	421.9		$	—		$	226.0		$	57.7		$	—		$	118.2		$	—		$	20.0		$	—
Goodwill (at period end)	$	1,624.7		$	—		$	696.6		$	182.1		$	—		$	2.8		$	641.9		$	94.3		$	7.0

Three Months Ended December 31, 2010:

							Reportable Segments
																			International Propane
	Total			Elims.			AmeriGas Propane			Gas Utility			Electric Utility			Midstream & Marketing			Antargaz			Flaga & Other (b)			Corporate & Other (c)
Revenues	$	1,765.6		$	(40.1	)  (d)	$	700.2		$	321.1		$	28.9		$	279.6		$	336.0		$	118.9		$	21.0
Cost of sales	$	1,162.6		$	(39.3	)  (d)	$	435.3		$	194.9		$	18.6		$	240.1		$	214.6		$	87.1		$	11.3
Segment profit:
Operating income	$	252.3		$	0.1		$	91.6		$	75.1		$	3.6		$	27.5		$	51.9		$	2.1		$	0.4
Loss from equity investees		(0.2	)		—			—			—			—			—			(0.2	)		—			—
Interest expense		(33.3	)		—			(15.4	)		(10.1	)		(0.5	)		(0.7	)		(5.5	)		(0.9	)		(0.2	)
Income before income taxes	$	218.8		$	0.1		$	76.2		$	65.0		$	3.1		$	26.8		$	46.2		$	1.2		$	0.2
Partnership EBITDA (a)							$	113.3
Noncontrolling interests’ net income	$	41.9		$	—		$	41.5		$	—		$	—		$	—		$	0.4		$	—		$	—
Depreciation and amortization	$	55.3		$	—		$	22.7		$	12.2		$	1.0		$	1.7		$	12.3		$	4.9		$	0.5
Capital expenditures	$	85.6		$	—		$	21.3		$	16.1		$	1.5		$	34.6		$	9.4		$	2.5		$	0.2
Total assets (at period end)	$	6,807.8		$	(89.7	)	$	1,904.5		$	2,061.3		$	141.0		$	548.5		$	1,690.9		$	395.2		$	156.1
Bank loans (at period end)	$	273.6		$	—		$	178.0		$	74.0		$	—		$	—		$	—		$	21.6		$	—
Investments in equity investees (at period end)	$	0.3		$	—		$	—		$	—		$	—		$	—		$	—		$	0.3		$	—
Goodwill (at period end)	$	1,564.7		$	—		$	690.1		$	180.1		$	—		$	2.8		$	591.0		$	93.7		$	7.0

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

		September 30,			September 30,
Three Months Ended December 31,	2011			2010
Partnership EBITDA	$	83.7		$	113.3
Depreciation and amortization		(24.2	)		(22.7	)
Noncontrolling interests (i)		0.6			1.0
Operating income	$	60.1		$	91.6

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

(b) International Propane—Flaga & Other principally comprises FLAGA's retail distrbution businesses, our propane distribution business in China and our propane distribution business in the United Kingdom.

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

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

10

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

6. Energy Services Accounts Receivable Securitization Facility

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

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

During the three months ended December 31, 2011 and 2010, Energy Services transferred trade receivables to ESFC totaling $251.2 and $290.8, respectively. During the three months ended December 31, 2011 and 2010, ESFC sold an aggregate $94.0 and $61.5, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At December 31, 2011, the balance of ESFC receivables was $78.4 and there was $33.2 sold to the commercial paper conduit. At December 31, 2010, the outstanding balance of ESFC receivables was $109.7 and there were no amounts sold to the commercial paper conduit.

7. Utility Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 to the Company’s 2011 Annual Financial Statements and Notes. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets:

11

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

		September 30,		September 30,		September 30,
	December 31,		September 30,		December 31,
	2011		2011		2010
Regulatory assets:
Income taxes recoverable	$	98.7	$	97.9	$	83.6
Underfunded pension and postretirement plans		148.7		150.7		116.3
Environmental costs		19.4		19.5		22.5
Deferred fuel and power costs		14.8		12.2		18.1
Removal costs, net		11.9		12.3		12.2
Other		8.0		7.8		6.3
Total regulatory assets	$	301.5	$	300.4	$	259.0
Regulatory liabilities:
Postretirement benefits	$	11.8	$	11.5	$	10.8
Environmental overcollections		4.7		4.7		7.0
Deferred fuel and power refunds		5.0		6.6		15.2
State tax benefits—distribution system repairs		6.5		6.3		6.7
Other		0.4		0.7		—
Total regulatory liabilities	$	28.4	$	29.8	$	39.7

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

Gas Utility uses derivative financial instruments to reduce volatility in the cost of natural gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Unrealized gains (losses) on such contracts at December 31, 2011, September 30, 2011 and December 31, 2010 were $(2.6), $(3.1) and $2.2, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception related to derivative financial instruments. As a result, Electric Utility’s electricity supply contracts are required to be recorded on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities in accordance with Electric Utility’s DS recovery mechanism. At December 31, 2011, September 30, 2011 and December 31, 2010, the fair values of Electric Utility’s electricity supply contracts were losses of $13.5, $8.7 and $13.4, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

12

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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

8. Defined Benefit Pension and Other Postretirement Plans

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

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

		September 30,			September 30,			September 30,			September 30,
							Other
	Pension Benefits						Postretirement Benefits
	Three Months  Ended December 31,						Three Months  Ended December 31,
	2011			2010			2011			2010
Service cost	$	2.1		$	2.3		$	0.1		$	0.1
Interest cost		6.1			5.9			0.2			0.3
Expected return on assets		(6.4	)		(6.5	)		(0.1	)		(0.1	)
Amortization of:
Prior service cost (benefit)		0.1			0.1			(0.1	)		(0.2	)
Actuarial loss		2.1			2.3			0.1			0.1
Net benefit cost		4.0			4.1			0.2			0.2
Change in associated regulatory liabilities		—			—			0.8			0.8
Net expense	$	4.0		$	4.1		$	1.0		$	1.0

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. It is our general policy to fund amounts for pension benefits equal to at least the minimum contribution required by ERISA. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $32.0 to the Pension Plan during the next twelve months. During the three months ended December 31, 2011 and 2010, the Company made contributions to the Pension Plan of $4.1 and $1.8, respectively. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI.

13

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Gas and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP for postretirement benefits other than pensions. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the three months ended December 31, 2011 and 2010, nor are they expected to be material for all of Fiscal 2012.

We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans. We recorded pre-tax expense associated with these plans of $0.7 and $0.6 for the three months ended December 31, 2011 and 2010, respectively.

9. Debt

In December 2011, Flaga entered into a €19.1 ($24.8 at December 31, 2011) euro-based variable-rate term loan agreement. Proceeds from the term loan were used, in large part, to fund Flaga’s October 2011 acquisition of Shell’s LPG propane businesses in Finland, Norway, Sweden and Denmark. The term loan matures in October 2016 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 1.175% to 2.525%. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 1.79% by entering into an interest rate swap agreement. The effective interest rate on this term loan at December 31, 2011 was 3.85%.

10. Commitments and Contingencies

Environmental Matters

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA terminates at the end of 2013. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At December 31, 2011 and 2010, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $17.8 and $21.3, respectively. We have recorded associated regulatory assets in equal amounts.

14

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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

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

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

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 trial court’s decision is pending.

15

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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

Sag Harbor, New York Matter. By letter dated June 24, 2004, KeySpan Energy (“KeySpan”) informed UGI Utilities that KeySpan has spent $2.3 and expects to spend another $11 to clean up an MGP site it owns in Sag Harbor, New York. KeySpan believes that UGI Utilities is responsible for approximately 50% of these costs as a result of UGI Utilities’ alleged direct ownership and operation of the plant from 1885 to 1902. By letter dated June 6, 2006, KeySpan reported that the New York Department of Environmental Conservation has approved a remedy for the site that is estimated to cost approximately $10. KeySpan has indicated that the cost could be as high as $20. There have been no recent developments in this case.

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

16

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Omaha, Nebraska. By letter dated October 20, 2011, the City of Omaha (“City”) and the Metropolitan Utilities District (“MUD”) notified UGI Utilities that they had been requested by the United States Environmental Protection Agency (“EPA”) to remediate a former manufactured gas plant site located in Omaha, Nebraska. According to a report prepared on behalf of the EPA identifying potentially responsible parties, a former subsidiary of a UGI Utilities’ predecessor is identified as an owner and operator of the site. The City and MUD has requested that UGI Utilities participate in the cost of remediation for this site. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated. In addition, UGI Utilities believes that it has strong defenses to any claims that may arise relating to the remediation of this site. By letter dated November 10, 2011, the EPA notified UGI Utilities of its investigation of the site in Omaha, Nebraska and issued an information request to UGI Utilities. On January 17, 2012, UGI Utilities responded to the EPA’s information request and is cooperating with its investigation.

AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in Saranac Lake, New York on its Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by DEC disclosed contamination related to former MGP operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The Partnership has researched the history of the site and its ownership interest in the site. The Partnership has reviewed the preliminary site characterization study prepared by the DEC, the extent of contamination and the possible existence of other potentially responsible parties. The Partnership communicated the results of its research to DEC in January 2009 and is awaiting a response before doing any additional investigation. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

Other Matters

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

Federal Trade Commission Investigation of Propane Grill Cylinder Filling Practices.On or about November 4, 2011, the General Partner received notice that the Federal Trade Commission (“FTC”) is conducting an antitrust and consumer protection investigation into certain practices of the Partnership which relate to the filling of portable propane cylinders.

17

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

On February 2, 2012, the Partnership received a Civil Investigative Demand from the FTC that requests documents and information concerning, among other things, (i) the Partnership’s decision, in 2008, to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds; (ii) changes in the Partnership’s labeling, advertising, and marketing practices resulting from that decision; (iii) cross-filling and related service arrangements with competitors; and (iv) communications between the Partnership and any competitors regarding the foregoing. The Partnership believes that it will have good defenses to any claims that may result from this investigation. We are not able to assess the financial impact this investigation or any related claims may have on the Partnership.

Purported Class Action Lawsuit.In 2005, Samuel and Brenda Swiger (the “Swigers”) filed what purports to be a class action in the Circuit Court of Harrison County, West Virginia against UGI, an insurance subsidiary of UGI, certain officers of UGI and the General Partner, and their insurance carriers and insurance adjusters. In this lawsuit, the Swigers are seeking compensatory and punitive damages on behalf of the putative class for alleged violations of the West Virginia Insurance Unfair Trade Practice Act, negligence, intentional misconduct, and civil conspiracy. The Court has not certified the class and, in October 2008, stayed the lawsuit pending resolution of a separate, but related class action lawsuit filed against AmeriGas Propane, L.P. in Monongalia County, which was settled in Fiscal 2011. We believe we have good defenses to the claims in this action.

BP America Production Company v. Amerigas Propane, L.P. On July 15, 2011, BP America Production Company (“BP”) filed a complaint against AmeriGas Propane, L.P. in the District Court of Denver County, Colorado, alleging, among other things, breach of contract and breach of the covenant of good faith and fair dealing relating to amounts billed for certain goods and services provided to BP since 2005 (the “Services”). The Services relate to the installation of propane-fueled equipment and appliances, and the supply of propane, to approximately 400 residential customers at the request of and for the account of BP. The complaint seeks an unspecified amount of direct, indirect, consequential, special and compensatory damages, including attorneys’ fees, costs and interest and other appropriate relief. It also seeks an accounting to determine the amount of the alleged overcharges related to the Services. We have substantially completed our investigation of this matter and, based upon the results of that investigation, we believe we have good defenses to the claims set forth in the complaint and the amount of loss will not have a material impact on our results of operations and financial condition.

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

18

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

11. Equity

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

		September 30,			September 30,		September 30,			September 30,			September 30,			September 30,
				UGI Shareholders
	Non- controlling Interests			Common Stock		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Equity
Three Months Ended December 31, 2011:
Balance September 30, 2011	$	213.4		$	937.4	$	1,085.8		$	(17.7	)	$	(27.8	)	$	2,191.1
Net income		23.1					87.0									110.1
Net losses on derivative instruments		(7.8	)							(33.5	)					(41.3	)
Reclassifications of net losses on derivative instruments		1.0								11.5						12.5
Benefit plans										0.1						0.1
Foreign currency translation and transaction adjustments										(22.2	)					(22.2	)
Dividends and distributions		(24.0	)				(29.2	)								(53.2	)
Equity transactions		0.4			1.7								1.1			3.2
Other		(0.6	)													(0.6	)
Balance December 31, 2011	$	205.5		$	939.1	$	1,143.6		$	(61.8	)	$	(26.7	)	$	2,199.7
Three Months Ended December 31, 2010:
Balance September 30, 2010	$	237.1		$	906.1	$	966.7		$	(10.1	)	$	(38.2	)	$	2,061.6
Net income		41.9					113.1									155.0
Net gains on derivative instruments		7.2								18.7						25.9
Reclassifications of net (gains) losses on derivative instruments		(2.4	)							16.1						13.7
Benefit plans										2.2						2.2
Foreign currency translation adjustments										(12.1	)					(12.1	)
Dividends and distributions		(22.8	)				(27.8	)								(50.6	)
Equity transactions		0.4			10.2								3.9			14.5
Other		(0.4	)													(0.4	)
Balance December 31, 2010	$	261.0		$	916.3	$	1,052.0		$	14.8		$	(34.3	)	$	2,209.8

12. Fair Value Measurement

Derivative Financial Instruments

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

19

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

		September 30,			September 30,			September 30,		September 30,
	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities			Significant Other Observable Inputs			Unobservable Inputs
	(Level 1)			(Level 2)			(Level 3)		Total
December 31, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	7.4		$	2.0		$	—	$	9.4
Foreign currency contracts	$	—		$	7.0		$	—	$	7.0
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(43.9	)	$	(34.6	)	$	—	$	(78.5	)
Interest rate contracts	$	—		$	(52.4	)	$	—	$	(52.4	)
September 30, 2011:
Assets:
Derivative financial instruments:
Commodity contracts	$	3.5		$	3.3		$	—	$	6.8
Foreign currency contracts	$	—		$	5.3		$	—	$	5.3
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(28.1	)	$	(16.1	)	$	—	$	(44.2	)
Foreign currency contracts	$	—		$	(3.3	)	$	—	$	(3.3	)
Interest rate contracts	$	—		$	(44.4	)	$	—	$	(44.4	)
December 31, 2010:
Assets:
Derivative financial instruments:
Commodity contracts	$	2.9		$	18.0		$	—	$	20.9
Foreign currency contracts	$	—		$	2.8		$	—	$	2.8
Interest rate contracts	$	—		$	7.2		$	—	$	7.2
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(22.3	)	$	(12.0	)	$	—	$	(34.3	)
Foreign currency contracts	$	—		$	(0.9	)	$	—	$	(0.9	)
Interest rate contracts	$	—		$	(8.0	)	$	—	$	(8.0	)

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

20

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

underlying commodity. The fair values of interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (excluding current maturities of long-term debt) approximate their fair values because of their short-term nature. At December 31, 2011, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $2,162.5 and $2,264.9, respectively. At December 31, 2010, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $1,996.7 and $2,100.5, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt.

Financial instruments other than derivative financial instruments, such as our short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit our credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. The credit risk from trade accounts receivable is limited because we have a large customer base which extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative financial instruments, see Note 13.

13. Disclosures About Derivative Instruments and Hedging Activities

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

Commodity Price Risk

In order to manage market price risk associated with the Partnership’s fixed-price programs which permit customers to lock in the prices they pay for propane principally during the months of October through March, the Partnership uses over-the-counter

21

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units and our International Propane operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. In addition, from time to time, the Partnership enters into price swap agreements to provide market price risk support to some of its wholesale customers. These agreements are not designated as hedges for accounting purposes and the volumes of propane subject to these agreements were not material.

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At December 31, 2011 and 2010, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 9.1 million dekatherms and 25.2 million dekatherms, respectively. At December 31, 2011, the maximum period over which Gas Utility is hedging natural gas market price risk is 9 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with FASB’s guidance in ASC 980 related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 7).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. During Fiscal 2010, Electric Utility determined that it could no longer assert that it would take physical delivery of substantially all of the electricity it had contracted for under its forward power purchase agreements and, as a result, such contracts no longer qualified for the normal purchases and normal sales exception. Because these contracts no longer qualify for the normal purchases and normal sales exception, the fair value of these contracts are required to be recognized on the balance sheet and measured at fair value. At December 31, 2011 and 2010, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $13.5 and $13.4, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Consolidated Balance Sheets. In accordance with ASC 980 related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At December 31, 2011 and 2010, the volumes of Electric Utility’s forward electricity purchase contracts was 816.0 million kilowatt hours and 984.3 million kilowatt hours, respectively. At December 31, 2011, the maximum period over which these contracts extend is 29 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. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient

22

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

electricity transmission capacity on the electric transmission grid. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 14 eastern and midwestern states. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with ASC 980 and reflected in cost of sales through the DS recovery mechanism (see Note 7). At December 31, 2011 and 2010, the volumes associated with Electric Utility FTRs totaled 130.0 million kilowatt hours and 342.0 million kilowatt hours, respectively. Midstream & Marketing’s FTRs are recorded at fair value with changes in fair value reflected in cost of sales. At December 31, 2011 and 2010, the volumes associated with Midstream & Marketing’s FTRs totaled 882.1 million kilowatt hours and 637.8 million kilowatt hours, respectively.

In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas and electricity futures contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. In addition, beginning April 1, 2011, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Because the contracts associated with the anticipated sale of stored natural gas or propane do not qualify for hedge accounting treatment, any gains or losses on the derivative contracts are recognized in earnings prior to gains or losses from the sale of the stored gas. Such derivative gains or losses during Fiscal 2011 were not material. At December 31, 2011, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 3.9 million dekatherms and 3.5 million gallons, respectively. Midstream & Marketing has entered into and may continue to enter into fixed-price propane sales agreements. In order to manage the market price risk relating to substantially all of its fixed-price propane sales agreements, Midstream & Marketing enters into price swap and option contracts.

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

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

		September 30,		September 30,
	Volumes
	December 31,
Commodity	2011		2010
LPG (millions of gallons)		125.4		123.7
Natural gas (millions of dekatherms)		28.0		34.3
Electricity calls (millions of kilowatt-hours)		1,538.3		1,612.7
Electricity puts (millions of kilowatt-hours)		175.4		—

At December 31, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 21 months with a weighted average of 4 months; the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk (excluding Gas Utility) is 34 months with a weighted average of 9 months; and the

23

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity price risk (excluding Electric Utility) is 24 months for electricity call contracts, with a weighted average of 8 months, and 24 months for electricity put contracts, with a weighted average of 13 months. At December 31, 2011, the maximum period over which we are economically hedging electricity congestion with FTRs (excluding Electric Utility) is 5 months.

We account for commodity price risk contracts (other than those contracts that are not eligible for hedge accounting and Gas Utility and Electric Utility contracts that are subject to regulatory treatment) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in accumulated other comprehensive income (“AOCI”) and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales on the Condensed Consolidated Statements of Income. At December 31, 2011, the amount of net losses associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $66.8.

Interest Rate Risk

Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its term loans, in each case through the respective scheduled maturity dates. As of December 31, 2011, the total notional amount of existing variable-rate debt subject to interest rate swap agreements was €442.6. As of December 31, 2010, the total notional amount of existing and anticipated variable-rate debt subject to interest rate swap agreements was €702.5.

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At December 31, 2011 and 2010, the total notional amount of unsettled IRPAs was $173 and $106.5. Our current unsettled IRPA contracts hedge forecasted interest payments associated with the issuance of UGI Utilities’ long-term debt forecasted to occur in September 2012 and September 2013.

We account for interest rate swaps and IRPAs as cash flow hedges. Changes in the fair values of interest rate swaps and IRPAs are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying interest rate risk, until earnings are affected by the hedged interest expense. At such time, gains and losses are recorded in interest expense. At December 31, 2011, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $1.3.

24

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG to occur during the heating-season months of October through March. At December 31, 2011 and 2010, we were hedging a total of $106.0 and $96.1 of U.S. dollar-denominated LPG purchases, respectively. At December 31, 2011, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 27 months with a weighted average of 7 months. We also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. For both December 31, 2011 and 2010, we were hedging a total of €14.5 of our euro-denominated net investments. As of December 31, 2011, such foreign currency contracts extend through September 2012.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. Changes in the fair values of these foreign currency exchange contracts are recorded in AOCI, to the extent effective in offsetting changes in the underlying currency exchange rate risk, until earnings are affected by the hedged LPG purchase, at which time gains and losses are recorded in cost of sales. At December 31, 2011, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $3.1. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.

In conjunction with the Shell Acquisition, in September 2011 we entered into foreign currency exchange transactions to economically hedge the U.S. dollar amount of a substantial portion of the associated euro-denominated purchase price. Through the date of their final expiration in October 2011, these contracts were recorded at fair value with gains or losses recorded in other income (expense). Gains recorded on these contracts during the three months ended December 31, 2011 were not material.

Derivative Financial Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and options contracts generally require cash deposits in margin accounts. At December 31, 2011 and

25

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

2010, restricted cash in brokerage accounts totaled $22.3 and $19.4, respectively. Although we have concentrations of credit risk associated with derivative financial instruments, the maximum amount of loss, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at December 31, 2011. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At December 31, 2011, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

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

	September 30,		September 30,		September 30,	September 30,		September 30,			September 30,
	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value December 31,				Balance Sheet	Fair Value December 31,
	Location	2011		2010		Location	2011			2010
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	1.7	$	16.6	Derivative financial instruments and Other noncurrent liabilities	$	(62.4	)	$	(20.9	)
Foreign currency contracts	Derivative financial instruments and Other assets		7.0		2.8	Derivative financial instruments and Other noncurrent liabilities		—			(0.9	)
Interest rate contracts	Other assets		—		7.2	Derivative financial instruments and Other noncurrent liabilities		(52.4	)		(8.0	)
Total Derivatives Designated as Hedging Instruments		$	8.7	$	26.6		$	(114.8	)	$	(29.8	)
Derivatives Accounted for under ASC 980:
Commodity contracts	Derivative financial instruments	$	—	$	2.6	Derivative financial instruments and Other noncurrent liabilities	$	(16.1	)	$	(13.4	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	$	7.7	$	1.7
Total Derivatives		$	16.4	$	30.9		$	(130.9	)	$	(43.2	)

The following table provides information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three months ended December 31, 2011 and 2010:

26

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Three Months Ended December 31,:

		September 30,			September 30,		September 30,			September 30,		September 30,
	Gain (Loss) Recognized in AOCI and Noncontrolling Interests					Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2011			2010		2011			2010			Interests into Income
Cash Flow
Hedges:
Commodity contracts	$	(57.2	)	$	19.9	$	(19.5	)	$	(20.0	)	Cost of sales
Foreign currency contracts		1.9			2.9		0.9			(1.0	)	Cost of sales
Interest rate contracts		(9.6	)		14.4		(1.9	)		(3.7	)	Interest expense / other income
Total	$	(64.9	)	$	37.2	$	(20.5	)	$	(24.7	)
Net Investment
Hedges:
Foreign currency contracts	$	0.5		$	0.5

Derivatives Not Designated as Hedging Instruments:

		September 30,			September 30,		September 30,
	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
	2011			2010
Commodity contracts	$	3.1		$	(0.1	)	Cost of sales
Commodity contracts		(0.1	)		0.2		Operating expenses / other income
Foreign currency contracts		0.5			—		Other income
Total	$	3.5		$	0.1

The amounts of derivative gains or losses representing ineffectiveness were not material for the three months ended December 31, 2011 and 2010.

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

27

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

14. Inventories

Inventories comprise the following:

		September 30,		September 30,		September 30,
	December 31, 2011		September 30, 2011		December 31, 2010
Non-utility LPG and natural gas	$	249.1	$	222.2	$	234.7
Gas Utility natural gas		87.7		95.6		100.1
Materials, supplies and other		53.9		45.2		52.5
Total inventories	$	390.7	$	363.0	$	387.3

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

The carrying values of natural gas storage inventories released under SCAAs with non-affiliates at December 31, 2011, September 30, 2011 and December 31, 2010 comprising 3.3 billion cubic feet (“bcf”), 3.9 bcf and 3.6 bcf of natural gas was $15.7, $19.0 and $18.9, respectively.

15. Subsequent Event—Partnership Acquisition of Heritage Propane

On January 12, 2012, AmeriGas Partners completed the acquisition of the subsidiaries of Energy Transfer Partners, L.P., a Delaware limited partnership (“ETP”), which operate ETP’s propane distribution business (“Heritage Propane”) for total consideration of approximately $2,600, including $1,460 in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of approximately $1,100 (the “Heritage Acquisition”). The cash consideration for the Heritage Acquisition is subject to adjustments for working capital, cash and the amount of indebtedness of Heritage Propane. The Heritage Acquisition was consummated pursuant to a Contribution and Redemption Agreement dated October 15, 2011, as amended (the “Contribution Agreement”), with ETP, Energy Transfer Partners GP, L.P. and the general partner of ETP (“ETP GP”), and Heritage ETC, L.P., (the “Contributor”). ETP conducted its propane operations in 41 states through its subsidiaries Heritage Operating, L.P. (“HOLP”) and Titan Propane LLC (“Titan”), a Delaware limited partnership and Delaware limited liability company, respectively. According to LP-Gas Magazine rankings, Heritage Propane comprises the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers. The Heritage Acquisition is consistent with UGI’s strategic initiatives and the Partnership’s growth strategies, one of which is to grow the Partnership’s core business.

28

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Pursuant to the Contribution Agreement, the Contributor contributed to AmeriGas Partners, a 99.999% limited partner interest in HOLP; a 100% membership interest in Heritage Operating GP, LLC, a Delaware limited liability company and a holder of a 0.001% general partner interest in HOLP; a 99.99% limited partner interest in Titan Energy Partners, L.P., a Delaware limited partnership and sole member of Titan; and a 100% membership interest in Titan Energy GP, L.L.C., a Delaware limited liability company and holder of a 0.01% general partner interest in Titan Energy Partners, L.P. Immediately prior to the consummation of the Heritage Acquisition, HOLP transferred its interests in all of the net assets constituting HOLP’s cylinder exchange business (“HPX”) to an indirect wholly owned subsidiary of ETP and ETP has agreed to use its best efforts to sell HPX to a third party. To the extent that the gross proceeds of ETP’s sale of HPX exceed an agreed upon amount, AmeriGas Partners will receive a share of such excess and to the extent such gross proceeds of the sale of HPX are less than such amount, AmeriGas Partners will pay Contributor an amount equal to the shortfall. Immediately after the consummation of the Heritage Acquisition and giving effect to the related contribution of Common Units to the Partnership by the General Partner, in order to maintain its general partner interests in AmeriGas Partners and AmeriGas OLP, UGI, through subsidiaries, held a 1% general partner interest and 27.4% limited partner interest in AmeriGas Partners and an effective 29.2% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 Common Units. The remaining 71.6% interest in AmeriGas Partners comprises 62,003,949 publicly held Common Units of which 29,567,362 Common Units are held by ETP. As a result of the Heritage Acquisition and in accordance with GAAP, UGI anticipates recording an increase in its common stockholder’s equity of approximately $175 relating to changes in UGI’s ownership interest in AmeriGas Partners.

The cash portion of the Heritage Acquisition was financed by the issuance by AmeriGas Finance Corp. and AmeriGas Finance LLC, wholly owned finance subsidiaries of AmeriGas Partners (the “Issuers”), of $550 principal amount of 6.75% Senior Notes due May 2020 (the “6.75% Notes”) and $1,000 principal amount of 7.00% Senior Notes due May 2022 (the “7.00% Notes” and, together with the 6.75% Notes, the “Notes”). The Notes are fully and unconditionally guaranteed on a senior unsecured basis by AmeriGas Partners. The Issuers have the right to redeem the Notes, in whole or in part, prior to their maturity subject to certain restrictions. A premium applies to redemptions of the 6.75% Notes and 7.00% Notes through May 2018 and May 2020, respectively. The Issuers may also redeem, at a premium and subject to certain restrictions, up to 35% of the Notes with the proceeds of a registered public equity offering. The Notes and guarantees rank equal in right of payment with all of AmeriGas Partners’ existing senior notes.

Due to the timing of the Heritage Acquisition, pro forma financial information for the three months ended December 31, 2011 cannot be reasonably determined at this time.

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UGI CORPORATION AND SUBSIDIARIES

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

Forward-Looking Statements

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

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors which could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other LPG, oil, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax, consumer protection and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers and retain current customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) large customer, counterparty or supplier defaults; (12) liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and LPG; (13) political, regulatory and economic conditions in the United States and in foreign countries, including foreign currency exchange rate fluctuations, particularly the euro; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (15) changes in commodity market prices resulting in significantly higher cash collateral requirements; (16) reduced distributions from subsidiaries; (17) the timing of development of Marcellus Shale gas production; (18) the timing and success of our acquisitions, commercial initiatives and investments to grow our businesses; and (19) our ability to successfully integrate acquired businesses and achieve anticipated synergies.

These factors, and those factors set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on our business, financial condition or future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

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ANALYSIS OF RESULTS OF OPERATIONS

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

Executive Overview

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

We recorded net income attributable to UGI Corporation of $87.0 million for the 2011 three-month period compared to net income attributable to UGI Corporation of $113.1 million in the prior-year three-month period. Net income attributable to UGI for the current-year period includes the benefit of $5.5 million related to the realization of previously unrecognized foreign tax credits. Net income attributable to UGI for the prior-year period includes a $9.4 million benefit from the reversal of the non-taxable French Competition Authority Matter reserve.

Each of our business units was negatively affected by temperatures that were substantially warmer than normal and significantly warmer than the prior-year comparable period. Average temperatures in our legacy Antargaz and Flaga businesses averaged nearly 22% and 5% warmer than normal, respectively. Domestically, average temperatures in our AmeriGas Propane service territories were 11.9% and 9.9% warmer than normal and the prior year, respectively, and temperatures in our Gas Utility service territory were approximately 12.2% and 18.6% warmer than normal and the prior year, respectively. At our Midstream & Marketing business, greater income from storage activities in the 2011 three-month period was more than offset by lower commodity and capacity management total margin and lower operating results from electric generation, both of which reflect the impact of the warmer weather on demand. The lower electric generation results in the 2011 three-month period include the effects of a planned maintenance outage at the Conemaugh generation station and greater operating and depreciation expenses including expenses associated with the repowered Hunlock Station. During the 2010 three-month period, the Hunlock Station was not operating while it was transitioning to a natural gas-fired facility.

Differences in exchange rates between the U.S. dollar and the euro during the 2011 three-month period compared with the 2010 three-month period did not have a material impact on the comparison of our year-over-year International Propane results.

After the end of the quarter, on January 12, 2012, AmeriGas Partners completed the acquisition of the subsidiaries of Energy Transfer Partners, L.P., (“ETP”) which operate ETP’s propane distribution business (“Heritage Propane”) for total consideration of approximately $2.6 billion, including $1.46 billion in cash and 29,567,362 AmeriGas Partners Common Units with a fair value at date of acquisition of approximately $1.1 billion (the “Heritage Acquisition”). The cash consideration for the Heritage Acquisition is subject to adjustments based on working capital, cash and the amount of indebtedness of Heritage Propane. The acquired business conducts its propane operations in 41

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states through Heritage Operating, L.P. (“HOLP”) and Titan Propane LLC (“Titan” and together with HOLP, “Heritage Propane”). According to LP-Gas Magazine rankings, Heritage Propane comprises the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers. Heritage Propane is a complementary business and the acquisition provides the Partnership with increased size and scale and presents opportunities for potential administrative and operational synergies. Immediately after the Heritage Acquisition, UGI, through subsidiaries, owns a combined effective 29% of the Partnership. For more information on the Heritage Acquisition, see “Subsequent Event — Acquisition of the Propane Operations of Energy Transfer Partners” below and Note 15 to condensed consolidated financial statements.

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

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

		September 30,			September 30,			September 30,		September 30,			September 30,			September 30,
	Three Months Ended December 31,											Variance - Unfavorable
(Millions of dollars)	2011			% of Total			2010		% of Total			Amount			%
AmeriGas Propane	$	12.1			13.9	%	$	20.6		18.2	%	$	(8.5	)		(41.3	)%
International Propane (a)		31.0			35.6	%		33.2		29.4	%		(2.2	)		(6.6	)%
Gas Utility		31.1			35.7	%		39.2		34.7	%		(8.1	)		(20.7	)%
Electric Utility		1.5			1.7	%		1.7		1.5	%		(0.2	)		(11.8	)%
Midstream & Marketing		13.9			16.0	%		18.1		16.0	%		(4.2	)		(23.2	)%
Corporate & Other		(2.6	)		(2.9	)%		0.3		0.2	%		(2.9	)		N.M.
Net income attributable to UGI Corporation	$	87.0			100.0	%	$	113.1		100.0	%	$	(26.1	)		(23.1	)%

N.M.—Variance not meaningful.

(a) 2011 net income includes the benefit of $5.5 million related to the realization of previously unrecognized foreign tax credits. 2010 net income from International Propane includes $9.4 million of net income from a nontaxable reserve reversal at Antargaz associated with the French Competition Authority Matter.

AmeriGas Propane:

		September 30,			September 30,			September 30,		September 30,
For the three months ended December 31,	2011			2010			Decrease
(Millions of dollars)
Revenues	$	683.8		$	700.2		$	(16.4	)	(2.3	)%
Total margin (a)	$	240.0		$	264.9		$	(24.9	)	(9.4	)%
Partnership EBITDA (b)	$	83.7		$	113.3		$	(29.6	)	(26.1	)%
Operating income	$	60.1		$	91.6		$	(31.5	)	(34.4	)%
Retail gallons sold (millions)		220.9			256.4			(35.5	)	(13.8	)%
Degree days—% (warmer) than normal (c)		(11.9	)%		(2.2	)%		—		—

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

(b) Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 5 to condensed consolidated financial statements).

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

Based upon heating degree-day data, average temperatures in the Partnership’s service territories averaged 11.9% warmer than normal during the 2011 three-month period and approximately 9.9% warmer than the prior-year period. In particular, temperatures in the month of December 2011 were nearly 12% warmer than normal and 16% warmer than the prior year. Retail propane gallons sold were 13.8% lower than in the prior-year period principally reflecting the impact of the significantly warmer weather.

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Retail propane revenues decreased $21.0 million during the 2011 three-month period reflecting an $83.6 million decrease as a result of the lower retail volumes sold partially offset by a $62.6 million increase as a result of higher average retail propane selling prices due in large part to higher commodity costs. Wholesale propane revenues increased $4.5 million principally reflecting a $5.9 million increase resulting from higher year-over-year wholesale selling prices partially offset by a $1.4 million decrease on lower volumes sold. Average wholesale propane commodity prices at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 14% higher in the 2011 three-month period compared to such prices in the 2010 three-month period. Total revenues from fee income and other ancillary sales and services were virtually unchanged from the prior-year period. Total cost of sales increased $8.5 million, to $443.8 million, principally reflecting the effects of the previously mentioned higher 2011 three-month period propane commodity prices ($62.1 million) offset in large part by the impact of the lower volumes sold.

Total margin decreased $24.9 million in the 2011 three-month period primarily due to the lower retail propane volumes sold ($32.1 million) partially offset by modestly higher average retail unit margins.

Partnership EBITDA in the 2011 three-month period decreased $29.6 million reflecting the lower total margin ($24.9 million), slightly higher operating and administrative expenses ($3.5 million) and lower other income ($1.5 million). The $3.5 million increase in operating and administrative expenses include incremental expenses associated with the Heritage Acquisition ($3.7 million) and higher vehicle expenses ($2.6 million) partially offset by lower compensation and benefits expenses. Operating income in the 2011 three-month period decreased $31.5 million reflecting the $29.6 million decrease in Partnership EBITDA and slightly higher depreciation and amortization expense associated with acquisitions and plant and equipment expenditures made since the 2010 three-month period.

International Propane:

		September 30,			September 30,			September 30,		September 30,
For the three months ended December 31,	2011			2010			Increase (Decrease)
(Millions of dollars)
Revenues	$	518.3		$	454.9		$	63.4		13.9	%
Total margin (a)	$	174.5		$	153.2		$	21.3		13.9	%
Operating income	$	41.7		$	54.0	(b)	$	(12.3	)	(22.8	)%
Income before income taxes	$	34.1		$	47.4	(b)	$	(13.3	)	28.1	%
Retail gallons sold (millions) (c)		164.1			139.6			24.5		17.6	%
Antargaz degree days—% (warmer) colder than normal		(21.7	)		12.4			—		—
Flaga degree days—% (warmer) colder than normal		(4.9	)		8.1			—		—

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

(b) Includes $9.4 million from a nontaxable reserve reversal at Antargaz associated with the French Competition Authority Matter.

(c) Excludes retail gallons from operations in China.

International Propane operating results in the 2011 three-month period reflect the operating results of Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden acquired in October 2011 (the “Shell Acquisitions”). Based upon heating degree day data, temperatures across Europe were warmer than normal and significantly warmer than the prior-year period. Specifically, weather at

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Antargaz was approximately 22% warmer than normal in the 2011 three-month period compared to weather that was approximately 12% colder than normal in the prior-year period. Average LPG wholesale product prices in northwest Europe were slightly lower in the 2011 three-month period compared with such prices in the prior-year period. During the 2011 three-month period, the average wholesale commodity price for propane in northwest Europe was approximately 9% lower than such prices in the prior-year period while the average wholesale commodity price for butane was essentially equal to the prior-year period. Our retail LPG gallons sold were higher than the prior-year period, notwithstanding the effects of the significantly warmer weather, reflecting an incremental 48 million gallons associated with the Shell Acquisitions.

Our International Propane base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. The functional currency of a significant portion of our International Propane results is denominated in euros. During each of the 2011 and 2010 three-month periods, the average un-weighted translation rate was approximately $1.35 per euro.

International Propane revenues increased $63.4 million or 13.9%, notwithstanding the significantly warmer weather, principally reflecting the effects of the Shell Acquisitions ($147.1 million). Cost of sales increased to $343.8 million in the 2011 three-month period from $301.7 million in the prior-year period, an increase of 14.0%, principally reflecting incremental cost of sales from the Shell Acquisitions ($113.3 million).

Total margin increased $21.3 million or 13.9% principally reflecting incremental margin from the Shell Acquisitions ($33.8 million) partially offset by lower total margin at our legacy Antargaz and Flaga units resulting from the lower volumes sold principally due to the significantly warmer weather.

International Propane operating income was $12.3 million lower than the prior year principally reflecting the higher total margin ($21.3 million) more than offset by incremental expenses associated with the acquired businesses, including operating and administrative costs, depreciation and acquisition integration costs, and the absence of the $9.4 million of other income from the reversal at Antargaz of a nontaxable reserve associated with the French Competition Authority Matter recorded in the prior-year three-month period. The $13.3 million decrease in income before income taxes principally reflects the previously mentioned decrease in operating income ($12.3 million) and a $1.1 million increase in interest expense, principally interest expense on Antargaz’ long-term debt which was refinanced in March 2011.

Gas Utility:

		September 30,			September 30,			September 30,		September 30,
For the three months ended December 31,	2011			2010			Increase (Decrease)
(Millions of dollars)
Revenues	$	255.0		$	321.1		$	(66.1	)	(20.6	)%
Total margin (a)	$	113.3		$	126.2		$	(12.9	)	(10.2	)%
Operating income	$	61.2		$	75.1		$	(13.9	)	(18.5	)%
Income before income taxes	$	51.1		$	65.0		$	(13.9	)	(21.4	)%
System throughput— billions of cubic feet (“bcf”)		49.0			48.9			0.1		0.2	%
Degree days—% (warmer) colder than normal (b)		(12.2	)%		7.9	%		—		—

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

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

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Temperatures in the Gas Utility service territory in the 2011 three-month period based upon heating degree days were 12.2% warmer than normal and 18.6% warmer than the prior-year period. Total distribution system throughput was about equal to last year notwithstanding the warmer weather principally reflecting greater throughput to certain non-weather-sensitive low-margin interruptible delivery service customers. Excluding total volumes to interruptible delivery service customers, Gas Utility system throughput declined 5.3 bcf in the 2011 three-month period principally reflecting the effects of the significantly warmer weather on throughput to core market customers. Gas Utility’s core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.

Gas Utility revenues decreased $66.1 million during the 2011 three-month period principally reflecting a decline in revenues from retail core market customers ($52.3 million) and a decline in revenues from off-system sales ($9.8 million). The decrease in retail core market revenues principally reflects the effects of the lower retail core market volumes ($31.5 million) and lower average purchased gas cost (“PGC”) rates resulting from lower natural gas prices. Under Gas Utility’s PGC recovery mechanisms, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $141.7 million in the 2011 three-month period compared with $194.9 million in the prior-year period reflecting the previously mentioned lower retail core-market sales and the lower average PGC rates.

Gas Utility total margin decreased $12.9 million in the 2011 three-month period. The decrease principally reflects a $9.7 million decrease in core market margin and lower firm delivery service total margin ($2.3 million). Gas Utility total margin in the current year period includes incremental margin from the August 2011 base rate increase at CPG Gas.

The decreases in Gas Utility operating income and income before income taxes during the 2011 three-month period principally reflects the previously mentioned decrease in total margin ($12.9 million).

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Electric Utility:

		September 30,		September 30,		September 30,		September 30,
For the three months ended December 31,	2011		2010		Decrease
(Millions of dollars)
Revenues	$	25.2	$	28.9	$	(3.7	)	(12.8	)%
Total margin (a)	$	8.5	$	8.8	$	(0.3	)	(3.4	)%
Operating income	$	3.2	$	3.6	$	(0.4	)	(11.1	)%
Income before income taxes	$	2.7	$	3.1	$	(0.4	)	(12.9	)%
Distribution sales—millions of kilowatt hours (“gwh”)		244.0		250.5		(6.5	)	(2.6	)%

(a) Total margin represents total revenues less total cost of sales and revenue-related taxes, i.e. Electric Utility gross receipts taxes, of $1.4 million and $1.6 million for the three-month periods ended December 31, 2011 and 2010, respectively. For financial statement purposes, revenue-related taxes are included in “Utility taxes other than income taxes” on the condensed consolidated statements of income.

Electric Utility’s kilowatt-hour sales in the 2011 three-month period were 2.6% lower than in the prior-year three-month period on heating degree day weather that was 18.4% warmer. The significantly warmer weather reduced sales to those Electric Utility customers who use electricity for heating purposes. Electric Utility revenues were less than the prior year principally as a result of lower average Default Service (“DS”) rates and to a lesser extent the lower sales volumes. Under Electric Utility’s DS rates, Electric Utility records the cost of electricity sold to customers at amounts included in DS rates. The difference between actual costs and the amounts included in DS 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 recovery mechanism, increases or decreases in the cost of electricity have no direct effect on margin. Electric Utility cost of sales declined to $15.2 million in the 2011 three-month period compared to $18.6 million in the 2010 three-month period principally reflecting the effects of the lower average DS rates in the current-year period and the effects of the lower sales.

Electric Utility total margin was $0.3 million lower in the 2011 three-month period principally the result of the lower sales.

Electric Utility 2011 three-month period operating income and income before income taxes each declined $0.4 million principally reflecting the lower total margin.

Midstream & Marketing:

		September 30,		September 30,		September 30,		September 30,
For the three months ended December 31,	2011		2010		Increase (Decrease)
(Millions of dollars)
Revenues	$	238.8	$	279.6	$	(40.8	)	(14.6	)%
Total margin (a)	$	40.0	$	39.5	$	0.5		1.3	%
Operating income	$	23.9	$	27.5	$	(3.6	)	(13.1	)%
Income before income taxes	$	22.8	$	26.8	$	(4.0	)	(14.9	)%

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

Midstream & Marketing total revenues decreased $40.8 million in the 2011 three-month period principally reflecting lower total revenues from natural gas marketing activities ($41.2 million), the result of modestly lower volumes sold and lower average natural gas prices, and lower electric generation and capacity management revenues. These decreases were partially offset by

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greater retail power revenue ($5.9 million), the result of higher sales, and greater storage services revenues ($3.3 million). The increase in natural gas storage income reflects the previously disclosed April 1, 2011 transfer of natural gas storage assets to Midstream & Marketing.

The $0.5 million increase in Midstream & Marketing’s total margin principally reflects greater natural gas storage income ($6.3 million) largely offset by lower natural gas marketing margin ($2.3 million), lower capacity management margin ($2.3 million) and lower electric generation total margin ($1.6 million). The decrease in electric generation total margin principally reflects the effects of a planned maintenance outage at the Conemaugh generation station during the 2011 three-month period.

Midstream & Marketing’s operating income in the 2011 three-month period was $3.6 million lower than the prior-year period reflecting the previously mentioned increase in total margin ($0.5 million) more than offset by greater operating, administrative and depreciation expenses associated with electric generation assets ($2.7 million), including incremental expenses associated with the repowered Hunlock Station and higher fuel and maintenance expenses associated with the Conemaugh generation station, and greater energy marketing and storage services’ operating and administrative expenses. The Hunlock Station was out of service last year as it transitioned to a natural gas-fired generation station. The decline in income before income taxes reflects the lower operating income ($3.6 million) and greater interest expense ($0.4 million) principally from Energy Services’ credit facility borrowings. These borrowings were used to return a portion of capital contributions previously made by UGI to fund major Midstream & Marketing capital projects.

Interest Expense and Income Taxes. Our consolidated interest expense was $2.7 million higher in the 2011 three-month period principally reflecting higher AmeriGas Propane interest expense ($1.1 million) on greater Partnership long-term debt outstanding; greater International Propane interest expense ($1.1 million); and slightly higher Midstream & Marketing interest expense. Our effective tax rate for the three months ended December 31, 2011 was lower than in the prior year. Among other things, current-year income taxes were reduced by $5.5 million as a result of the realization of previously unrecognized foreign tax credits. The prior-year three-month period effective tax rate was reduced by, among other things, the effect of the reversal of the $9.4 million reserve associated with the French Competition Authority Matter at Antargaz which was not subject to tax.

FINANCIAL CONDITION AND LIQUIDITY

Financial Condition

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

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Our cash and cash equivalents, excluding cash in commodity futures brokerage accounts restricted from withdrawal, totaled $229.0 million at December 31, 2011 compared with $238.5 million at September 30, 2011. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at December 31, 2011 and September 30, 2011, UGI had $44.8 million and $81.4 million, respectively, of cash and cash equivalents.

The Company’s debt outstanding at December 31, 2011 totaled $2,584.4 million (including current maturities of long-term debt of $46.8 million and bank loan borrowings of $421.9 million) compared to debt outstanding at September 30, 2011 of $2,296.4 million (including current maturities of long-term debt of $47.4 million and bank loan borrowings of $138.7 million). Total debt outstanding at December 31, 2011 consists of (1) $1,158.3 million of Partnership debt; (2) $597.5 million (€461.0 million) of International Propane debt; (3) $697.7 million of UGI Utilities’ debt; (4) $118.3 million of Midstream & Marketing debt; and (5) $12.6 million of other debt. Long-term debt maturing in the next twelve months principally comprises $40 million of UGI Utilities Medium-Term Notes.

AmeriGas Partners’ total debt at December 31, 2011 includes $920 million of AmeriGas Partners’ Senior Notes, $226 million of AmeriGas OLP bank loan borrowings and $12.3 million of other long-term debt.

International Propane’s total debt at December 31, 2011 includes $492.5 million (€380 million) outstanding under Antargaz’ Senior Facilities term loan and a combined $81.1 million (€62.6 million) outstanding under Flaga’s three term loans. Total International Propane debt outstanding at December 31, 2011 also includes combined borrowings of $20.0 million (€15.4 million) outstanding under Flaga’s working capital facilities and $3.9 million (€3.0 million) of other long-term debt.

UGI Utilities’ total debt at December 31, 2011 includes $383 million of Senior Notes and $257 million of Medium-Term Notes. There was $57.7 million outstanding under UGI Utilities’ Revolving Credit Agreement at December 31, 2011.

AmeriGas Partners. At December 31, 2011, AmeriGas OLP had a $325 million unsecured credit agreement (“2011 AmeriGas Credit Agreement”). Concurrently with the Heritage Acquisition, on January 12, 2012, the 2011 AmeriGas Credit Agreement was amended to, among other things, increase the total amount available to $525 million, extend its expiration date to October 2016, and amend certain financial covenants for a limited time period as a result of the Heritage Acquisition.

At December 31, 2011, there were $226 million of borrowings outstanding under the 2011 AmeriGas Credit Agreement which are classified as bank loans on the Condensed Consolidated Balance Sheets. Issued and outstanding letters of credit under AmeriGas OLP credit agreements, which reduce the amount available for borrowings, totaled $35.7 million at both December 31, 2011 and 2010. The average daily and peak bank loan borrowings outstanding under the 2011 AmeriGas Credit Agreement during the 2011 three-month period were $136.3 million and $226 million, respectively. The average daily and peak bank loan borrowings outstanding under predecessor credit agreements during the 2010 three-month period were $135.1 million and $201 million, respectively. At December 31, 2011, the Partnership’s available borrowing capacity under the 2011 AmeriGas Credit Agreement was $63.3 million.

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Excluding financing transactions related to the Heritage Acquisition, the Partnership’s management believes that the Partnership will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2012 from existing cash balances, cash expected to be generated from operations and borrowings available under the 2011 AmeriGas Credit Agreement.

International Propane. Antargaz has a Senior Facilities Agreement with a consortium of banks (“2011 Senior Facilities Agreement”) consisting of a €380 million variable-rate term loan and a €40 million revolving credit facility. Scheduled maturities under the term loan are €38 million due May 2014, €34.2 million due May 2015, and €307.8 million due March 2016. Antargaz has entered into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan at an average rate of approximately 2.45% through September 2015 and, thereafter, at a rate of approximately 3.71% through the date of the term loan’s final maturity in March 2016. At December 31, 2011, the effective interest rate on Antargaz’ term loan was 4.66%. Antargaz had no amounts outstanding under the revolving credit facility at December 31, 2011 or 2010.

Antargaz’ management believes that it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2012 with cash generated from operations and borrowings under its revolving credit facility.

In December 2011, Flaga entered into a €19.1 million ($24.8 million at December 31, 2011) euro-based variable-rate term loan agreement. Proceeds from the term loan were used, in large part, to fund Flaga’s October 2011 acquisition of Shell’s LPG propane businesses in Finland, Norway, Sweden and Denmark. The term loan matures in October 2016 and bears interest at three-month euribor rates plus a margin. The margin on such borrowings ranges from 1.175% to 2.525%. Flaga has effectively fixed the euribor component of the interest rate on this term loan at 1.79% by entering into an interest rate swap agreement. The effective interest rate on this term loan at December 31, 2011 was 3.85%.

Flaga has three principal working capital facilities comprising (1) a €46 million multi-currency working capital facility which includes an uncommitted €6 million overdraft facility (the “Flaga 2011 Multi-currency Working Capital Facility”) and (2) two euro-denominated working capital facilities that provide for borrowings and issuances of guarantees totaling €12 million (the “Euro Facilities”). The Flaga 2011 Multi-currency Working Capital Facility expires in September 2014 and the Euro Facilities expire in March 2012. Flaga expects to extend the Euro Facilities prior to their expiration. At December 31, 2011 and 2010, there were €13.4 million ($17.3 million) and €16.1 million ($21.6 million) of borrowings outstanding under Flaga’s principal working capital facilities, respectively. These amounts are reflected as bank loans on the Condensed Consolidated Balance Sheets.

Issued and outstanding guarantees, which reduce available borrowings under these facilities, totaled €19.7 million ($25.6 million) at December 31, 2011. The average daily and peak bank loan borrowings outstanding under Flaga’s principal working capital facilities during the 2011 three-month period were €12.3 million and €13.4 million, respectively. The average daily and peak bank loan borrowings outstanding under Flaga working capital facilities during the 2010 three-month period were €18.2 million and €23.4 million, respectively.

Based upon cash generated from operations and borrowings available under its working capital facilities, Flaga’s management believes it will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2012.

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UGI Utilities.UGI Utilities may borrow up to a total of $300 million under the UGI Utilities Revolving Credit Agreement. The UGI Utilities Revolving Credit Agreement expires in May 2012 but may be extended to October 2015 if UGI Utilities receives approval by the PUC. UGI Utilities expects to receive such approval prior to the May 2012 termination date. At December 31, 2011, there was $57.7 million outstanding under the UGI Utilities Revolving Credit Agreement which are classified as bank loans. During the 2011 and 2010 three-month periods, average daily bank loan borrowings were $29.7 million and $49.3 million, respectively, and peak bank loan borrowings totaled $70.5 million and $90 million, respectively. Peak bank loan borrowings typically occur during the heating season months of December and January.

Based upon cash expected to be generated from Gas Utility and Electric Utility operations and borrowings available under the UGI Utilities Revolving Credit Agreement, UGI Utilities’ management believes that it will be able to meet its anticipated contractual and projected cash commitments during Fiscal 2012.

Midstream & Marketing. Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $170 million (including a $50 million sublimit for letters of credit) which expires in August 2013. There were $85 million of borrowings outstanding under this facility at December 31, 2011. During the three months ended December 31, 2011, Energy Services borrowed $75 million under this facility and made a cash dividend to UGI of $55 million.

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

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

During the three months ended December 31, 2011 and 2010, Energy Services transferred trade receivables totaling $251.2 million and $290.8 million, respectively, to ESFC. During the three months ended December 31, 2011 and 2010, ESFC sold an aggregate $94.0 million and $61.5 million, respectively, of undivided interests in its trade receivables to the commercial paper conduit. At December 31, 2011, the balance of ESFC receivables was $78.4 million and there was $33.2 million sold to the commercial paper conduit. At December 31, 2010, the outstanding balance of ESFC receivables was $109.7 million and there were no amounts sold to the commercial paper conduit. During the three months ended December 31, 2011 and 2010, peak amounts sold under the Receivables Facility were $75 million and $31.7 million, respectively, and average daily amounts sold were $20.9 million and $4.2 million, respectively.

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Based upon cash expected to be generated from operations, borrowings available under the Energy Services Credit Agreement and Receivables Facility, and capital contributions from UGI, Midstream & Marketing’s management believes that Midstream & Marketing will be able to meet its anticipated contractual commitments and projected cash needs during Fiscal 2012.

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 used by operating activities was $22.4 million in the 2011 three-month period compared to $36.0 million in the 2010 three-month period. Cash flow from operating activities before changes in operating working capital was $153.4 million in the 2011 three-month period compared to $203.3 million in the prior-year three-month period. The decrease in cash flow from operating activities before changes in operating working capital reflects in large part the effects of the lower operating results in the 2011 three-month period. Cash required to fund changes in operating working capital totaled $175.8 million in the 2011 three-month period compared to $239.3 million in the prior-year three-month period. The lower cash required to fund changes in operating working capital in the 2011 three-month period reflects, among other things, lower increases in customer accounts receivable and inventories reflecting the impact of the lower volume sales due to warmer weather at most of our operations and the effects of the timing of payments of LPG on accounts payable.

Investing Activities. Cash flow used in investing activities was $243.3 million in the 2011 three-month period compared with $104.1 million of cash used in the prior-year period. Cash used for acquisitions of businesses in the 2011 three-month period was $152.8 million compared with only $37.8 million paid in the prior-year period reflecting the acquisition of certain Shell European LPG businesses in the 2011 three-month period.

Financing Activities. Cash flow provided by financing activities was $256.7 million in the 2011 three-month period compared with $22.2 million in the prior-year period. Net bank loan borrowings totaled $265.0 million in the 2011 three-month period including a $57.7 million increase in bank loans at UGI Utilities and a $130.5 million increase at AmeriGas OLP. In addition, during the three months ended December 31, 2011, Energy Services borrowed $75.0 million under the Energy Services Credit Agreement. A portion of the proceeds of the borrowings were dividended to UGI and used to fund a portion of the acquisition of certain of Shell’s European LPG businesses (see European LPG Acquisitions below). Increases in long-term debt reflect the issuance of a €19.1 million ($24.8 million) term loan by Flaga.

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European LPG Acquisitions

On October 14, 2011, UGI, through subsidiaries, acquired Shell’s LPG distribution businesses in the United Kingdom, Belgium, the Netherlands, Luxembourg, Denmark, Finland, Norway and Sweden for approximately €130 in cash, subject to working capital adjustments. The acquired businesses delivered a combined approximately 300 million gallons of LPG in 2010. The purchase price for these businesses was funded at the time of acquisition principally from existing cash at UGI including a cash dividend from Midstream & Marketing with borrowings under the Energy Services Credit Agreement.

Subsequent Event—Acquisition of the Propane Operations of Energy Transfer Partners

On January 12, 2012, AmeriGas Partners completed the acquisition of the subsidiaries of Energy Transfer Partners, L.P. (“ETP”) which operate ETP’s propane distribution business (“Heritage Propane”) for total consideration of approximately $2.6 billion, including $1.46 billion in cash and 29,567,362 AmeriGas Partners Common Units with a fair value of approximately $1.1 billion (the “Heritage Acquisition”). The cash consideration for the Heritage Acquisition is subject to adjustments for working capital, cash and the amount of indebtedness of Heritage Propane. The acquired business conducts its propane operations in 41 states through Heritage Operating, L.P. (“HOLP”) and Titan Propane LLC. (“Titan” and together with HOLP, “Heritage Propane”). According to LP-Gas Magazine rankings, Heritage Propane comprises the third largest retail propane distributor in the United States, delivering over 500 million gallons to more than one million retail propane customers. Heritage Propane is a complementary business and the acquisition provides the Partnership with increased size and scale and presents opportunities for potential administrative and operational synergies.

The cash portion of the Heritage Acquisition was financed by the issuance of $550 million principal amount of 6.75% Senior Notes due May 2020 (the “6.75% Notes”) and $1 billion principal amount of 7.00% Senior Notes due May 2022 (the “7.00% Notes”). The 6.75% Notes and 7.00% Notes are fully and unconditionally guaranteed on a senior unsecured basis by AmeriGas Partners. The 6.75% Notes and the 7.00% Notes and guarantees rank equal in right of payment with all of AmeriGas Partners’ existing senior notes.

Immediately after the consummation of the Heritage Acquisition and giving effect to the related contribution of Common Units to the Partnership by the General Partner, in order to maintain its general partner interests in AmeriGas Partners and AmeriGas OLP, UGI, through subsidiaries, held a 1% general partner interest and 27.4% limited partner interest in AmeriGas Partners and an effective 29.2% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 Common Units. The remaining 71.6% interest in AmeriGas Partners comprises 62,003,949 publicly held Common Units of which 29,567,362 Common Units are held by ETP. As a result of the Heritage Acquisition and in accordance with GAAP, UGI anticipates recording an increase in its common stockholder’s equity of approximately $175 million relating to changes in UGI’s ownership interest in AmeriGas Partners.

For additional information on the Heritage Acquisition, see Note 15 to condensed consolidated financial statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

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

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the 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.

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

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

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

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

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

The fair value of unsettled commodity price risk sensitive derivative instruments held at December 31, 2011 (excluding those Gas Utility and Electric Utility commodity derivative instruments which are refundable to or recoverable from customers) was a loss of $53.0 million. A hypothetical 10% adverse change in (1) the market price of LPG and gasoline; (2) the market price of natural gas; and (3) the market price of electricity and electricity transmission congestion charges would result in a decrease in such fair value of $31.9 million at December 31, 2011.

Interest Rate Risk

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

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Our variable-rate debt at December 31, 2011 includes our bank loan borrowings and Antargaz’ and Flaga’s variable rate term loans. These debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz and Flaga have effectively fixed the underlying euribor interest rates on their term loans through their scheduled maturity dates through the use of interest rate swaps. At December 31, 2011 combined borrowings outstanding under these variable-rate debt agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled $421.9 million.

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

The fair value of unsettled interest rate risk sensitive derivative instruments held at December 31, 2011 was a loss of $52.4 million. A hypothetical 10% adverse change in the three-month euribor would result in a decrease in fair value of $7.6 million.

Foreign Currency Exchange Rate Risk

Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. We use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Realized gains or losses on net investment hedges remain in accumulated other comprehensive income until such foreign operations are liquidated. At December 31, 2011, the fair value of unsettled net investment hedges was a gain of $1.5 million. With respect to our net investments in our International Propane operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value at December 31, 2011 by approximately $83.5 million, which amount would be reflected in other comprehensive income.

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

The fair value of unsettled foreign currency exchange rate risk sensitive derivative instruments held at December 31, 2011 was a gain of $7.0 million. A hypothetical 10% adverse change in the value of the euro versus the U.S. dollar would result in a decrease in fair value of $11.9 million.

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

Derivative Financial Instrument Credit Risk

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We are exposed to risk of loss in the event of nonperformance by our derivative financial instrument counterparties. Our derivative financial instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures and option contracts generally require cash deposits in margin accounts. Declines in natural gas, LPG and electricity product costs can require our business units to post collateral with counterparties or make margin deposits to brokerage accounts. At December 31, 2011 and 2010, restricted cash in brokerage accounts totaled $22.3 million and $19.4 million, respectively.

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ITEM 4.  CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

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

(b) Change in Internal Control over Financial Reporting

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

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PART II OTHER INFORMATION

ITEM 1.  LEGAL  PROCEEDINGS

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

ITEM 1A. RISK FACTORS

In addition to the other information presented in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended September 30, 2011, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

ITEM 6. EXHIBITS

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

Incorporation by Reference

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
2.1	Amendment No. 1, dated as of December 1, 2011, to the Contribution and Redemption Agreement, dated as of October 15, 2011, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P.	AmeriGas Partners, L.P.	Form 8-K (12/1/11)	2.1
2.2	Amendment No. 2, dated as of January 11, 2012, to the Contribution and Redemption Agreement, dated as of October 15, 2011, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P.	AmeriGas Partners, L.P.	Form 8-K (1/11/12)	2.1
2.3	Letter Agreement, dated as of January 11, 2012, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage ETC, L.P. and AmeriGas Partners, L.P.	AmeriGas Partners, L.P.	Form 8-K (1/11/12)	2.2
4.1	Indenture, dated as of January 12, 2012, among AmeriGas Finance Corp., AmeriGas Finance LLC, AmeriGas Partners, L.P., as guarantor, and U.S. Bank National Association, as trustee.	AmeriGas Partners, L.P.	Form 8-K (1/12/12)	4.1
4.2	First Supplemental Indenture, dated as of January 12, 2012, among AmeriGas Finance Corp., AmeriGas Finance LLC, AmeriGas Partners, L.P., as guarantor, and U.S. Bank National Association, as trustee.	AmeriGas Partners, L.P.	Form 8-K (1/12/12)	4.2

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Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.1	Contingent Residual Support Agreement, dated as of January 12, 2012, among Energy Transfer Partners, L.P., AmeriGas Finance LLC, AmeriGas Finance Corp., AmeriGas Partners, L.P. and, for certain limited purposes only, UGI Corporation.	AmeriGas Partners, L.P.	Form 8-K (1/11/12)	10.1
10.2	Unitholder Agreement, dated as of January 12, 2012, by and among Heritage ETC, L.P., AmeriGas Partners, L.P., and, for limited purposes, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., and Energy Transfer Equity, L.P.	AmeriGas Partners, L.P.	Form 8-K (1/11/12)	10.2
10.3	Amendment No. 2, dated as of January 12, 2012 to the Credit Agreement dated as of June 21, 2011 by and among AmeriGas Propane, L.P., as Borrower, AmeriGas Propane, Inc., as a Guarantor, Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and Issuing Lender, Wells Fargo Securities, LLC, as Sole Lead Arranger and Sole Book Manager and the financial institutions from time to time party thereto.	AmeriGas Partners, L.P.	Form 8-K (1/11/12)	10.3
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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UGI CORPORATION AND SUBSIDIARIES

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
32	Certification by the Chief Executive Officer and the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101 INS*	XBRL.Instance
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase
101.LAB*	XBRL Taxonomy Extension Labels Linkbase
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase

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

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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: February 3, 2012	By:	/s/ John L. Walsh
		John L. Walsh
		President and Chief Operating Officer (Principal Financial Officer)

Date: February 3, 2012	By:	/s/ Davinder S. Athwal
		Davinder S. Athwal
		Vice President—Accounting and Financial Control and Chief Risk Officer

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EXHIBIT INDEX

31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2011, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification by the Chief Executive Officer and the Principal Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2011, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL.Instance
101.SCH*	XBRL Taxonomy Extension Schema
101.CAL*	XBRL Taxonomy Extension Calculation
101.DEF*	XBRL Taxonomy Extension Definition
101.LAB*	XBRL Taxonomy Extension Labels
101.PRE*	XBRL Taxonomy Extension Presentation

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