Edgar Filing: UGI CORP /PA/

UGI Corp Q1 12.31.2013 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended December 31, 2013



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

For the transition period from ________ to ________

Commission file number 1-11071

UGI CORPORATION

(Exact name of registrant as specified in its charter)



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

460 North Gulph Road, King of Prussia, PA		19406
(Address of principal executive offices)		(Zip Code)

(610) 337-1000

(Registrant’s telephone number, including area code)

______________________________________

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

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

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



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

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

At January 31, 2014, there were 114,759,004 shares of UGI Corporation Common Stock, without par value, outstanding.

Table of Contents

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, 2013, September 30, 2013 and December 31, 2012	1

Condensed Consolidated Statements of Income for the three months ended December 31, 2013 and 2012	2

Condensed Consolidated Statements of Comprehensive Income for the three months ended December 31, 2013 and 2012	3

Condensed Consolidated Statements of Cash Flows for the three months ended December 31, 2013 and 2012	4

Condensed Consolidated Statements of Changes in Equity for the three months ended December 31, 2013 and 2012	5

Notes to Condensed Consolidated Financial Statements	6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3. Quantitative and Qualitative Disclosures About Market Risk	38

Item 4. Controls and Procedures	41

Part II Other Information

Item 1A. Risk Factors	42

Item 6. Exhibits	43

Signatures	44

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Millions of dollars)



	December 31, 2013			September 30, 2013			December 31, 2012 (Revised, See Note 3)
ASSETS
Current assets:
Cash and cash equivalents	$	418.1		$	389.3		$	348.1
Restricted cash	4.5			8.3			6.9
Accounts receivable (less allowances for doubtful accounts of $43.8, $39.5 and $39.9, respectively)	1,204.0			745.6			989.3
Accrued utility revenues	66.4			18.9			59.0
Inventories	412.4			365.5			378.5
Deferred income taxes	23.0			10.6			36.9
Utility regulatory assets	0.4			8.2			3.6
Derivative financial instruments	51.6			23.8			9.3
Prepaid expenses and other current assets	47.1			57.1			58.3
Total current assets	2,227.5			1,627.3			1,889.9
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,630.9, $2,560.3 and $2,359.1, respectively)	4,517.1			4,480.2			4,271.4
Goodwill	2,884.5			2,871.0			2,835.0
Intangible assets, net	598.8			610.6			646.8
Other assets	435.6			419.7			495.2
Total assets	$	10,663.5		$	10,008.8		$	10,138.3
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	67.2		$	67.2		$	164.4
Bank loans	421.5			227.9			333.2
Accounts payable	691.4			472.3			579.3
Derivative financial instruments	20.8			30.0			88.1
Other current liabilities	678.6			627.5			614.6
Total current liabilities	1,879.5			1,424.9			1,779.6
Long-term debt	3,549.1			3,542.2			3,358.4
Deferred income taxes	980.2			962.3			923.0
Deferred investment tax credits	4.2			4.3			4.5
Other noncurrent liabilities	531.8			527.2			634.0
Total liabilities	6,944.8			6,460.9			6,699.5
Commitments and contingencies (Note 10)
Equity:
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized—300,000,000 shares; issued — 115,783,794, 115,783,794 and 115,644,794 shares, respectively)	1,210.0			1,208.1			1,170.0
Retained earnings	1,397.9			1,308.3			1,227.9
Accumulated other comprehensive income (loss)	32.2			8.4			(37.3		)
Treasury stock, at cost	(30.5		)	(32.3		)	(29.4		)
Total UGI Corporation stockholders’ equity	2,609.6			2,492.5			2,331.2
Noncontrolling interests, principally in AmeriGas Partners	1,109.1			1,055.4			1,107.6
Total equity	3,718.7			3,547.9			3,438.8
Total liabilities and equity	$	10,663.5		$	10,008.8		$	10,138.3

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Millions of dollars, except per share amounts)



	Three Months Ended December 31,
	2013			2012 (Revised, See Note 3)
Revenues	$	2,315.9		$	2,018.7
Costs and expenses:
Cost of sales (excluding depreciation shown below)	1,429.9			1,215.5
Operating and administrative expenses	431.5			426.9
Utility taxes other than income taxes	4.2			4.3
Depreciation	78.6			72.5
Amortization	15.4			15.3
Other income, net	(7.4		)	(10.0		)
	1,952.2			1,724.5
Operating income	363.7			294.2
Interest expense	(59.3		)	(61.5		)
Income before income taxes	304.4			232.7
Income tax expense	(86.9		)	(64.9		)
Net income	217.5			167.8
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners	(95.5		)	(65.3		)
Net income attributable to UGI Corporation	$	122.0		$	102.5
Earnings per common share attributable to UGI Corporation stockholders:
Basic	$	1.06		$	0.91
Diluted	$	1.05		$	0.90
Average common shares outstanding (thousands):
Basic	114,825			113,136
Diluted	116,470			114,490
Dividends declared per common share	$	0.2825		$	0.27

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(Millions of dollars)



	Three Months Ended December 31,
	2013			2012 (Revised, See Note 3)
Net income	$	217.5		$	167.8
Other comprehensive income (loss):
Net gains (losses) on derivative instruments (net of tax of $(7.5) and $1.4, respectively)	40.5			(5.3		)
Reclassifications of net (gains) losses on derivative instruments (net of tax of $2.0 and $(3.5), respectively)	(13.8		)	17.4
Foreign currency adjustments (net of tax of $(3.7) and $(4.0), respectively)	12.3			16.1
Benefit plans (net of tax of $0.1 and $(0.2), respectively)	0.4			0.3
Other comprehensive income	39.4			28.5
Comprehensive income	256.9			196.3
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	(111.1		)	(75.9		)
Comprehensive income attributable to UGI Corporation	$	145.8		$	120.4

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Millions of dollars)



	Three Months Ended December 31,
	2013			2012 (Revised, See Note 3)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	217.5		$	167.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	94.0			87.8
Deferred income taxes, net	(19.7		)	1.6
Provision for uncollectible accounts	8.9			7.4
Unrealized (gains) losses on derivative instruments	(5.2		)	1.9
Other, net	0.8			(1.6		)
Net change in:
Accounts receivable and accrued utility revenues	(508.2		)	(408.1		)
Inventories	(45.1		)	(19.3		)
Utility deferred fuel costs, net of changes in unsettled derivatives	2.1			4.8
Accounts payable	245.9			164.8
Other current assets	5.2			31.2
Other current liabilities	76.7			(7.2		)
Net cash provided by operating activities	72.9			31.1
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(133.1		)	(91.3		)
Acquisitions of businesses, net of cash acquired	(20.8		)	—
Decrease (increase) in restricted cash	3.8			(3.9		)
Other, net	1.3			1.8
Net cash used by investing activities	(148.8		)	(93.4		)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(32.4		)	(30.6		)
Distributions on AmeriGas Partners Common Units	(58.0		)	(55.2		)
Repayments of debt	(4.1		)	(6.3		)
Increase in bank loans	188.2			134.7
Receivables Facility net borrowings	5.5			33.0
Issuances of UGI Common Stock	1.7			10.6
Other	0.2			1.3
Net cash provided by financing activities	101.1			87.5
EFFECT OF EXCHANGE RATE CHANGES ON CASH	3.6			3.0
Cash and cash equivalents increase	$	28.8		$	28.2
Cash and cash equivalents:
End of period	$	418.1		$	348.1
Beginning of period	389.3			319.9
Increase	$	28.8		$	28.2

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

(Millions of dollars)



	Three Months Ended December 31,
	2013			2012 (Revised, See Note 3)
Common stock, without par value
Balance, beginning of period	$	1,208.1		$	1,157.7
Common Stock issued in connection with employee and director plans, net of tax withheld	0.2			9.6
Dividend reinvestment plan	—			0.5
Excess tax benefits realized on equity-based compensation	0.3			1.3
Stock-based compensation expense	1.4			0.9
Balance, end of period	$	1,210.0		$	1,170.0
Retained earnings
Balance, beginning of period	$	1,308.3		$	1,156.0
Net income attributable to UGI Corporation	122.0			102.5
Cash dividends on Common Stock	(32.4		)	(30.6		)
Balance, end of period	$	1,397.9		$	1,227.9
Accumulated other comprehensive income (loss)
Balance, beginning of period	$	8.4		$	(55.2	)
Net gains (losses) on derivative instruments, net of tax	15.3			(3.4		)
Reclassification of net (gains) losses on derivative instruments, net of tax	(4.2		)	4.9
Benefit plans, net of tax	0.4			0.3
Foreign currency, net of tax	12.3			16.1
Balance, end of period	$	32.2		$	(37.3	)
Treasury stock
Balance, beginning of period	$	(32.3	)	$	(28.7	)
Common Stock issued in connection with employee and director plans, net of tax withheld	1.9			7.2
Dividend reinvestment plan	—			0.2
Reacquired common stock - employee and director plans	(0.1		)	(8.1		)
Balance, end of period	$	(30.5	)	$	(29.4	)
Total UGI Corporation stockholders’ equity	$	2,609.6		$	2,331.2
Noncontrolling interests
Balance, beginning of period	$	1,055.4		$	1,085.6
Net income attributable to noncontrolling interests, principally in AmeriGas Partners	95.5			65.3
Net gains (losses) on derivative instruments	25.2			(1.9		)
Reclassification of net (gains) losses on derivative instruments	(9.6		)	12.5
Dividends and distributions	(58.0		)	(55.2		)
Other	0.6			1.3
Balance, end of period	$	1,109.1		$	1,107.6
Total equity	$	3,718.7		$	3,438.8

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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


1.	Nature of Operations

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

We conduct a domestic retail propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”). AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”) and prior to its merger with AmeriGas OLP on July 1, 2013 (the “Merger”), AmeriGas OLP’s principal operating subsidiary Heritage Operating, L.P. (“HOLP”). AmeriGas OLP after the Merger, and AmeriGas OLP and HOLP prior to the Merger, are collectively referred to herein as the “Operating Partnership.” AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the “General Partner”), serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as the “Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At December 31, 2013, the General Partner held a 1% general partner interest and 25.3% limited partner interest in AmeriGas Partners and an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners at December 31, 2013, comprises 69,073,909 publicly held Common Units of which 22,067,362 Common Units are held by a subsidiary of Energy Transfer Partners, L.P. (“ETP”) as a result of the January 12, 2012, acquisition of substantially all of ETP’s propane operations (“Heritage Propane”). In January 2014, ETP sold 9,200,000 of the Common Units it held in an underwritten public offering, pursuant to its registration rights in its unitholder agreement. AmeriGas Partners did not receive any proceeds from the sale of the Common Units by ETP.

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

Enterprises, through UGI Energy Services, LLC (which was formerly known as UGI Energy Services, Inc. prior to its merger with and into UGI Energy Services, LLC effective October 1, 2013) and its subsidiaries conduct an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business primarily in the Mid-Atlantic region of the United States. In addition, UGI Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. These businesses are referred to herein collectively as “Midstream & Marketing.” UGI Energy Services, LLC subsequent to the merger and UGI Energy Services, Inc. prior to the merger are referred to herein as “Energy Services.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries.

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


2.	Significant Accounting Policies

Our condensed consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the public’s and ETP’s limited partner interests in the Partnership, and

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests.We eliminate all significant intercompany accounts and transactions when we consolidate. Entities in which we do not have control but have significant influence over operating and financial policies are accounted for by the equity method. Investments in business entities that are not publicly traded and in which we hold less than 20% of voting rights are accounted for using the cost method. Undivided interests in natural gas production assets and an electricity generation facility are consolidated on a proportionate basis.

The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2013, condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”).

These financial statements should be read in conjunction with the financial statements and related notes included in our Annual Report on Form 10-K for the year ended September 30, 2013 (“Company’s 2013 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 principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.

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

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



	Three Months Ended December 31,
	2013	2012
Denominator (thousands of shares):
Average common shares outstanding for basic computation	114,825	113,136
Incremental shares issuable for stock options and awards	1,645	1,354
Average common shares outstanding for diluted computation	116,470	114,490

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

Changes in accumulated other comprehensive income (“AOCI”) during the three months ended December 31, 2013, are as follows:

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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



							Foreign
							Currency
	Postretirement			Derivative			Translation
	Benefit Plans			Instruments			Adjustments		Total
Balance, September 30, 2013	$	(16.4	)	$	(26.9	)	$	51.7	$	8.4
Other comprehensive income before reclassification adjustments (after-tax)	—			40.5			12.3		52.8
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0.3			(15.8		)	—		(15.5		)
Reclassification adjustments tax (expense) benefit	0.1			2.0			—		2.1
Reclassification adjustments (after-tax)	0.4			(13.8		)	—		(13.4		)
Other comprehensive income	0.4			26.7			12.3		39.4
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	—			(15.6		)	—		(15.6		)
Other comprehensive income attributable to UGI	0.4			11.1			12.3		23.8
Balance, December 31, 2013	$	(16.0	)	$	(15.8	)	$	64.0	$	32.2

For additional information on amounts reclassified from AOCI relating to derivative instruments see Note 12 to condensed consolidated financial statements.

Income Taxes. In December 2013, the French Parliament approved the Finance Bill for 2014 and amended the Finance Bill for 2013 (collectively, the “Finance Bills”). Among other things, the Finance Bills limit Antargaz’ ability to deduct interest expense for income tax purposes on certain intercompany debt and temporarily increases the corporate surtax rate for a period of two years. Based upon our review of the Finance Bills and interpretive guidance currently available, provisions of the Finance Bills associated with the deductibility of interest expense on certain intercompany debt at Antargaz applies retroactively to such interest expense incurred during Fiscal 2013. During the three months ended December 31, 2013, the Company recorded additional income taxes of $5.7 to reflect the effects of the retroactive provisions of the Finance Bills associated with the deductibility of interest expense on certain intercompany debt.

Reclassifications. Certain prior period amounts have been reclassified to conform to current period presentation.

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


3.	Revisions of Condensed Consolidated Financial Statements

During the preparation of the Fiscal 2013 consolidated financial statements, management concluded that it had incorrectly accounted for certain commodity derivative instruments as cash flow hedges. Management had incorrectly applied the hedge accounting criteria when designating certain commodity derivative instruments at its Midstream & Marketing businesses as cash flow hedges. Management has discontinued the use of hedge accounting for Midstream & Marketing’s commodity derivative instruments and reports changes in the fair values of unsettled commodity derivative instruments, and gains and losses on settled commodity derivatives for which the associated forecasted transaction has not yet occurred, in net income.

The Company had previously determined that the impact of the error was not material to the Company’s historical condensed consolidated financial statements for the three months ended December 31, 2012. However, in conjunction with its conclusion that the error was material to certain other quarterly periods in Fiscal 2013 not presented herein, management decided to revise its consolidated financial statements for the three months ended December 31, 2012 which are included herein. Accordingly, the accompanying condensed consolidated financial statements as of and for the three months ended December 31, 2012, have been revised to report changes in the fair values of unsettled commodity derivative instruments and gains and losses on settled commodity

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

derivative instruments for which the associated forecasted transactions have not yet occurred in cost of sales or revenues in the Condensed Consolidated Statement of Income rather than in other comprehensive income.

The following tables set forth the effects of the revision on affected line items within the Company’s previously reported condensed consolidated financial statements for the three months ended December 31, 2012. Also included in the adjustment columns in the tables below are certain other immaterial corrections that the Company made, including, but not limited to, adjustments to correct the Partnership’s accounting for certain customer credits and to correct the classification of deferred income tax assets, as well as certain other minor adjustments related principally to the timing of certain expense and income accruals.

Condensed Consolidated Balance Sheet



	December 31, 2012
	As Previously Reported			Adjustment			As Revised
Assets:
Accounts receivable	$	999.2		$	(9.9	)	$	989.3
Deferred income taxes	$	57.6		$	(20.7	)	$	36.9
Prepaid expenses and other current assets	$	57.5		$	0.8		$	58.3
Property, plant and equipment	$	4,270.8		$	0.6		$	4,271.4
Liabilities and equity:
Accounts payable	$	580.7		$	(1.4	)	$	579.3
Other current liabilities	$	616.8		$	(2.2	)	$	614.6
Deferred income taxes	$	946.1		$	(23.1	)	$	923.0
Other noncurrent liabilities	$	629.8		$	4.2		$	634.0
Retained earnings	$	1,238.1		$	(10.2	)	$	1,227.9
Accumulated other comprehensive loss	$	(43.7	)	$	6.4		$	(37.3	)
Noncontrolling interests	$	1,110.5		$	(2.9	)	$	1,107.6

Condensed Consolidated Statement of Income



	For the three months ended December 31, 2012
	As Previously Reported			Adjustment			As Revised
Revenues	$	2,023.2		$	(4.5	)	$	2,018.7
Cost of sales	$	1,218.8		$	(3.3	)	$	1,215.5
Depreciation	$	71.8		$	0.7		$	72.5
Operating income	$	296.1		$	(1.9	)	$	294.2
Interest expense	$	(60.3	)	$	(1.2	)	$	(61.5	)
Income before income taxes	$	235.8		$	(3.1	)	$	232.7
Income taxes	$	(65.1	)	$	0.2		$	(64.9	)
Net income	$	170.7		$	(2.9	)	$	167.8
Deduct net income attributable to noncontrolling interests	$	(68.1	)	$	2.8		$	(65.3	)
Net income attributable to UGI Corporation	$	102.6		$	(0.1	)	$	102.5
Basic earnings per common share	$	0.91					$	0.91
Diluted earnings per common share	$	0.90					$	0.90

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Condensed Consolidated Statement of Comprehensive Income



	For the three months ended December 31, 2012
	As Previously Reported			Adjustment			As Revised
Net income	$	170.7		$	(2.9	)	$	167.8
Net losses on derivative instruments	$	(9.3	)	$	4.0		$	(5.3	)
Reclassifications of net losses on derivative instruments	$	21.8		$	(4.4	)	$	17.4
Other comprehensive income	$	28.9		$	(0.4	)	$	28.5
Comprehensive income	$	199.6		$	(3.3	)	$	196.3
Deduct comprehensive income attributable to noncontrolling interests	$	(78.7	)	$	2.8		$	(75.9	)
Comprehensive income attributable to UGI Corporation	$	120.9		$	(0.5	)	$	120.4

Condensed Consolidated Statements of Cash Flows



	For the three months ended December 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:	As Previously Reported			Adjustment			As Revised
Net income	$	170.7		$	(2.9	)	$	167.8
Depreciation and amortization	$	87.1		$	0.7		$	87.8
Net change in realized gains and losses deferred as cash flow hedges	$	1.9		$	(1.9	)	$	—
Unrealized gains on derivative instruments	$	—		$	1.9		$	1.9
Other, net	$	(3.8	)	$	2.2		$	(1.6	)

Condensed Consolidated Statements of Changes in Equity



	For the three months ended December 31, 2012
	As Previously Reported			Adjustment			As Revised
Retained earnings	$	1,238.1		$	(10.2	)	$	1,227.9
Accumulated other comprehensive loss	$	(43.7	)	$	6.4		$	(37.3	)
Noncontrolling interests	$	1,110.5		$	(2.9	)	$	1,107.6


4.	Accounting Changes

Adoption of New Accounting Standards

Disclosures about Reclassifications Out of Accumulated Other Comprehensive Income. During the three months ended December 31, 2013, the Company adopted new accounting guidance regarding disclosures for items reclassified out of AOCI. The disclosures required by the new accounting guidance are included in Note 2 and Note 12 to the condensed consolidated financial statements. The new disclosures are applied prospectively. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Disclosures about Offsetting Assets and Liabilities. During the three months ended December 31, 2013, the Company adopted new accounting guidance requiring entities to disclose both gross and net information about recognized derivative instruments that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The new disclosures are applied retroactively to all periods presented. The required disclosures are included in Note 11 to the condensed consolidated financial statements. As this guidance only affects disclosure requirements, the adoption of this guidance did not impact our results of operations, cash flows or financial position.


5.	Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following:



	December 31, 2013			September 30, 2013			December 31, 2012
Goodwill (not subject to amortization)	$	2,884.5		$	2,871.0		$	2,835.0
Intangible assets:
Customer relationships, noncompete agreements and other	$	709.6		$	706.4		$	694.8
Trademarks and tradenames (not subject to amortization)	132.2			131.3			138.4
Gross carrying amount	841.8			837.7			833.2
Accumulated amortization	(243.0		)	(227.1		)	(186.4		)
Intangible assets, net	$	598.8		$	610.6		$	646.8

Amortization expense of intangible assets was $13.3 in each of the three-month periods ended December 31, 2013 and 2012. No amortization is included in cost of sales in the Condensed Consolidated Statements of Income. As of December 31, 2013, our expected aggregate amortization expense of intangible assets for the remainder of Fiscal 2014 and for the next four fiscal years is as follows: remainder of Fiscal 2014 — $39.6; Fiscal 2015 — $50.0; Fiscal 2016 — $43.4; Fiscal 2017 — $36.9; Fiscal 2018 — $35.6.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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


6.	Segment Information

Our operations comprise six reportable segments generally based upon products sold, geographic location and regulatory environment. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) Gas Utility; (5) Energy Services; and (6) Electric Generation. We refer to both international segments together as “UGI International” and Energy Services and Electric Generation together as “Midstream & Marketing.”

The accounting policies of our reportable segments are the same as those described in Note 2, “Significant Accounting Policies” in the Company’s 2013 Annual Financial Statements and Notes. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization (“Partnership EBITDA”). Although we use Partnership EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership EBITDA may be different from that used by other companies. We evaluate the performance of our other reportable segments principally based upon their income before income taxes.

Three Months Ended December 31, 2013:



														Midstream & Marketing					UGI International
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	2,315.9		$	(65.5	)	(c)	$	1,045.8		$	271.6		$	272.7		$	20.8	$	425.3		$	293.3		$	51.9
Cost of sales	$	1,429.9		$	(64.4	)	(c)	$	582.7		$	135.5		$	227.1		$	10.6	$	282.5		$	231.7		$	24.2
Segment profit:
Operating income	$	363.7		$	(0.1	)		$	179.7		$	82.1		$	31.8		$	4.4	$	43.2		$	13.7		$	8.9
Income from equity investees	—			—				—			—			—			—		—			—			—
Interest expense	(59.3		)	—				(41.6		)	(8.4		)	(1.0		)	—		(6.4		)	(1.3		)	(0.6		)
Income before income taxes	$	304.4		$	(0.1	)		$	138.1		$	73.7		$	30.8		$	4.4	$	36.8		$	12.4		$	8.3
Partnership EBITDA (a)								$	230.2
Noncontrolling interests’ net income	$	95.5		$	—			$	95.4		$	—		$	—		$	—	$	0.1		$	—		$	—
Depreciation and amortization	$	94.0		$	—			$	52.3		$	13.4		$	2.6		$	2.6	$	15.0		$	6.6		$	1.5
Capital expenditures	$	102.8		$	(1.2	)		$	23.3		$	32.9		$	21.7		$	9.3	$	9.8		$	4.6		$	2.4
Total assets (at period end)	$	10,663.5		$	(101.1	)		$	4,682.3		$	2,188.6		$	574.8		$	279.3	$	1,938.9		$	696.5		$	404.2
Bank loans (at period end)	$	421.5		$	—			$	208.8		$	73.5		$	124.5		$	—	$	—		$	14.7		$	—
Goodwill (at period end)	$	2,884.5		$	—			$	1,938.8		$	182.1		$	2.8		$	—	$	654.3		$	99.5		$	7.0

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Three Months Ended December 31, 2012:



														Midstream & Marketing					UGI International
	Total			Elims.				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Revenues	$	2,018.7		$	(58.5	)	(c)	$	871.9		$	248.3		$	227.8		$	14.9	$	419.3		$	245.6		$	49.4
Cost of sales	$	1,215.5		$	(57.3	)	(c)	$	449.3		$	123.6		$	189.5		$	9.6	$	279.9		$	194.9		$	26.0
Segment profit:
Operating income	$	294.2		$	—			$	137.3		$	69.8		$	25.7		$	0.2	$	47.5		$	10.3		$	3.4
Income from equity investees	—			—				—			—			—			—		—			—			—
Interest expense	(61.5		)	—				(42.4		)	(9.6		)	(1.0		)	—		(6.5		)	(1.3		)	(0.7		)
Income before income taxes	$	232.7		$	—			$	94.9		$	60.2		$	24.7		$	0.2	$	41.0		$	9.0		$	2.7
Partnership EBITDA (a)								$	185.9
Noncontrolling interests’ net income	$	65.3		$	—			$	65.2		$	—		$	—		$	—	$	0.1		$	—		$	—
Depreciation and amortization	$	87.8		$	—			$	50.1		$	12.6		$	1.6		$	2.5	$	14.1		$	5.5		$	1.4
Capital expenditures	$	91.3		$	—			$	26.5		$	28.5		$	13.5		$	6.8	$	12.2		$	2.2		$	1.6
Total assets (at period end)	$	10,138.3		$	(101.5	)		$	4,687.1		$	2,144.7		$	396.7		$	261.2	$	1,828.2		$	564.1		$	357.8
Bank loans (at period end)	$	333.2		$	—			$	177.2		$	73.1		$	69.0		$	—	$	—		$	13.9		$	—
Goodwill (at period end)	$	2,835.0		$	—			$	1,919.2		$	182.1		$	2.8		$	—	$	628.0		$	95.9		$	7.0


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



Three Months Ended December 31,	2013			2012
Partnership EBITDA	$	230.2		185.9
Depreciation and amortization	(52.3		)	(50.1		)
Noncontrolling interests (i)	1.8			1.5
Operating income	$	179.7		$	137.3


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

(b)

Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments and gains and losses on settled commodity derivative instruments not associated with current period transactions, (4) net expenses of UGI’s captive general liability insurance company, and (5) UGI Corporation’s unallocated corporate and general expenses and interest income. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.


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

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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


7.	Energy Services Accounts Receivable Securitization Facility

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 major bank and, prior to October 1, 2013, 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. Trade receivables sold to the bank or, prior to October 1, 2013, the commercial paper conduit, remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank or the commercial paper conduit. The Company records interest expense on amounts owed to the bank or, prior to October 1, 2013, the commercial paper conduit. Energy Services continues to service, administer and collect trade receivables on behalf of the bank or commercial paper issuer, as applicable.

During the three months ended December 31, 2013 and 2012, Energy Services transferred trade receivables to ESFC totaling $269.0 and $224.3, respectively. During the three months ended December 31, 2013 and 2012, ESFC sold an aggregate $92.0 and $79.5, respectively, of undivided interests in its trade receivables to the bank or commercial paper conduit, as applicable. At December 31, 2013, the outstanding balance of ESFC receivables was $88.5 and there was $35.5 sold to the bank. At December 31, 2012, the outstanding balance of ESFC receivables was $69.3 and there was $33.0 sold to the commercial paper conduit.


8.	Utility Regulatory Assets and Liabilities and Regulatory Matters

For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 to the Company’s 2013 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:



	December 31, 2013		September 30, 2013		December 31, 2012
Regulatory assets:
Income taxes recoverable	$	106.4	$	106.1	$	103.7
Underfunded pension and postretirement plans	92.8		94.5		184.8
Environmental costs	14.9		17.1		17.1
Deferred fuel and power costs	0.4		8.3		7.8
Removal costs, net	13.7		13.3		11.5
Other	5.7		5.6		5.7
Total regulatory assets	$	233.9	$	244.9	$	330.6
Regulatory liabilities:
Postretirement benefits	$	16.8	$	16.5	$	13.5
Environmental overcollections	2.3		2.6		3.1
Deferred fuel and power refunds	7.5		8.3		1.9
State tax benefits—distribution system repairs	8.7		8.4		7.7
Other	1.3		1.5		0.6
Total regulatory liabilities	$	36.6	$	37.3	$	26.8

Deferred fuel and power—costs and refunds. Gas Utility’s tariffs and Electric Utility’s tariffs contain clauses which permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) rates in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollected costs are classified as a regulatory liability.

Gas Utility uses derivative financial instruments to reduce volatility in the cost of natural gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative financial instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at December 31, 2013, September 30, 2013 and December 31, 2012 were $2.0, $(1.7) and $(0.4), respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts do not currently qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the Condensed Consolidated Balance Sheets with an associated adjustment to regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities. At December 31, 2013, September 30, 2013, and December 31, 2012, the fair values of Electric Utility’s electricity supply contracts were net losses of $3.2, $4.8 and $8.2, respectively, which amounts are reflected in current derivative financial instrument liabilities and other noncurrent liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs in the table above.

In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power—costs or refunds. Unrealized gains or losses on FTRs at December 31, 2013, September 30, 2013, and December 31, 2012, were not material.


9.	Defined Benefit Pension and Other Postretirement Plans

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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



	Pension Benefits						Other Postretirement Benefits
	Three Months Ended December 31,						Three Months Ended December 31,
	2013			2012			2013			2012
Service cost	$	2.3		$	2.8		$	0.1		$	0.2
Interest cost	6.4			5.9			0.2			0.2
Expected return on assets	(7.3		)	(6.9		)	(0.1		)	(0.1		)
Amortization of:
Prior service benefit	—			—			(0.1		)	(0.1		)
Actuarial loss	2.0			3.8			—			0.1
Net benefit cost	3.4			5.6			0.1			0.3
Change in associated regulatory liabilities	—			—			0.9			0.8
Net expense	$	3.4		$	5.6		$	1.0		$	1.1

Pension Plan assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and UGI Common Stock. It is our general policy to fund amounts for Pension Plan benefits equal to at least the minimum contribution set forth in applicable employee benefit laws. Based upon current assumptions, the Company estimates that it will be required to contribute approximately $14.4 to the Pension Plan during the remainder of Fiscal 2014. During the three months ended December 31, 2013 and 2012, the Company made cash contributions to the Pension Plan of $3.5 and $5.7, respectively. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay UGI Gas’ and Electric Utility’s postretirement health care and life insurance benefits referred to above by depositing into the VEBA the annual amount of postretirement benefit costs determined under GAAP. The difference between such amounts calculated under GAAP and the amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Amounts contributed to the VEBA by UGI Utilities were not material during the three months ended December 31, 2013 and 2012, nor are they expected to be material for all of Fiscal 2014.

We also sponsor unfunded and non-qualified defined benefit supplemental executive retirement plans (“Supplemental Defined Benefit Plans”). We recorded pre-tax expense associated with these plans of $0.8 in each of the three months ended December 31, 2013 and 2012.


10.	Commitments and Contingencies

Environmental Matters

UGI Utilities

CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA was recently renewed and is scheduled to terminate at the end of 2018. 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, 2013 and 2012, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $16.9 and $15.0, respectively. In accordance with GAAP related to rate-regulated entities, we have recorded associated regulatory assets in equal amounts.

From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, by the early 1950s UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility.

UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At December 31, 2013, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.

From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by it or owned or operated by its former subsidiaries. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP.

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

AmeriGas Propane

AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that DEC had placed property owned by the Partnership in Saranac Lake, New York, on its Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by DEC disclosed contamination related to former MGP operations on the site. DEC has classified the site as a significant threat to public health or environment with further action required. The Partnership has researched the history of the site and its ownership interest in the site. The Partnership has reviewed the preliminary site characterization study prepared by the DEC, the extent of contamination and the possible existence of other potentially responsible parties. The Partnership communicated the results of its research to DEC in January 2009. There have been no recent developments in this matter. Because of the preliminary nature of available environmental information, the ultimate amount of expected clean up costs cannot be reasonably estimated.

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

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Other Matters

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

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

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

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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


11.	Fair Value Measurements

Derivative Financial Instruments

The following table presents our financial assets and financial liabilities that are measured at fair value on a recurring basis for each of the fair value hierarchy levels, including both current and noncurrent portions, as of December 31, 2013, September 30, 2013 and December 31, 2012:



	Asset (Liability)
	Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total
December 31, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	4.6		$	48.8		$	—	$	53.4
Foreign currency contracts	$	—		$	0.4		$	—	$	0.4
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(0.9	)	$	(3.8	)	$	—	$	(4.7	)
Foreign currency contracts	$	—		$	(7.2	)	$	—	$	(7.2	)
Interest rate contracts	$	—		$	(29.2	)	$	—	$	(29.2	)
Cross-currency swaps	$	—		$	(2.1	)	$	—	$	(2.1	)
September 30, 2013:
Assets:
Derivative financial instruments:
Commodity contracts	$	2.1		$	21.2		$	—	$	23.3
Foreign currency contracts	$	—		$	0.9		$	—	$	0.9
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(9.7	)	$	(6.3	)	$	—	$	(16.0	)
Foreign currency contracts	$	—		$	(7.2	)	$	—	$	(7.2	)
Interest rate contracts	$	—		$	(31.0	)	$	—	$	(31.0	)
Cross-currency swaps	—			(1.2		)	—		$	(1.2	)
December 31, 2012:
Assets:
Derivative financial instruments:
Commodity contracts	$	0.7		$	6.5		$	—	$	7.2
Interest rate contracts	$	—		$	4.2		$	—	$	4.2
Liabilities:
Derivative financial instruments:
Commodity contracts	$	(9.3	)	$	(37.6	)	$	—	$	(46.9	)
Foreign currency contracts	$	—		$	(2.4	)	$	—	$	(2.4	)
Interest rate contracts	$	—		$	(71.8	)	$	—	$	(71.8	)

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

The fair values of our Level 1 exchange-traded commodity futures and option contracts and non exchange-traded commodity futures and forward contracts are based upon actively-quoted market prices for identical assets and liabilities. The remainder of our derivative financial instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 which are not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of our Level 2 interest rate contracts and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. There were no transfers between Level 1 and Level 2 during the periods presented.

Other Financial Instruments

The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. At December 31, 2013, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,616.3 and $3,856.9, respectively. At December 31, 2012, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,522.8 and $3,840.3, respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2).

Financial instruments other than derivative financial instruments, such as our short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit our credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. The credit risk from trade accounts receivable is limited because we have a large customer base that extends across many different U.S. markets and several foreign countries. Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value. For information regarding concentrations of credit risk associated with our derivative financial instruments, see Note 12 and below.

Disclosures about Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities are presented net by counterparty on our Condensed Consolidated Balance Sheets. Our derivative financial instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency, or other conditions.

In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our derivative counterparties is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our derivative counterparties is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on our Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the tables below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Offsetting Derivative Assets and Liabilities

										Gross Amounts Not Offset in the Balance Sheet
	Gross Amount Recognized			Gross Amount Offset in the Balance Sheet			Net Amounts Presented in the Balance Sheet			Financial Instruments			Cash Collateral		Net Amount
December 31, 2013:
Derivative assets	$	59.8		$	(6.0	)	$	53.8		$	—		$	—	$	53.8
Derivative (liabilities)	$	(49.2	)	$	6.0		$	(43.2	)	$	—		$	—	$	(43.2	)

September 30, 2013:
Derivative assets	$	26.3		$	(2.1	)	$	24.2		$	(1.7	)	$	—	$	22.5
Derivative (liabilities)	$	(57.5	)	$	2.1		$	(55.4	)	$	1.7		$	1.4	$	(52.3	)

December 31, 2012:
Derivative assets	$	19.1		$	(7.7	)	$	11.4		$	(0.3	)	$	—	$	11.1
Derivative (liabilities)	$	(128.8	)	$	7.7		$	(121.1	)	$	0.3		$	5.4	$	(115.4	)


12.	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. A substantial portion of our derivative financial instruments, other than commodity derivative instruments at Midstream & Marketing, are designated and qualify as cash flow hedges or net investment hedges. Midstream & Marketing’s commodity derivative instruments are not accounted for as hedges under GAAP. Because a substantial portion of our derivative instruments qualify for and are designated as hedges under GAAP or are subject to regulatory rate recovery mechanisms, we expect that changes in the fair value of derivative instruments used to manage commodity, interest rate or currency exchange rate risk would be substantially offset by gains or losses on the associated anticipated transactions.

Commodity Price Risk

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

Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. At December 31, 2013 and 2012, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 9.7 million dekatherms and 13.0 million dekatherms, respectively. At December 31, 2013, 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

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

assets or liabilities on the Condensed Consolidated Balance Sheets in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the PGC mechanism (see Note 8).

Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because these contracts currently do not qualify for the normal purchases and normal sales exception under GAAP, the fair values of these contracts are required to be recognized on the balance sheet. At December 31, 2013 and 2012, the fair values of Electric Utility’s forward purchase power agreements comprising losses of $3.2 and $8.2, respectively, are reflected in current derivative financial instrument liabilities and other noncurrent liabilities in the accompanying Condensed Consolidated Balance Sheets. In accordance with GAAP related to rate-regulated entities, Electric Utility has recorded equal and offsetting amounts in regulatory assets. At December 31, 2013 and 2012, the volumes of Electric Utility’s forward electricity purchase contracts was 324.4 million kilowatt hours and 482.3 million kilowatt hours, respectively. At December 31, 2013, the maximum period over which these contracts extend is 11 months.

In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process and by purchases of FTRs at monthly auctions. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts. FTRs are derivative financial instruments that entitle the holder to receive compensation for electricity transmission congestion charges that result when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP related to rate-regulated entities and reflected in cost of sales through the DS recovery mechanism (see Note 8). Midstream & Marketing from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. At December 31, 2013 and 2012, the volumes associated with Electric Utility FTRs totaled 117.9 million kilowatt hours and 118.2 million kilowatt hours, respectively. Midstream & Marketing’s FTRs and capacity swap contracts are recorded at fair value with changes in fair value reflected in cost of sales. At December 31, 2013 and 2012, the volumes associated with Midstream & Marketing’s FTRs and NYISO capacity swap contracts totaled 968.0 million kilowatt hours and 677.5 million kilowatt hours, respectively.

In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures contracts, IntercontinentalExchange (“ICE”) natural gas basis swap contracts, and electricity futures contracts. Midstream & Marketing also uses NYMEX and over the counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later sale of natural gas or propane. Substantially all of Midstream & Marketing’s derivative financial instruments described above are not accounted for as hedges under GAAP. These derivative instruments are recorded at fair value with changes in fair value reflected in income. As a result, volatility in Midstream and Marketing’s results can occur due to changes in the fair value of unsettled derivative instruments. Volatility can also occur as a result of timing differences between the settlement of financial derivatives and the sale or purchase of the corresponding physical commodity that was economically hedged.

At December 31, 2013 and 2012, total volumes associated with Midstream & Marketing’s natural gas futures contracts associated with forecasted purchases of natural gas totaled 27.4 million dekatherms and 21.1 million dekatherms, respectively. At December 31, 2013 and 2012, total volumes associated with Midstream & Marketing’s electricity call contracts and electricity put contracts totaled 664.7 million kilowatt hours and 371.0 million kilowatt hours, and 1,180.8 million kilowatt hours and 195.3 million kilowatt hours, respectively. At December 31, 2013, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 1.1 million dekatherms and 2.2 million gallons, respectively. At December 31, 2012, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 2.4 million dekatherms and 2.0 million gallons, respectively.

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

At December 31, 2013 and 2012, we had outstanding LPG derivative commodity instruments that qualify for hedge accounting treatment of 215.2 million gallons and 212.1 million gallons, respectively. At December 31, 2013, the maximum period over which

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

we are hedging our exposure to the variability in cash flows associated with LPG commodity price risk is 21 months with a weighted average of 5 months.

We account for commodity price risk contracts (other than Midstream & Marketing’s contracts that are not designated as accounting hedges, Gas Utility and Electric Utility contracts that are subject to regulatory treatment and certain other contracts not qualifying for hedge accounting) as cash flow hedges. Changes in the fair values of contracts qualifying for cash flow hedge accounting are recorded in AOCI and, with respect to the Partnership, noncontrolling interests, to the extent effective in offsetting changes in the underlying commodity price risk. When earnings are affected by the hedged commodity, gains or losses are recorded in cost of sales on the Condensed Consolidated Statements of Income. At December 31, 2013, the amount of net gains associated with commodity price risk hedges expected to be reclassified into earnings during the next twelve months based upon current fair values is $43.6.

Interest Rate Risk

Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its variable-rate term loan, and Flaga has entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on its term loans, in each case through the respective scheduled maturity dates. As of December 31, 2013 and 2012, the total notional amount of existing variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) was €439.8 and €441.2, respectively.

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At December 31, 2013, we had no unsettled IRPAs. At December 31, 2012, the total notional amount of unsettled IRPAs was $173.

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, 2013, the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $2.7.

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases through the use of forward foreign currency exchange contracts. The amount of dollar-denominated purchases of LPG associated with such contracts generally represents approximately 15% to 30% of estimated dollar-denominated purchases of LPG forecasted to occur during the heating-season months of October through March. At December 31, 2013 and 2012, we were hedging a total of $149.1 and $120.0 of U.S. dollar-denominated LPG purchases, respectively. At December 31, 2013, the maximum period over which we are hedging our exposure to the variability in cash flows associated with dollar-denominated purchases of LPG is 27 months with a weighted average of 12 months. From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At December 31, 2013 and 2012, we had no euro-dominated net investment hedges.

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, 2013, the amount of net losses associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $3.4. Gains and losses on net investment hedges are included in AOCI until such foreign operations are liquidated.

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

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Cross-Currency Swaps

During Fiscal 2013, Flaga entered into a cross-currency swap to hedge its exposure to the variability in expected future cash flows associated with foreign currency and interest rate risk resulting from the issuance of $52 of U.S. dollar denominated variable-rate debt. The cross-currency hedge includes initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. The cross-currency swap also includes an interest rate swap of a fixed foreign-denominated interest rate to a fixed U.S. denominated interest rate. We have designated this cross-currency swap as a cash flow hedge. Changes in the fair value of our cross-currency swap is recorded in AOCI to the extent effective in offsetting changes in the underlying foreign currency exchange and interest rate risk. At December 31, 2013, the amount of net losses associated with this cross-currency swap expected to be reclassified into earnings over the next twelve months is 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 forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2013 and 2012, restricted cash in brokerage accounts totaled $3.2 and $6.9, respectively. Although we have concentrations of credit risk associated with derivative financial instruments, the maximum amount of loss, based upon the gross fair values of the derivative financial instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at December 31, 2013. Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At December 31, 2013, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

The following table provides information regarding the fair values and balance sheet locations of our derivative assets and liabilities existing as of December 31, 2013 and 2012:

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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



	Derivative Assets					Derivative (Liabilities)
	Balance Sheet	Fair Value December 31,				Balance Sheet	Fair Value December 31,
	Location	2013		2012		Location	2013			2012
Derivatives Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments and Other assets	$	40.9	$	3.5	Derivative financial instruments and Other noncurrent liabilities	$	—		$	(29.3	)
Foreign currency contracts	Derivative financial instruments and Other assets	0.4		—		Other noncurrent liabilities	(7.2		)	(2.4		)
Cross-currency contracts		—		—		Derivative financial instruments and Other noncurrent liabilities	(2.1		)	—
Interest rate contracts	Derivative financial instruments	—		4.2		Derivative financial instruments and Other noncurrent liabilities	(29.2		)	(71.8		)
Total Derivatives Designated as Hedging Instruments		$	41.3	$	7.7		$	(38.5	)	$	(103.5	)
Derivatives Subject to Utility Rate Regulation:
Commodity contracts	Derivative financial instruments	$	1.9	$	0.4	Derivative financial instruments and Other noncurrent liabilities	$	(3.3	)	$	(9.0	)
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Derivative financial instruments	$	10.6	$	3.3	Derivative financial instruments	$	(1.4	)	$	(8.6	)
Total Derivatives		$	53.8	$	11.4		$	(43.2	)	$	(121.1	)

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, 2013 and 2012:



Three Months Ended December 31,	Gain (Loss) Recognized in AOCI and Noncontrolling Interests						Gain (Loss) Reclassified from AOCI and Noncontrolling Interests into Income						Location of Gain (Loss) Reclassified from AOCI and Noncontrolling
	2013			2012			2013			2012			Interests into Income
Cash Flow Hedges:
Commodity contracts	$	53.4		$	(4.1	)	$	22.3		$	(17.9	)	Cost of sales
Foreign currency contracts	(2.5		)	(3.7		)	(2.1		)	0.5			Cost of sales
Cross-currency contracts	(1.2		)	—			(0.3		)	—			Interest expense
Interest rate contracts	(1.7		)	1.0			(4.1		)	(3.5		)	Interest expense / other income, net
Total	$	48.0		$	(6.8	)	$	15.8		$	(20.9	)

	Gain (Loss) Recognized in Income												Location of Gain (Loss) Recognized in Income
Derivatives Not Designated as Hedging Instruments:	2013			2012
Commodity contracts	$	12.8		$	2.3								Cost of sales
Commodity contracts	0.1			—									Operating expenses / other income, net
Total	$	12.9		$	2.3

The amounts of derivative gains or losses representing ineffectiveness were not material for the three-month periods ended December 31, 2013 and 2012.

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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


13.	Inventories

Inventories comprise the following:



	December 31, 2013		September 30, 2013		December 31, 2012
Non-utility LPG and natural gas	$	282.9	$	230.0	$	265.9
Gas Utility natural gas	69.1		78.9		51.8
Materials, supplies and other	60.4		56.6		60.8
Total inventories	$	412.4	$	365.5	$	378.5

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

As of December 31, 2013, UGI Utilities had SCAAs with Energy Services and a non-affiliate. The carrying values of natural gas storage inventories released under SCAAs with non-affiliates at December 31, 2013 and September 30, 2013, comprising 3.1 billion cubic feet (“bcf”) and 3.8 bcf of natural gas, were $12.3 and $11.4, respectively. UGI Utilities did not have any SCAAs with non-affiliates at December 31, 2012.

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

Forward-Looking Statements

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

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that actual results almost always vary from assumed facts or bases, and the differences between actual results and assumed facts or bases can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the following important factors that could affect our future results and could cause those results to differ materially from those expressed in our forward-looking statements: (1) adverse weather conditions resulting in reduced demand; (2) cost volatility and availability of propane and other LPG, oil, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax, consumer protection and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings;

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(6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers and retain current customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) large customer, counterparty or supplier defaults; (12) liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and LPG and the impact of regulatory enforcement activity related thereto, ranging from financial penalties, required reporting or operational measures up to suspension of applicable certificates of public convenience; (13) political, regulatory and economic conditions in the United States and in foreign countries, including foreign currency exchange rate fluctuations, particularly the euro; (14) capital market conditions, including reduced access to capital markets and interest rate fluctuations; (15) changes in commodity market prices resulting in significantly higher cash collateral requirements; (16) reduced distributions from subsidiaries; (17) the timing of development of Marcellus Shale gas production; (18) the timing and success of our acquisitions, commercial initiatives and investments to grow our businesses; and (19) our ability to successfully integrate acquired businesses and achieve anticipated synergies.

These factors, and those factors set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended September 30, 2013, 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, 2013 (“2013 three-month period”) with the three months ended December 31, 2012 (“2012 three-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 6 to the condensed consolidated financial statements.

Executive Overview

Because most of our businesses sell or distribute 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 $122.0 million (equal to $1.05 per diluted share) for the 2013 three-month period compared to net income attributable to UGI Corporation of $102.5 million (equal to $0.90 per diluted share) for the 2012 three-month period. Net income attributable to UGI Corporation in the 2013 three-month period and the 2012 three-month period include net after-tax gains of $4.2 million and $1.3 million, respectively, related to changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments as well as gains and losses on Midstream & Marketing’s settled commodity derivative instruments not associated with current period transactions (which amounts are reflected in “Corporate & Other” in the business unit summary table below). Adjusted net income attributable to UGI (which excludes the previously mentioned after-tax gains associated with Midstream & Marketing’s commodity derivative instruments and, with respect to the the 2013 three-month period, the retroactive impact of changes in French tax law as further described below) was $123.5 million (equal to $1.06 per diluted share) in the 2013 three-month period compared to $101.2 million (equal to $0.88 per diluted share) in the prior-year period. The retroactive effect to Fiscal 2013 of the change in tax laws in France increased tax expense and reduced 2013 three-month period net income and adjusted net income attributable to UGI by $5.7 million (equal to $0.05 per diluted share).

Operating results in the 2013 three-month period reflect the benefits on our domestic businesses of colder 2013 three-month period weather. Temperatures during the 2013 three-month period based upon heating degree day data was colder than normal at AmeriGas Propane, Gas Utility and Midstream & Marketing compared with temperatures that were warmer than normal during the prior-year period. Net income attributable to UGI Corporation during the 2013 three-month period increased $7.9 million at Gas Utility, $7.9 million at AmeriGas Propane, and $7.0 million at Midstream & Marketing (which amount excludes the impact of the previously mentioned after-tax gains associated with commodity derivative instruments). The increase in the Gas Utility’s 2013 three-month period results principally reflects the effects on core market volumes of 6.9% colder weather while the improved results at AmeriGas Propane principally reflect significantly colder weather and the benefits of the full integration of Heritage Propane acquired by AmeriGas Partners in Fiscal 2012. Midstream & Marketing’s Electric Generation business benefited from higher unit margins and higher production at its Hunlock Creek natural gas fired generating facility. In addition to the positive effects on operating results from the colder weather, Midstream & Marketing’s Energy Service’s operating results benefited from more volatile early winter weather patterns which resulted in higher margin from peaking and capacity management activities. In contrast to the colder weather experienced in the United States, temperatures at UGI International’s European operations were warmer than normal and overall warmer than the prior year. Although UGI International’s pre-tax operating results during the 2013 three-month period were only slightly below the prior-year period, after-tax results were substantially lower due to French tax law changes affecting Antargaz, including certain tax law changes retroactive to Fiscal 2013 that reduced UGI International net income by $5.7 million.

Our UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during each of the reporting periods. The differences in foreign currency exchange rates between the 2013 three-month period and the 2012 three-month period did not have a material impact on UGI International net income attributable to UGI.

We believe each of our business units has sufficient liquidity in the forms of revolving credit facilities, and with respect to Energy Services also an accounts receivable securitization facility, to fund business operations during Fiscal 2014 (see Financial Condition and Liquidity below).

Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Diluted Earnings Per Share

UGI management uses “adjusted net income attributable to UGI” and “adjusted earnings per diluted share,” both of which are non-GAAP financial measures, when evaluating UGI’s overall performance. Adjusted net income attributable to UGI is net income attributable to UGI excluding (1) changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments as well as gains and losses on settled commodity derivative instruments not associated with current period transactions and (2) those items that management regards as highly unusual in nature and not expected to recur. Midstream & Marketing accounts for commodity derivative instruments at fair value with changes in fair value included in earnings as a component of cost of sales or revenues on the Condensed Consolidated Statements of Income. Volatility in net income at UGI can occur as a result of changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments as well as timing differences between

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the settlement of commodity derivative instruments and the income statement impact of the purchase or sale of the associated commodity.

Non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measures. Management believes that these non-GAAP measures provide meaningful information to investors about UGI’s performance because they eliminate the impact of (1) changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments as well as gains and losses on settled commodity derivative instruments not associated with current period transactions that are required, under GAAP, to be recorded in current period earnings but are economic hedges of the related commodity transactions and (2) those items that management regards as highly unusual in nature and not expected to recur.

The following table reconciles consolidated net income attributable to UGI, the most directly comparable GAAP measure, to adjusted net income attributable to UGI, and reconciles diluted earnings per share, the most comparable GAAP measure, to adjusted diluted earnings per share, to reflect the adjustments referred to above:




(Millions of dollars, except per share)	For the three months ended December 31,
	2013			2012
Adjusted net income attributable to UGI Corporation:
Net income attributable to UGI Corporation	$	122.0		$	102.5
Adjust: Net unrealized (gains) losses on Midstream & Marketing’s unsettled commodity derivative instruments	(3.0		)	1.1
Adjust: Net (gains) losses on certain Midstream & Marketing settled commodity derivative instruments	(1.2		)	(2.4		)
Adjust: Retroactive impact of change in French tax law	5.7			0.0
Adjusted net income attributable to UGI Corporation	$	123.5		$	101.2

Adjusted diluted earnings per share:
UGI Corporation earnings per share - diluted	$	1.05		$	0.90
Adjust: Net unrealized (gains) losses on Midstream & Marketing’s unsettled commodity derivative instruments	(0.03		)	0.01
Adjust: Net (gains) losses on certain Midstream & Marketing settled commodity derivative instruments (a)	(0.01		)	(0.03		)
Adjust: Retroactive impact of change in French tax law	0.05			—
Adjusted diluted earnings per share	$	1.06		$	0.88

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(a) - includes the impact of rounding.

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



Net income (loss) attributable to UGI Corporation by Business Unit:
	Three Months Ended December 31,
	2013				2012					Variance - Favorable (Unfavorable)
(Millions of dollars)	Amount		% of Total		Amount			% of Total		Amount			% Change
AmeriGas Propane	$	25.5	20.9	%	$	17.6		17.2	%	$	7.9		44.9	%
UGI International	27.4		22.5	%	35.5			34.6	%	(8.1		)	(22.8	)%
Gas Utility	43.4		35.6	%	35.5			34.6	%	7.9			22.3	%
Midstream & Marketing	22.0		18.0	%	15.0			14.6	%	7.0			46.7	%
Corporate & Other	3.7		2.9	%	(1.1		)	(1.0	)%	4.8			N.M.
Net income attributable to UGI Corporation	$	122.0	100.0	%	$	102.5		100.0	%	$	19.5		N.M

N.M. — Variance is not meaningful.

AmeriGas Propane:



For the three months ended December 31,	2013			2012			Increase (decrease)
(Millions of dollars)
Revenues	$	1,045.8		$	871.9		$	173.9		19.9	%
Total margin (a)	$	463.1		422.6			$	40.5		9.6	%
Operating and administrative expenses	$	237.6		$	243.5		$	(5.9	)	(2.4	)%
Partnership EBITDA (b)	$	230.2		$	185.9		$	44.3		23.8	%
Operating income (b)	$	179.7		$	137.3		$	42.4		30.9	%
Retail gallons sold (millions)	374.1			350.7			23.4			6.7	%
Degree days—% colder (warmer) than normal (c)	3.8		%	(9.0		)%	—			—


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

(b)

Partnership EBITDA (earnings before interest expense, income taxes and depreciation and amortization) should not be considered as an alternative to net income (as an indicator of operating performance) and is not a measure of performance or financial condition under accounting principles generally accepted in the United States of America. Management uses Partnership EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 6 to condensed consolidated financial statements). Partnership EBITDA for the three months ended December 31, 2012, includes transition expenses of $5.5 million associated with Heritage Propane.


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

AmeriGas Propane’s retail gallons sold in the 2013 three-month period increased 6.7% from the 2012 three-month period. The increase in retail gallons sold reflects average temperatures based upon heating degree days that were 3.8% colder than normal and 14% colder than the prior-year period.

Retail propane revenues increased $153.3 million during the 2013 three-month period reflecting the effects of higher average retail selling prices ($102.3 million), largely the result of higher propane product costs, and the higher retail volumes sold ($51.0 million). Wholesale propane revenues increased $25.5 million during the 2013 three-month period reflecting the effects of higher wholesale selling prices ($14.1 million) and higher wholesale volumes sold ($11.4 million). Average daily wholesale propane commodity prices during the 2013 three-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 35% higher than such prices during the prior-year three-month period. Total revenues from fee income and other ancillary sales and services in the 2013 three-month period were slightly lower than in the 2012 three-month period. Total cost of

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sales during the 2013 three-month period increased $133.4 million principally reflecting the effects of the higher average propane product costs ($98.0 million) and, to a lesser extent, the effects of the greater retail and wholesale volumes sold ($37.7 million).

Total margin increased $40.5 million in the 2013 three-month period principally reflecting higher retail propane total margin ($42.2 million). The increase in retail propane total margin reflects the increase in retail volumes sold and slightly higher average retail propane unit margins.

Partnership EBITDA in the 2013 three-month period increased $44.3 million principally reflecting the higher total margin ($40.5 million) and slightly lower operating and administrative expenses ($5.9 million). Notwithstanding higher distribution-related expenses associated with the higher retail volumes sold, operating and administrative expenses were lower reflecting synergies from the integration of Heritage Propane which was completed in Fiscal 2013. Operating and administrative expenses in the prior-year three-month period include $5.5 million of transition expenses associated with the integration of Heritage Propane. Operating income increased $42.4 million in the 2013 three-month period principally reflecting the higher total margin ($40.5 million) and the lower operating and administrative expenses ($5.9 million) partially offset by higher depreciation and amortization expense ($2.2 million) and, to a lesser extent, lower other income ($1.7 million).

UGI International:



For the three months ended December 31,	2013			2012			Increase (decrease)
(Millions of dollars)
Revenues	$	718.6		$	664.9		$	53.7		8.1	%
Total margin (a)	$	204.4		$	190.1		$	14.3		7.5	%
Operating and administrative expenses	$	126.6		$	113.9		$	12.7		11.2	%
Operating income	$	56.9		$	57.8		$	(0.9	)	(1.6	)%
Income before income taxes	$	49.2		$	50.0		$	(0.8	)	(1.6	)%
Retail gallons sold (b)	185.1			172.8			12.3			7.1	%
Antargaz degree days—% (warmer) than normal (c)	(7.2		)%	(7.7		)%	—			—
Flaga degree days—% (warmer) than normal (c)	(12.9		)%	(3.2		)%	—			—


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


(b)	Excludes retail gallons from operations in China.


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

Based upon heating degree day data, temperatures during the 2013 three-month period at our UGI International European LPG operations were warmer than normal. Compared to temperatures in the prior-year three-month period, average temperatures at Antargaz were approximately the same while average temperatures at Flaga and AvantiGas were warmer. Total retail gallons sold were higher, notwithstanding the effects of the overall warmer weather, reflecting incremental retail gallons associated with BP’s former LPG business in Poland acquired by Flaga in September 2013 (“BP Poland acquisition”). During the 2013 three-month period, the average wholesale commodity price for propane in northwest Europe was approximately 15% lower than in the prior-year period while the average wholesale commodity price for butane was approximately 3% lower than the prior-year period.

UGI International 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 UGI International results is the euro. During the 2013 and 2012 three-month periods, the average un-weighted translation rate was approximately $1.36 and $1.30 per euro, respectively. The difference in euro to U.S. dollar translation rates and, to a lesser extent, the difference in the British Pound Sterling to the U.S. dollar, did not have a material impact on net income attributable to UGI.

UGI International revenues were $53.7 million higher than the prior-year period principally reflecting greater total revenues at Flaga ($55.6 million), primarily reflecting the effects of the BP Poland acquisition, and greater natural gas marketing revenues at Antargaz ($18.7 million). These increases in revenues were partially offset by the effects of the previously mentioned lower average LPG commodity prices. Cost of sales increased to $514.2 million in the 2013 three-month period from $474.8 million in the prior-year period as greater cost of sales at Flaga ($47.5 million), primarily reflecting the BP Poland acquisition, and higher cost of gas associated with Antargaz natural gas sales ($17.3 million) were partially offset by the effects of the lower LPG wholesale commodity costs. The previously mentioned increases in revenues and cost of sales during the 2013 three-month period also reflect the effects of the slightly stronger euro.

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Total UGI International margin increased $14.3 million during the 2013 three-month period reflecting, among other things, higher total margin at Flaga ($8.0 million), principally the effects of the BP Poland acquisition, higher total margin at AvantiGas ($2.9 million) reflecting higher average unit margins, and higher natural gas marketing margin at Antargaz.

UGI International 2013 three-month period operating income and income before income taxes were $0.9 million and $0.8 million, respectively, lower than the prior-year period principally reflecting the higher total margin ($14.3 million) offset by increased operating and administrative costs at Flaga ($4.7 million) and Antargaz ($6.9 million) and, to a much lesser extent, slightly higher depreciation expense. The increase in Flaga operating and administrative expenses reflects expenses associated with the BP Poland operations including $0.4 million of integration costs while the higher costs at Antargaz includes, among other things, higher repairs and maintenance expenses. The higher operating and administrative costs and depreciation expense also reflects the currency conversion effects principally from the slightly stronger euro in the 2013 three-month period.

Gas Utility:



For the three months ended December 31,	2013			2012			Increase (decrease)
(Millions of dollars)
Revenues	$	271.6		$	248.3		$	23.3		9.4	%
Total margin (a)	$	136.1		$	124.7		$	11.4		9.1	%
Operating and administrative expenses	$	38.6		$	40.6		$	(2.0	)	(4.9	)%
Operating income	$	82.1		$	69.8		$	12.3		17.6	%
Income before income taxes	$	73.7		60.2			$	13.5		22.4	%
System throughput—billions of cubic feet (“bcf”) —
Core market	24.1			21.8			2.3			10.6	%
Total	56.7			54.0			2.7			5.0	%
Degree days—% colder (warmer) than normal (b)	3.0		%	(3.6		)%	—			—


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


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

Temperatures in the Gas Utility service territory in the 2013 three-month period based upon heating degree days were 3.0% colder than normal and 6.9% colder than the prior-year three-month period. Total distribution system throughput increased 2.7 bcf (5.0%) principally reflecting a 2.3 bcf increase in throughput to Gas Utility’s core market customers. Core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers. Gas Utility system throughput to core-market customers was higher than last year principally reflecting the effects of the colder weather and, to a lesser extent, customer growth due principally to conversions from other fuels prompted by sustained lower natural gas prices and high oil prices.

Gas Utility revenues increased $23.3 million during the 2013 three-month period principally reflecting higher revenues from core market customers ($21.8 million) and, to a much lesser extent, higher revenues from large firm delivery service customers on higher throughput ($2.9 million). These increases were partially offset by slightly lower revenues from off-system sales ($1.7 million). The increase in core market revenues principally reflects the effects of the higher core market throughput partially offset by the effects of lower average purchased gas cost (“PGC”) rates ($0.8 million). Under Gas Utility’s PGC recovery mechanisms, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from or refunded to customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of gas was $135.5 million in the 2013 three-month period compared with $123.6 million in the prior-year period principally reflecting the effects of the greater retail core-market volumes sold ($11.4 million) partially offset by the effects of the lower off-system sales ($1.7 million) and the effects of the lower average PGC rates.

Gas Utility total margin increased $11.4 million in the 2013 three-month period principally reflecting higher core market total margin ($8.0 million) and greater large firm delivery service total margin ($3.2 million). The higher core market and large firm delivery service total margin reflects the effects of the greater throughput to these customers resulting from the colder weather.

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Gas Utility operating income and income before income taxes during the 2013 three-month period were $12.3 million and $13.5 million higher than the prior year, respectively. The increase in Gas Utility operating income principally reflects the $11.4 million increase in total margin and, to a much lesser extent, a $2.0 million decrease in operating and administrative expenses which includes, among other things, lower pension and benefits expenses. The increase in Gas Utility income before income taxes reflects the greater operating income ($12.3 million) and lower interest expense principally reflecting lower average interest rates.

Midstream & Marketing:



For the three months ended December 31,	2013		2012		Increase
(Millions of dollars)
Revenues (a)	$	289.0	$	241.9	$	47.1	19.5	%
Total margin (b)	$	55.8	$	43.6	$	12.2	28.0	%
Operating and administrative expenses	$	14.2	$	13.5	$	0.7	5.2	%
Operating income	$	36.2	$	25.9	$	10.3	39.8	%
Income before income taxes	$	35.2	$	24.9	$	10.3	41.4	%


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

(b)

Total margin represents total revenues less total cost of sales. Amounts exclude pre-tax gains (losses) from changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments and gains (losses) on settled commodity instruments not associated with the current period transactions of $7.2 million and $2.3 million during the 2013 three-month period and the 2012 three-month period, respectively.

Midstream & Marketing total revenues increased $47.1 million in the 2013 three-month period principally reflecting higher natural gas revenues ($42.1 million) principally from greater natural gas volumes and, to a much lesser extent, higher capacity management revenues ($6.2 million) and greater Electric Generation revenues ($5.9 million). The increase in natural gas revenues principally reflects higher wholesale volumes sold while the increase in Electric Generation revenues reflects higher electricity production at the Hunlock Creek electricity generating station. These increases in revenues were partially offset by lower retail power revenues from a decline in retail power sales in certain markets.

Midstream & Marketing total margin increased $12.2 million in the 2013 three-month period principally reflecting higher capacity management and natural gas gathering total margin ($10.3 million), higher Electric Generation total margin ($4.8 million) and increased peaking total margin partially offset by lower retail power total margin. The greater total margin from capacity management and peaking activities reflects opportunities resulting from greater volatility in early winter weather patterns while the increase in natural gas gathering total margin includes incremental margin from the Auburn pipeline extension which was placed in service during the 2013 three-month period. The greater total margin from Electric Generation principally reflects the impact of higher unit margins at the Hunlock Creek natural gas-fired electricity generating facility reflecting in large part lower natural gas feedstock costs and greater electricity production. The lower retail power total margin reflects, in part, lower sales in certain competitive markets and lower average retail power unit margins.

Midstream & Marketing operating income and income before income taxes in the 2013 three-month period were each $10.3 million higher than the prior-year period reflecting the previously mentioned increase in total margin ($12.2 million) partially offset by higher operating and depreciation expenses. The higher operating and depreciation expenses include greater expenses associated with peaking and natural gas gathering assets, and greater Electric Generation operating expenses ($0.7 million) largely a result of the increased production at the Hunlock Creek electricity generating facility.

Interest Expense and Income Taxes. Our consolidated interest expense was $2.2 million lower during the 2013 three-month period principally reflecting slightly lower UGI Utilities and AmeriGas Propane interest expense.

Our consolidated effective tax rate for the three months ended December 31, 2013 was higher than the prior-year period. The higher effective tax rate in the 2013 three-month period reflects the effects of new tax legislation in France which, among other things, limits Antargaz’ ability to deduct interest expense for income tax purposes on certain intercompany debt and increases the corporate surtax rate for a period of two years. Based upon our review of the new tax legislation and interpretive guidance currently available, provisions of the new tax legislation associated with the deductibility of interest expense on certain intercompany debt at Antargaz applies retroactively to such interest incurred during Fiscal 2013. During the three months ended December 31, 2013, the Company recorded income taxes of $5.7 million to reflect the retroactive effects of the new tax legislation associated with the deductibility of interest expense on certain intercompany debt.

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FINANCIAL CONDITION AND LIQUIDITY

Financial Condition and Liquidity

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 borrowings under credit facilities and, in the case of Midstream & Marketing, also from a receivables purchase facility. Long-term cash requirements not met by cash from operations are generally met through issuance of long-term debt or equity securities. We believe that each of our business units has sufficient liquidity in the forms of cash and cash equivalents on hand; cash expected to be generated from operations; credit facility and receivables purchase facility borrowings; and the ability to obtain long-term financing to meet anticipated contractual and projected cash commitments. Issuances of debt and equity securities in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.

Our cash and cash equivalents totaled $418.1 million at December 31, 2013, compared with $389.3 million at September 30, 2013. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at December 31, 2013 and September 30, 2013, UGI had $183.5 million and $171.6 million, respectively, of cash and cash equivalents.

Long-term Debt and Credit Facilities

The Company’s debt outstanding at December 31, 2013, totaled $4,037.8 million (including current maturities of long-term debt of $67.2 million and bank loan borrowings of $421.5 million) compared to debt outstanding at September 30, 2013, of $3,837.3 million (including current maturities of long-term debt of $67.2 million and bank loan borrowings of $227.9 million). Total debt outstanding at December 31, 2013, consists of (1) $2,507.8 million of Partnership debt; (2) $677.4 million of UGI International debt; (3) $715.5 million of UGI Utilities’ debt; (4) $125.5 million of Midstream & Marketing debt; and (5) $11.6 million of other debt.

AmeriGas Partners. AmeriGas Partners’ total debt at December 31, 2013, includes $2,250.8 million of AmeriGas Partners’ Senior Notes, $208.8 million of AmeriGas OLP bank loan borrowings and $48.2 million of other long-term debt.

UGI International. UGI International’s total debt at December 31, 2013, includes $522.3 million (€380 million) outstanding under Antargaz’ Senior Facilities term loan, $52 million under Flaga’s U.S. dollar-denominated term loan and a combined $82.3 million (€59.8 million) outstanding under Flaga’s three term loans. Total UGI International debt outstanding at December 31, 2013, also includes combined borrowings of $14.7 million outstanding under all of Flaga’s working capital facilities and $6.1 million (€4.5 million) of other long-term debt.

UGI Utilities. UGI Utilities’ total debt at December 31, 2013, includes long-term debt comprising $275 million of Senior Notes, $192 million of Medium-Term Notes, $175 million outstanding under UGI Utilities Term Loan Credit Agreement and $73.5 million of bank loan borrowings. UGI Utilities expects to repay $175 million outstanding under the UGI Utilities Term Loan Credit Agreement in March 2014 with proceeds from $175 million of Senior Notes due March 26, 2044 issued under a Note Purchase Agreement.

Credit Facilities

Due to the seasonal nature of the Company’s businesses, operating cash flows 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 first and fourth fiscal quarters when the Company’s investment in working capital, principally inventories and accounts receivable, is generally greatest. AmeriGas Propane and UGI Utilities primarily use their credit facilities to satisfy their seasonal operating cash flow needs. Energy Services historically has used its Receivables Facility to satisfy its operating cash flow needs. Energy Services also has a $240 million credit facility which it can use for working capital and general corporate purposes. Flaga principally uses borrowings under its credit agreements to satisfy its operating cash flow needs. Antargaz has generally funded its operating cash flow needs without using its revolving credit facilities and AvantiGas has satisfied its operating cash flow needs from cash on hand. Borrowings under the credit facilities and under the Energy Services Receivables Facility are classified as bank loans on the Condensed Consolidated Balance Sheets.

AmeriGas Partners. AmeriGas OLP has a $525 million unsecured credit agreement (“AmeriGas Credit Agreement”) that expires on October 15, 2016.

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UGI International. Under its Senior Facilities Agreement, Antargaz has a €40 million credit facility that expires in March 2016. Flaga has two principal working capital facilities (the “Flaga Credit Agreements”) comprising (1) a €46 million multi-currency working capital facility that includes an uncommitted €6 million overdraft facility (the “Flaga Multi-Currency Working Capital Facility”) and (2) a euro-denominated working capital facility that provides for borrowings and issuances of guarantees totaling €12 million (the “Euro Facility”). Both the Flaga Multi-Currency Working Capital Facility and the Euro Facility are currently scheduled to expire in September 2014.

UGI Utilities. UGI Utilities has a revolving credit agreement (the “UGI Utilities Credit Agreement”) with a group of banks providing for borrowings of up to $300 million (including a $100 million sublimit for letters of credit) which expires in October 2015.

Midstream & Marketing. Energy Services has an unsecured credit agreement (“Energy Services Credit Agreement”) with a group of lenders providing for borrowings of up to $240 million (including a $50 million sublimit for letters of credit) which expires in June 2016. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services and its subsidiaries and to fund dividend payments provided that, after giving effect to such dividend payments, Energy Services maintains a specified ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement.

Information about the Company’s principal credit agreements as of and for the three months ended December 31, 2013 and 2012, including the average daily and peak bank loan borrowings under the Company’s principal credit agreements is presented in the table below. The Energy Services Receivables Facility is discussed further below and is excluded from the table. There were no borrowings under Antargaz’ credit facility during the three months ended December 31, 2013 or 2012.



(Millions of dollars or euros)	As of December 31, 2013				For the three months ended December 31, 2013
	Total Capacity	Borrowings Outstanding	Letters of Credit and Guarantees Outstanding	Available Capacity	Average Borrowings	Peak Borrowings
AmeriGas Credit Agreement	$525.0	$208.8	$64.7	$251.5	$172.1	$266.0
Antargaz Credit Facility	€40.0	€0.0	€0.0	€40.0	N.A.	N.A.
Flaga Credit Agreements	€58.0	€6.6	€32.5	€18.9	€0.5	€3.6
UGI Utilities Credit Agreement	$300.0	$73.5	$2.0	$224.5	$53.0	$84.0
Energy Services Credit Agreement	$240.0	$89.0	$0.0	$151.0	$75.6	$89.0

	As of December 31, 2012				For the three months ended December 31, 2012
	Total Capacity	Borrowings Outstanding	Letters of Credit and Guarantees Outstanding	Available Capacity	Average Borrowings	Peak Borrowings
AmeriGas Credit Agreement	$525.0	$177.2	$54.1	$293.7	$109.9	$200.5
Antargaz Credit Facility	€40.0	€0.0	€0.0	€40.0	N.A.	N.A.
Flaga Credit Agreements	€58.0	€3.9	€19.9	€34.2	€11.6	€15.3
UGI Utilities Credit Agreement	$300.0	$73.1	$2.0	$224.9	$53.5	$78.6
Energy Services Credit Agreement	$170.0	$36.0	$0.0	$134.0	$65.3	$85.0

Energy Services has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper that is currently scheduled to expire in October 2014. The Receivables Facility provides Energy Services with the ability to borrow up to $150 million of eligible receivables during the period November 1, 2013 to May 31, 2014, and up to $75 million of eligible receivables during the period June 1, 2014 to October 31, 2014. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.

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balance sheet and the Company reflects a liability equal to the amount advanced by the bank or the commercial paper conduit. The Company records interest expense on amounts owed to the bank or commercial paper conduit, as applicable.

During the three months ended December 31, 2013 and 2012, Energy Services transferred trade receivables totaling $269.0 million and $224.3 million, respectively, to ESFC. During the three months ended December 31, 2013 and 2012, ESFC sold an aggregate $92.0 million and $79.5 million, respectively, of undivided interests in its trade receivables to the bank or commercial paper conduit, as applicable. At December 31, 2013, the balance of ESFC receivables was $88.5 million and there was $35.5 million sold to the commercial paper conduit. At December 31, 2012, the outstanding balance of ESFC receivables was $69.3 million and there was $33.0 million sold to the commercial paper conduit. During the three months ended December 31, 2013 and 2012, peak amounts sold under the Receivables Facility were $42.5 million and $46.5 million, respectively, and average daily amounts sold were $25.8 million and $6.9 million, respectively.

Dividends and Distributions. During the three months ended December 31, 2013, UGI declared and paid a cash dividend equal to $0.2825 per common share. On January 30, 2014, UGI’s Board of Directors declared a quarterly dividend of $0.2825 per common share. The dividend is payable April 1, 2014, to shareholders of record as of March 14, 2014. In addition, on January 30, 2014, the UGI Board of Directors authorized a share repurchase program for up to 10 million shares of UGI Corporation Common Stock. The authorization permits the execution of the share repurchase program over a four-year period.

During the three months ended December 31, 2013, the Partnership declared and paid quarterly distributions on all limited partner units at a rate of $0.84 per Common Unit for the quarter ended September 30, 2013. On January 29, 2014, the General Partner’s Board of Directors approved a quarterly distribution of $0.84 per limited partner unit for the quarter ended December 31, 2013. The distribution will be paid on February 18, 2014, to unitholders of record on February 10, 2014.

Cash Flows

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

Operating Activities. Cash flow provided by operating activities was $72.9 million in the 2013 three-month period compared to $31.1 million in the 2012 three-month period. Cash flow from operating activities before changes in operating working capital was $296.3 million in the 2013 three-month period compared to $264.9 million in the prior-year three-month period. The increase in cash flow from operating activities before changes in operating working capital largely reflects the effects of the higher operating results in the 2013 three-month period. Cash required to fund changes in operating working capital totaled $223.4 million in the 2013 three-month period compared to $233.8 million in the prior-year three-month period. The cash required to fund changes in operating working capital in the 2013 three-month period reflects, among other things, greater cash needed to fund operating working capital associated with the increased 2013 three-month period sales, principally changes in accounts receivable and inventories. This greater use of cash in the current-year period was partially offset by, among other things, the timing and amount of cash payments associated with accounts payable and changes in accrued income taxes.

Investing Activities. Cash flow used by investing activities was $148.8 million in the 2013 three-month period compared with $93.4 million in the prior-year period. Investing activity cash flow is principally affected by expenditures for property, plant and equipment; cash paid for acquisitions of businesses; changes in restricted cash balances; and proceeds from sales of assets.

Financing Activities. Cash flow provided by financing activities was $101.1 million in the 2013 three-month period compared with cash flow provided by financing activities of $87.5 million in the prior-year period. Changes in cash flow from financing activities are primarily due to issuances and repayments of long-term debt; net bank loan borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units; and issuances of UGI and AmeriGas Partners equity instruments.

AmeriGas Propane - Recent Propane Supply and Logistical Disruptions

Most of the United States, with the exception of the western parts of the country, has experienced colder than normal winter weather thus far this heating season. As a result of this colder than normal winter weather and a record volume of propane sales during the fall 2013 crop drying season, the retail propane industry began to experience significant logistical and infrastructure challenges in January 2014. These logistical disruptions are resulting in supply shortages in the affected parts of the United States and have also led to significant increases in wholesale propane supply costs at many major supply hubs. Current market conditions have also caused many of the impacted states to issue emergency declarations waiving maximum hour restrictions on drivers transporting propane in an effort to mitigate the logistical issues causing supply disruptions.

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In addition to incurring increased wholesale costs at our traditional supply points, AmeriGas Propane has taken additional steps to procure propane from alternative sources and has incurred incremental transportation costs in an effort to get adequate supply into the areas that are most affected. Since the retail propane business is a “margin-based” business in which gross profits are dependent upon the excess of the sales price over the propane supply costs, our earnings could be negatively impacted in the second quarter of Fiscal 2014 if AmeriGas Propane cannot pass on the full amount of the related cost increases to its customers. In addition, the combination of higher customer consumption and higher product costs could result in higher uncollectible accounts expense in Fiscal 2014. Finally, the cost increases experienced by AmeriGas Propane’s customers could lead to increased levels of customer conservation and attrition in the future.

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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 UGI International 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 UGI International may not, however, always be able to pass through product cost increases fully or on a timely basis, particularly when product costs rise rapidly. In order to reduce the volatility of LPG market price risk, the Partnership uses contracts for the forward purchase or sale of propane, propane fixed-price supply agreements and over-the-counter derivative commodity instruments including price swap and option contracts. In addition, Antargaz hedges a portion of its future U.S. dollar denominated LPG product purchases through the use of forward foreign exchange contracts as further described below. Our UGI International operations have used over-the-counter derivative commodity instruments and may from time to time enter into other derivative contracts, similar to those used by the Partnership, to reduce market risk associated with a portion of their LPG purchases. Over-the-counter derivative commodity instruments used to hedge forecasted purchases of propane are generally settled at expiration of the contract. 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.

Gas Utility's tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to its customers, including the cost of financial instruments used to hedge purchased gas costs. The recovery clauses provide for periodic adjustments for the difference between the total amounts actually collected from customers through PGC rates and the recoverable costs incurred. Because of this ratemaking mechanism, there is limited commodity price risk associated with our Gas Utility operations. Gas Utility uses derivative financial instruments including natural gas futures and option contracts traded on the NYMEX to reduce volatility in the cost of gas it purchases for its retail core-market customers. The cost of these derivative financial instruments, net of any associated gains or losses, is included in Gas Utility's PGC recovery mechanism. At December 31, 2013, the fair values of Gas Utility’s natural gas futures and option contracts were net gains of $2.0 million.

Electric Utility's DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of financial transmission rights (“FTRs”) and forward electricity purchase contracts, associated with our Electric Utility operations. At December 31, 2013, the fair values of Electric Utility’s electricity supply contracts were net losses of $3.2 million. At December 31, 2013, the fair values of Electric Utility’s FTRs were not material.

In addition, Gas Utility and Electric Utility from time to time enter into exchange-traded gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in their operations. These gasoline futures and swap contracts are recorded at fair value with changes in fair value reflected in other income. The amount of unrealized gains on these contracts and associated volumes under contract at December 31, 2013, were not material.

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

Midstream & Marketing purchases FTRs to economically hedge certain transmission costs that may be associated with its fixed-price electricity sales contracts. Midstream & Marketing from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Midstream & Marketing also 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 NYISO

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capacity swap contracts, 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.

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 UGID’s results.

The fair value of unsettled commodity price risk sensitive derivative instruments held at December 31, 2013 (excluding those Gas Utility and Electric Utility commodity derivative instruments which are refundable to or recoverable from customers) was a loss of $50.0 million. A hypothetical 10% adverse change in the market price of LPG, gasoline, natural gas, electricity and electricity transmission congestion charges would increase such loss by approximately $43.4 million at December 31, 2013.

Interest Rate Risk

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

Our variable-rate debt at December 31, 2013, includes our bank loan borrowings and Antargaz’ and Flaga’s variable-rate term loans. These debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz and Flaga have effectively fixed the underlying euribor interest rates on their term loans through their scheduled maturity dates through the use of interest rate swaps. In addition, Flaga’s $52.0 million U.S. dollar-denominated loan has been swapped from fixed-rate U.S. dollars to fixed-rate euro currency at issuance through cross currency swaps, removing interest rate risk and foreign currency exchange risk associated with the underlying interest and principal payments. At December 31, 2013, combined borrowings outstanding under these variable-rate debt agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled $421.5 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”). There were no unsettled IRPAs at December 31, 2013.

The fair value of unsettled interest rate risk sensitive derivative instruments held at December 31, 2013 (including pay-fixed, receive-variable interest rate swaps) was a loss of $29.2 million. A hypothetical 10% adverse change in the three-month euribor would result in a decrease in fair value of approximately $0.4 million.

Foreign Currency Exchange Rate Risk

Our primary currency exchange rate risk is associated with the U.S. dollar versus the euro. The U.S. dollar value of our foreign currency denominated assets and liabilities will fluctuate with changes in the associated foreign currency exchange rates. From time to time we use derivative instruments to hedge portions of our net investments in foreign subsidiaries (“net investment hedges”). Gains or losses on net investment hedges remain in accumulated other comprehensive income until such foreign operations are liquidated. At December 31, 2013, there were no unsettled net investment hedges outstanding. With respect to our net investments in our UGI International 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, 2013, by approximately $89.2 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, 2013, was a loss of $8.9 million. A hypothetical 10% adverse change in the value of the euro versus the U.S. dollar would result in a decrease in fair value of approximately $21.1 million.

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Derivative Financial Instrument Credit Risk

Certain of our derivative instrument agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts generally require cash deposits in margin accounts. Declines in natural gas, LPG and electricity product costs can require our business units to post collateral with counterparties or make margin deposits to brokerage accounts. At December 31, 2013 and 2012, restricted cash in brokerage accounts totaled $3.2 million and $6.9 million, respectively.

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

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ITEM 4. CONTROLS AND PROCEDURES


(a)	Evaluation of Disclosure Controls and Procedures

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

Remediation Plans

Management and the Board of Directors are committed to the remediation of the material weakness related to the accounting for commodity derivative instruments described in Item 8 of its Annual Report on Form 10-K for the fiscal year ended September 30, 2013. Subsequent to the end of the Company’s fiscal year ended September 30, 2013, the Company has taken or will take the following actions designed to remediate the material weakness: 1) supplement the Company’s existing technical expertise necessary to evaluate the accounting for commodity derivatives, 2) enhance controls over the assessment of new commodity derivative agreements to ensure the appropriate accounting is identified at the inception of the agreement, and 3) enhance controls over commodity derivative agreements to ensure that any ongoing compliance requirements are appropriately monitored. Management expects to remediate the material weakness during Fiscal 2014. In addition, management has discontinued the use of hedge accounting for commodity derivative instruments at Midstream & Marketing and will report mark-to-market adjustments on unsettled derivatives.


(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 1A. RISK FACTORS

In addition to the information presented below and 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, 2013, 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.

Supply and logistical disruptions in the current winter heating season may adversely affect our results of operations.

Most of the United States, with the exception of the western parts of the country, has experienced colder-than-normal winter weather thus far this heating season. As a result of this colder-than-normal winter weather and a record volume of propane sales during the fall 2013 crop drying season, the retail propane industry began to experience significant logistical and infrastructure challenges in January 2014. These logistical disruptions are resulting in supply shortages in the affected parts of the United States and have also led to significant increases in wholesale propane supply costs at many major supply hubs. Current market conditions have also caused many of the impacted states to issue emergency declarations waiving maximum hour restrictions on drivers transporting propane in an effort to mitigate the logistical issues causing supply disruptions.

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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

31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2013, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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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 7, 2014	By:	/s/ Kirk R. Oliver
			Kirk R. Oliver
			Chief Financial Officer


Date:	February 7, 2014	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, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2013, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32		Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended December 31, 2013, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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