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 March 31, 2015

OR

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

For the transition period from  ________ to ________            

Commission file number 1-11071

UGI CORPORATION

(Exact name of registrant as specified in its charter)

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

(610) 337-1000

(Registrant’s telephone number, including area code)

______________________________________

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

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

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

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

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

At April 30, 2015, there were 172,497,596 shares of UGI Corporation Common Stock, without par value, outstanding.

UGI CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS

	Page
Part I Financial Information
Item 1. Financial Statements (unaudited)
Condensed Consolidated Balance Sheets as of March 31, 2015, September 30, 2014 and March 31, 2014	1
Condensed Consolidated Statements of Income for the three and six months ended March 31, 2015 and 2014	2
Condensed Consolidated Statements of Comprehensive Income for the three and six months ended March 31, 2015 and 2014	3
Condensed Consolidated Statements of Cash Flows for the six months ended March 31, 2015 and 2014	4
Condensed Consolidated Statements of Changes in Equity for the six months ended March 31, 2015 and 2014	5
Notes to Condensed Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3. Quantitative and Qualitative Disclosures About Market Risk	42
Item 4. Controls and Procedures	44
Part II Other Information
Item 1A. Risk Factors	45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 6. Exhibits	45
Signatures	47

- i -

UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(Millions of dollars)

	March 31, 2015			September 30, 2014			March 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	445.5		$	419.5		$	493.6
Restricted cash	56.7			16.6			4.4
Accounts receivable (less allowances for doubtful accounts of $42.7, $39.1 and $57.9, respectively)	1,046.0			684.7			1,323.3
Accrued utility revenues	42.1			14.3			49.7
Inventories	201.5			423.0			324.4
Deferred income taxes	49.6			10.1			10.8
Utility regulatory assets	0.6			13.2			4.2
Derivative instruments	33.1			14.5			22.2
Prepaid expenses and other current assets	83.9			67.1			48.5
Total current assets	1,959.0			1,663.0			2,281.1
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,691.0, $2,633.0 and $2,637.8, respectively)	4,486.3			4,543.7			4,519.1
Goodwill	2,731.2			2,833.4			2,886.0
Intangible assets, net	537.5			576.4			608.2
Derivative instruments	20.9			12.5			0.8
Other assets	447.8			464.0			425.3
Total assets	$	10,182.7		$	10,093.0		$	10,720.5
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	470.5		$	77.2		$	65.0
Short-term borrowings	89.9			210.8			260.1
Accounts payable	440.8			459.8			634.1
Derivative instruments	129.0			40.2			27.5
Other current liabilities	719.5			642.9			668.6
Total current liabilities	1,849.7			1,430.9			1,655.3
Long-term debt	2,958.2			3,433.6			3,548.6
Deferred income taxes	942.0			1,005.1			984.4
Deferred investment tax credits	3.8			3.9			4.1
Derivative instruments	34.3			16.6			29.2
Other noncurrent liabilities	511.0			539.7			496.8
Total liabilities	6,299.0			6,429.8			6,718.4
Commitments and contingencies (Note 9)
Equity:
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized—450,000,000 shares; issued—173,788,741, 173,770,641 and 173,729,541 shares, respectively)	1,215.0			1,215.6			1,215.6
Retained earnings	1,715.0			1,509.4			1,579.9
Accumulated other comprehensive (loss) income	(85.4		)	(21.2		)	24.3
Treasury stock, at cost	(41.6		)	(44.7		)	(24.6		)
Total UGI Corporation stockholders’ equity	2,803.0			2,659.1			2,795.2
Noncontrolling interests, principally in AmeriGas Partners	1,080.7			1,004.1			1,206.9
Total equity	3,883.7			3,663.2			4,002.1
Total liabilities and equity	$	10,182.7		$	10,093.0		$	10,720.5

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(Millions of dollars, except per share amounts)

	Three Months Ended March 31,						Six Months Ended March 31,
	2015			2014			2015			2014
Revenues	$	2,455.6		$	3,163.3		$	4,460.2		$	5,479.2
Costs and expenses:
Cost of sales (excluding depreciation shown below)	1,205.4			2,001.3			2,610.0			3,431.2
Operating and administrative expenses	466.6			492.0			902.3			923.5
Utility taxes other than income taxes	4.8			4.8			8.9			9.0
Depreciation	73.8			76.8			149.6			155.4
Amortization	14.2			10.9			29.4			26.3
Other operating income, net	(11.3		)	(11.1		)	(25.4		)	(18.5		)
	1,753.5			2,574.7			3,674.8			4,526.9
Operating income	702.1			588.6			785.4			952.3
Loss from equity investees	(0.1		)	—			(1.1		)	—
Interest expense	(58.2		)	(59.5		)	(117.2		)	(118.8		)
Income before income taxes	643.8			529.1			667.1			833.5
Income tax expense	(161.6		)	(141.3		)	(184.7		)	(228.2		)
Net income	482.2			387.8			482.4			605.3
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners	(235.7		)	(173.4		)	(201.8		)	(268.9		)
Net income attributable to UGI Corporation	$	246.5		$	214.4		$	280.6		$	336.4
Earnings per common share attributable to UGI Corporation stockholders:
Basic	$	1.42		$	1.24		$	1.62		$	1.95
Diluted	$	1.40		$	1.22		$	1.60		$	1.92
Average common shares outstanding (thousands):
Basic	173,154			172,760			173,055			172,494
Diluted	175,628			175,121			175,715			174,789
Dividends declared per common share	$	0.2175		$	0.1883		$	0.4350		$	0.3767

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 March 31,						Six Months Ended March 31,
	2015			2014			2015			2014
Net income	$	482.2		$	387.8		$	482.4		$	605.3
Other comprehensive income (loss):
Net gains on derivative instruments (net of tax of $(10.4), $0.4, $(14.3) and $(7.1), respectively)	20.2			6.3			27.9			46.8
Reclassifications of net losses (gains) on derivative instruments (net of tax of $1.1, $3.3, $(0.4) and $5.3, respectively)	(1.9		)	(31.4		)	0.2			(45.2		)
Foreign currency adjustments (net of tax of $35.0, $0.6, $50.6 and $(3.1), respectively)	(64.5		)	(0.6		)	(95.0		)	11.7
Benefit plans (net of tax of $(0.2), $(0.1), $(0.6) and $0.0, respectively)	0.4			0.2			1.0			0.6
Other comprehensive (loss) income	(45.8		)	(25.5		)	(65.9		)	13.9
Comprehensive income	436.4			362.3			416.5			619.2
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	(235.1		)	(155.8		)	(200.1		)	(266.9		)
Comprehensive income attributable to UGI Corporation	$	201.3		$	206.5		$	216.4		$	352.3

See accompanying notes to condensed consolidated financial statements.

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UGI CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(Millions of dollars)

	Six Months Ended March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	482.4		$	605.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	179.0			181.7
Deferred income tax (benefit) expense, net	(33.7		)	13.0
Provision for uncollectible accounts	20.7			31.4
Unrealized losses on derivative instruments	125.2			8.0
Other, net	7.0			(6.8		)
Net change in:
Accounts receivable and accrued utility revenues	(469.7		)	(632.5		)
Inventories	208.0			43.0
Utility deferred fuel and power costs, net of changes in unsettled derivatives	55.8			(10.2		)
Accounts payable	31.8			194.1
Other current assets	(8.3		)	3.6
Other current liabilities	59.6			52.4
Net cash provided by operating activities	657.8			483.0
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(233.5		)	(224.4		)
Acquisitions of businesses, net of cash acquired	(7.3		)	(21.3		)
(Increase) decrease in restricted cash	(40.1		)	3.9
Other, net	15.1			4.5
Net cash used by investing activities	(265.8		)	(237.3		)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(75.0		)	(64.8		)
Distributions on AmeriGas Partners publicly held Common Units	(121.7		)	(116.1		)
Issuances of debt	—			175.1
Repayments of debt	(6.9		)	(182.8		)
(Decrease) increase in short-term borrowings	(112.2		)	51.5
Receivables Facility net repayments	(7.5		)	(19.5		)
Issuances of UGI Common Stock	5.0			10.3
Repurchases of UGI Common Stock	(17.3		)	(4.5		)
Other	(2.3		)	5.4
Net cash used by financing activities	(337.9		)	(145.4		)
EFFECT OF EXCHANGE RATE CHANGES ON CASH	(28.1		)	4.0
Cash and cash equivalents increase	$	26.0		$	104.3
Cash and cash equivalents:
End of period	$	445.5		$	493.6
Beginning of period	419.5			389.3
Increase	$	26.0		$	104.3

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)

	Six Months Ended March 31,
	2015			2014
Common stock, without par value
Balance, beginning of period	$	1,215.6		$	1,208.1
Common Stock issued in connection with employee and director plans (including (losses) gains on treasury stock transactions), net of tax withheld	(15.1		)	(5.2		)
Excess tax benefits realized on equity-based compensation	5.0			5.9
Equity-based compensation expense	9.5			6.8
Balance, end of period	$	1,215.0		$	1,215.6
Retained earnings
Balance, beginning of period	$	1,509.4		$	1,308.3
Net income attributable to UGI Corporation	280.6			336.4
Cash dividends on Common Stock	(75.0		)	(64.8		)
Balance, end of period	$	1,715.0		$	1,579.9
Accumulated other comprehensive (loss) income
Balance, beginning of period	$	(21.2	)	$	8.4
Net gains on derivative instruments, net of tax	27.9			13.5
Reclassification of net losses (gains) on derivative instruments, net of tax	1.9			(9.9		)
Benefit plans, net of tax	1.0			0.6
Foreign currency, net of tax	(95.0		)	11.7
Balance, end of period	$	(85.4	)	$	24.3
Treasury stock
Balance, beginning of period	$	(44.7	)	$	(32.3	)
Common stock issued in connection with employee and director plans, net of tax withheld	24.7			29.9
Repurchases of Common Stock	(17.3		)	(4.5		)
Reacquired common stock - employee and director plans	(4.3		)	(17.7		)
Balance, end of period	$	(41.6	)	$	(24.6	)
Total UGI Corporation stockholders’ equity	$	2,803.0		$	2,795.2
Noncontrolling interests
Balance, beginning of period	$	1,004.1		$	1,055.4
Net income attributable to noncontrolling interests, principally in AmeriGas Partners	201.8			268.9
Net gains on derivative instruments	—			33.3
Reclassification of net gains on derivative instruments	(1.7		)	(35.3		)
Dividends and distributions	(122.2		)	(116.1		)
Other	(1.3		)	0.7
Balance, end of period	$	1,080.7		$	1,206.9
Total equity	$	3,883.7		$	4,002.1

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)

Note 1 — Nature of Operations

UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports 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, natural gas production and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”

We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”). 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”), which is 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 March 31, 2015, the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises 69,131,947 Common Units held by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances as further described in Note 15 of our Annual Report on Form 10-K for the fiscal year ended September 30, 2014 (the “Company’s 2014 Annual Report”). Incentive distributions received by the General Partner during the six months ended March 31, 2015 and 2014 were $13.1 and $10.8, respectively.

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 and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business primarily in the Mid-Atlantic and Northeast U.S. 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 is 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 distribution utility business (“Gas Utility”) is 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.” 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. Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Note 2 — Summary of 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 limited partner interests in the Partnership, and outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests. We eliminate 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, 2014, 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 the Company’s 2014 Annual Report. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

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 March 31,		Six Months Ended March 31,
	2015	2014	2015	2014
Denominator (thousands of shares):
Average common shares outstanding for basic computation	173,154	172,760	173,055	172,494
Incremental shares issuable for stock options and awards	2,474	2,361	2,660	2,295
Average common shares outstanding for diluted computation	175,628	175,121	175,715	174,789

Derivative Instruments. Derivative instruments are reported in the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.

Certain of our derivative instruments are designated and qualify as cash flow hedges or net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on certain commodity derivative instruments used by Gas Utility and Electric Utility are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers.

Effective October 1, 2014, UGI International determined that on a prospective basis it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Midstream & Marketing has not applied cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Substantially all realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues. For additional information on our derivative instruments, see Note 12.

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

Consolidated Effective Income Tax Rate. UGI’s consolidated effective income tax rate, defined as total income tax (expense) or benefit as a percentage of income (loss) before income taxes, includes amounts associated with noncontrolling interests in the Partnership, which principally comprises AmeriGas Partners and AmeriGas OLP.  AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. As a result, UGI’s consolidated effective income tax rate is affected by the amount of income (loss) before income taxes attributable to noncontrolling interests in the Partnership not subject to income taxes.

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.

Note 3 — Accounting Changes

Accounting Standards Not Yet Adopted

Consolidation.In February 2015, the Financial Accounting Standards Board (“FASB”) issued new guidance regarding whether a reporting entity should consolidate certain types of legal entities. Among other things, the new guidance modifies the evaluation of whether limited partnerships and similar entities are variable interest entities (“VIEs”) or voting interest entities, and also eliminates the presumption that a general partner should consolidate a limited partnership. The new guidance also affects the consolidation analysis of reporting entities that are involved with VIEs including those that have fee arrangements and related party relationships. The new guidance is effective for the Company beginning in Fiscal 2017. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements, if any, from the adoption of the new guidance.

Debt Issuance Costs. In April 2015, the FASB issued Accounting Standards Update (“ASU”) No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Entities would apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2015.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This standard is effective for the Company for interim and annual periods beginning October 1, 2017 (Fiscal 2018) and allows for either full retrospective adoption or modified retrospective adoption. On April 29, 2015, the FASB issued for public comment a proposal to delay the effective date by one year. The Company is in the process of assessing the impact of the adoption of ASU 2014-09 on its results of operations, cash flows and 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)

Note 4 — Inventories

Inventories comprise the following:

	March 31, 2015		September 30, 2014		March 31, 2014
Non-utility LPG and natural gas	$	135.8	$	283.6	$	251.4
Gas Utility natural gas	6.3		82.7		7.5
Materials, supplies and other	59.4		56.7		65.5
Total inventories	$	201.5	$	423.0	$	324.4

At March 31, 2015, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”) having terms of 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 terms 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 for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

As of March 31, 2015, UGI Utilities has SCAAs with Energy Services and a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with non-affiliates at March 31, 2015, September 30, 2014 and March 31, 2014, comprising 0.2 billion cubic feet (“bcf”), 3.9 bcf and 0.2 bcf of natural gas, was $0.7, $16.8 and $0.8, respectively.

Note 5 — Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following:

	March 31, 2015			September 30, 2014			March 31, 2014
Goodwill (not subject to amortization)	$	2,731.2		$	2,833.4		$	2,886.0
Intangible assets:
Customer relationships, noncompete agreements and other	$	670.2		$	712.0		$	727.5
Accumulated amortization	(254.1		)	(263.8		)	(251.6		)
Intangible assets, net (definite-lived)	416.1			448.2			475.9
Trademarks and tradenames (indefinite-lived)	121.4			128.2			132.3
Total intangible assets, net	$	537.5		$	576.4		$	608.2

The decrease in goodwill and intangible assets at March 31, 2015, includes the effects of currency translation. Amortization expense of intangible assets was $12.0 and $25.0 for the three and six months ended March 31, 2015, respectively. Amortization expense of intangible assets was $8.9 and $22.2 for the three and six months ended March 31, 2014, respectively. Amortization expense included in cost of sales in the Condensed Consolidated Statements of Income is not material. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 2015 and for the next four fiscal years is as follows: remainder of Fiscal 2015 — $24.7; Fiscal 2016 — $44.3; Fiscal 2017 — $38.1; Fiscal 2018 — $36.4; Fiscal 2019 — $34.8.

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UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Note 6 — 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 9 in the Company’s 2014 Annual Report. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Utilities are included in our accompanying Condensed Consolidated Balance Sheets:

	March 31, 2015		September 30, 2014		March 31, 2014
Regulatory assets (a):
Income taxes recoverable	$	111.5	$	110.7	$	106.8
Underfunded pension and postretirement plans	105.5		110.1		91.0
Environmental costs	14.1		14.6		14.5
Deferred fuel and power costs	—		11.8		4.3
Removal costs, net	18.4		16.8		14.4
Other	3.1		4.2		4.9
Total regulatory assets	$	252.6	$	268.2	$	235.9
Regulatory liabilities (a):
Postretirement benefits	$	19.3	$	18.6	$	17.2
Environmental overcollections	—		0.3		1.9
Deferred fuel and power refunds	40.6		0.3		3.2
State tax benefits—distribution system repairs	10.6		10.1		9.0
Other	2.1		3.2		1.8
Total regulatory liabilities	$	72.6	$	32.5	$	33.1

(a) Noncurrent regulatory assets are recorded in other assets and regulatory liabilities are recorded in other current and other noncurrent liabilities in the Condensed Consolidated Balance Sheets.

Deferred fuel and power—costs and refunds. Gas Utility’s 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”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at March 31, 2015, September 30, 2014 and March 31, 2014 were $(3.4), $(1.4) and $2.4, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. We have chosen not to elect the NPNS exception under GAAP related to these derivative instruments for all forward electricity purchase contracts entered into prior to March 1, 2015. These electricity supply contracts are recognized on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its DS costs. At March 31, 2015, September 30, 2014, and March 31, 2014, the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(1.2), $0.3 and $0.4, respectively. These amounts are reflected in current and noncurrent derivative assets and current and noncurrent derivative liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds in the table above. Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility will elect the NPNS exception under GAAP and, as a result, the fair values of such contracts will not be recognized on the balance sheet (see Note 12).

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 instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric

- 10 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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 deferred fuel and power refunds. Unrealized gains or losses on FTRs at March 31, 2015, September 30, 2014, and March 31, 2014, were not material.

Note 7 — Energy Services Accounts Receivable Securitization Facility

Energy Services has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2015. The Receivables Facility provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November to May and up to $75 of eligible receivables during the period June to October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.

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. 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 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 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 six months ended March 31, 2015 and 2014, Energy Services transferred trade receivables to ESFC totaling $692.0 and $820.7, respectively. During the six months ended March 31, 2015 and 2014, ESFC sold an aggregate $216.5 and $251.0, respectively, of undivided interests in its trade receivables to the bank. At March 31, 2015, the outstanding balance of ESFC receivables was $96.9 and there were no amounts sold to the bank. At March 31, 2014, the outstanding balance of ESFC receivables was $124.1 of which $10.5 was sold to the bank. Losses on sales of receivables to the bank during the six months ended March 31, 2015 and 2014, which are included in interest expense on the Condensed Consolidated Statements of Income, were not material.

Note 8 — Debt

On March 27, 2015, UGI Utilities entered into an unsecured revolving credit agreement (the “UGI Utilities 2015 Credit Agreement”) with a group of banks providing for borrowings up to $300 (including a $100 sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2015 Credit Agreement, UGI Utilities terminated its then-existing $300 revolving credit agreement dated as of May 25, 2011. Under the UGI Utilities 2015 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2015 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.0. The UGI Utilities 2015 Credit Agreement is currently scheduled to expire in March 2016, but may be extended by UGI Utilities to March 2020 if on or before March 25, 2016, the Company satisfies certain requirements relating to approval by the PUC. The Company intends to seek such regulatory approval.

In anticipation of the Company’s pending acquisition of Total’s retail LPG distribution business in France (“Totalgaz”) expected to occur during the third quarter of Fiscal 2015, on April 30, 2015, UGI France, an indirect wholly owned subsidiary of UGI, entered into a new Senior Facilities Agreement with a consortium of banks (the “2015 Senior Facilities Agreement”) having a final maturity date of April 30, 2020. UGI France expects to draw under the Senior Facilities Agreement substantially concurrent with the closing of the pending Totalgaz acquisition. The 2015 Senior Facilities Agreement, when drawn, will consist of a €600 variable-rate term loan and also a €60 revolving credit facility. The term loan proceeds from the 2015 Senior Facilities Agreement will be used to (1) fund a portion of the acquisition of Totalgaz, including related fees and expenses; (2) prepay €342 principal amount, plus accrued interest, outstanding under Antargaz’ 2011 Senior Facilities Agreement due March 2016 (the “2011 Senior Facilities Agreement”); (3) settle Antargaz’ existing pay-fixed, receive-variable interest rate swaps associated with the 2011 Senior Facilities Agreement; and (4) for general corporate purposes. As of March 31, 2015, the fair value of the interest rate swaps was a loss of $10.3. UGI France does not intend to draw on either the term loan or the revolving credit facility until the closing date of the Totalgaz acquisition, which is required to occur no later than June 30, 2015, pursuant to the terms of the 2015 Senior Facilities Agreement.

- 11 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Borrowings under the 2015 Senior Facilities Agreement €600 term loan and the €60 revolving credit facility will bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate. The margin on such borrowings (which ranges from 1.60% to 2.70% for the term loan, and 1.45% to 2.55% for the revolving credit facility) will be dependent upon the ratio of UGI France’s consolidated total net debt to earnings before interest expense, income taxes, depreciation, and amortization (“EBITDA”), each as defined in the 2015 Senior Facilities Agreement. UGI France expects to enter into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan.

Principal amounts to be outstanding under the 2015 Senior Facilities Agreement term loan will be due as follows: €60 due April 30, 2018; €60 due April 30, 2019; and €480 million due April 30, 2020.The 2015 Senior Facilities Agreement restricts the ability of UGI France to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires UGI France and its consolidated subsidiaries to maintain a ratio of total net debt to EBITDA, each as defined in the 2015 Senior Facilities Agreement, that shall not exceed (a) 3.75 to 1.00 from the closing date of the pending Totalgaz acquisition to September 30, 2015, and (b) 3.50 to 1.00 from October 1, 2015, to the final maturity date. UGI France will generally be permitted to make restricted payments, such as dividends, if no event of default exists or would exist upon payment of such dividend.

Note 9 — 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 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 March 31, 2015 and 2014, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $9.6 and $11.1, respectively. We have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable.

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

UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At March 31, 2015, 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 UGI Utilities 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

- 12 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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.

Other Matters

Purported Class Action Lawsuits.  Between May and October of 2014, more than 35 purported class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI Corporation and a competitor by certain of their direct and indirect customers.  The class action lawsuits allege, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce the fill level of portable propane cylinders from 17 pounds to 15 pounds and combined to persuade its common customer, Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in violation of federal and certain state antitrust laws.  The claims seek treble damages, injunctive relief, attorneys’ fees and costs on behalf of the putative classes.  On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to the Western Division of the Western District of Missouri.  We are unable to reasonably estimate the impact, if any, arising from such litigation.  We believe we have strong defenses to the claims and intend to vigorously defend against them.

In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

Note 10 — Defined Benefit Pension and Other Postretirement Plans

In the U.S., we sponsor a 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 (“U.S. Pension Plan”). We also provide postretirement health care benefits to certain retirees and active employees and postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans.

- 13 -

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 March 31,	2015			2014			2015			2014
Service cost	$	2.5		$	2.3		$	0.1		$	0.1
Interest cost	6.3			6.5			0.2			0.2
Expected return on assets	(8.0		)	(7.3		)	(0.1		)	(0.1		)
Amortization of:
Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.1		)
Actuarial loss	2.5			1.9			—			—
Net benefit cost	3.4			3.5			0.1			0.1
Change in associated regulatory liabilities	—			—			1.0			0.9
Net expense	$	3.4		$	3.5		$	1.1		$	1.0
	Pension Benefits						Other Postretirement Benefits
Six Months Ended March 31,	2015			2014			2015			2014
Service cost	$	4.9		$	4.7		$	0.3		$	0.3
Interest cost	12.6			12.9			0.4			0.5
Expected return on assets	(15.9		)	(14.7		)	(0.3		)	(0.3		)
Amortization of:
Prior service cost (benefit)	0.2			0.2			(0.2		)	(0.2		)
Actuarial loss	5.0			3.8			—			—
Net benefit cost	6.8			6.9			0.2			0.3
Change in associated regulatory liabilities	—			—			1.9			1.8
Net expense	$	6.8		$	6.9		$	2.1		$	2.1

The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. During the six months ended March 31, 2015 and 2014, the Company made cash contributions to the U.S. Pension Plan of $5.6 and $7.0, respectively. The Company expects to make additional discretionary cash contributions of approximately $5.6 to the U.S. Pension Plan during the remainder of Fiscal 2015.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the six months ended March 31, 2015 and 2014.

We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans (“Supplemental Defined Benefit Plans”). We recorded pre-tax expense associated with these plans of $0.6 and $0.9 in the three months ended March 31, 2015 and 2014, respectively. We recorded pre-tax expense associated with these plans of $1.3 and $1.7 in the six months ended March 31, 2015 and 2014, respectively.

- 14 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Note 11 — Fair Value Measurements

Recurring Fair Value Measurements

The following table presents on a gross basis our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of March 31, 2015, September 30, 2014 and March 31, 2014:

	Asset (Liability)
	Level 1			Level 2			Level 3		Total
March 31, 2015:
Derivative instruments:
Assets:
Commodity contracts	$	13.9		$	8.3		$	—	$	22.2
Foreign currency contracts	$	—		$	35.8		$	—	$	35.8
Interest rate contracts	$	—		$	0.1		$	—	$	0.1
Cross-currency swaps	$	—		$	9.7		$	—	$	9.7
Liabilities:
Commodity contracts	$	(64.0	)	$	(104.3	)	$	—	$	(168.3	)
Interest rate contracts	$	—		$	(12.5	)	$	—	$	(12.5	)
Non-qualified supplemental postretirement grantor trust investments (a)	$	31.8		$	—		$	—	$	31.8
September 30, 2014:
Derivative instruments:
Assets:
Commodity contracts	$	10.6		$	19.8		$	—	$	30.4
Foreign currency contracts	$	—		$	12.8		$	—	$	12.8
Interest rate contracts	$	—		$	0.1		$	—	$	0.1
Cross-currency swaps	$	—		$	2.1		$	—	$	2.1
Liabilities:
Commodity contracts	$	(21.2	)	$	(32.9	)	$	—	$	(54.1	)
Foreign currency contracts	$	—		$	(0.1	)	$	—	$	(0.1	)
Interest rate contracts	$	—		$	(21.0	)	$	—	$	(21.0	)
Non-qualified supplemental postretirement grantor trust investments (a)	$	30.0		$	—		$	—	$	30.0
March 31, 2014 (b):
Derivative instruments:
Assets:
Commodity contracts	$	17.5		$	14.0		$	—	$	31.5
Foreign currency contracts	$	—		$	0.1		$	—	$	0.1
Liabilities:
Commodity contracts	$	(10.0	)	$	(19.7	)	$	—	$	(29.7	)
Foreign currency contracts	$	—		$	(5.6	)	$	—	$	(5.6	)
Interest rate contracts	$	—		$	(27.8	)	$	—	$	(27.8	)
Cross-currency swaps	$	—		$	(2.2	)	$	—	$	(2.2	)
Non-qualified supplemental postretirement grantor trust investments (a)	$	29.8		$	—		$	—	$	29.8

(a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.

(b) Certain immaterial amounts have been revised to correct the classification of derivatives.

- 15 -

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 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. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. 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 March 31, 2015, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,428.7 and $3,664.2, respectively. At March 31, 2014, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,613.6 and $3,864.4, 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 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 arising from concentrations of trade accounts receivable is limited because we have a large customer base which extends across many different U.S. markets and a number of foreign countries. For information regarding concentrations of credit risk associated with our derivative instruments, see Note 12. 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.

Note 12 — 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.

Commodity Price Risk

In order to manage market price risk associated with the Partnership’s fixed-price programs, 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. The Partnership from time to time, enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility. At March 31, 2015 and 2014, total volumes associated with LPG commodity derivative instruments totaled 362.5 million gallons and 121.9 million gallons, respectively. At March 31, 2015, the maximum period over which we are economically hedging our exposure to LPG commodity price risk is 45 months.

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 March 31, 2015 and 2014, the volumes of natural gas associated with Gas Utility’s unsettled

- 16 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

NYMEX natural gas futures and option contracts totaled 9.7 million dekatherms and 9.0 million dekatherms, respectively. At March 31, 2015, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism. (see Note 6).

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. For such contracts entered into by Electric Utility prior to March 1, 2015, Electric Utility chose not to elect the NPNS exception under GAAP related to these derivative instruments and the fair values of these contracts are reflected in current and noncurrent derivative instrument assets and liabilities in the accompanying Condensed Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Condensed Consolidated Balance Sheets in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility will elect the NPNS exception under GAAP and, as a result, the fair values of such contracts will not be recognized on the balance sheet. At March 31, 2015 and 2014, the volumes of Electric Utility’s forward electricity purchase contracts were 384.4 million kilowatt hours and 207.0 million kilowatt hours, respectively. At March 31, 2015, the maximum period over which these contracts extend is 14 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. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and 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. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). At March 31, 2015 and 2014, the total volumes associated with FTRs and NYISO capacity contracts totaled 124.6 million kilowatt hours and 482.5 million kilowatt hours, respectively. At March 31, 2015, the maximum period over which we are economically hedging electricity congestion and locational basis differences is 2 months.

In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures contracts, IntercontinentalExchange (“ICE”) natural gas basis swap contracts, and electricity futures contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas or propane. Because it could no longer assert the NPNS exception under GAAP for new contracts entered into for the forward purchase of natural gas and pipeline transportation, beginning in the second quarter of Fiscal 2014 Energy Services began recording these contracts at fair value with changes in fair value reflected in cost of sales.

At March 31, 2015 and 2014, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline contracts totaled 61.6 million dekatherms and 65.1 million dekatherms, respectively. At March 31, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk is 42 months. At March 31, 2015 and 2014, total volumes associated with Midstream & Marketing’s electricity call contracts and electricity put contracts totaled 356.0 million kilowatt hours and 315.4 million kilowatt hours, and 603.1 million kilowatt hours and 346.1 million kilowatt hours, respectively. At March 31, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity commodity price risk (excluding Electric Utility) is 24 months for electricity call contracts and 18 months for electricity put contracts. At March 31, 2015, the volumes associated with Midstream & Marketing’s natural gas storage NYMEX contracts totaled 0.6 million dekatherms and there were no propane storage NYMEX contracts. At March 31, 2014, the volumes associated with Midstream & Marketing’s natural gas storage NYMEX contracts totaled 0.1 million dekatherms and there were no propane storage NYMEX contracts.

At March 31, 2015, the amount of net gains associated with commodity derivative instruments previously designated and qualified as cash flow hedges expected to be reclassified into earnings during the next twelve months is not material.

- 17 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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 and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on their variable-rate term loans through the respective scheduled maturity dates. As of March 31, 2015 and 2014, the total notional amounts of variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) were €401.1 and €439.8, respectively.

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At March 31, 2015 and 2014, we had no unsettled IRPAs.

We account for interest rate swaps and IRPAs as cash flow hedges. At March 31, 2015, 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 $2.6.

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases during the heating-season months of October through March through the use of forward foreign currency exchange contracts. At March 31, 2015 and 2014, we were hedging a total of $223.5 and $199.4 of U.S. dollar-denominated LPG purchases, respectively. At March 31, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with U.S. dollar-denominated purchases of LPG is 35 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 March 31, 2015 and 2014, we had no euro-denominated net investment hedges.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At March 31, 2015, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $19.5.

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. dollar-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. dollar-denominated interest rate. We have designated this cross-currency swap as a cash flow hedge. At March 31, 2015, the amount of net gains associated with this cross-currency swap expected to be reclassified into earnings over the next twelve months is not material.

Derivative Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts generally require cash deposits in margin accounts. At March 31, 2015 and 2014, restricted cash in brokerage accounts totaled $56.7 and $4.4, respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would

- 18 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

incur if these counterparties failed to perform according to the terms of their contracts was not material at March 31, 2015. 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 March 31, 2015, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

Fair Value of Derivative Instruments

The following table presents the Company’s derivative assets and liabilities on a gross basis as of March 31, 2015 and 2014:

	March 31, 2015			March 31, 2014 (a)
Derivative assets:
Derivatives designated as hedging instruments:
Commodity contracts	$	—		$	10.9
Foreign currency contracts	35.8			0.1
Cross-currency contracts	9.7			—
Interest rate contracts	0.1			—
	45.6			11.0
Derivatives subject to utility rate regulation:
Commodity contracts	—			3.5
Derivatives not designated as hedging instruments:
Commodity contracts	22.2			17.1
Total derivative assets	$	67.8		$	31.6
Derivative liabilities:
Derivatives designated as hedging instruments:
Commodity contracts	$	—		$	(1.1	)
Foreign currency contracts	—			(5.6		)
Cross-currency contracts	—			(2.2		)
Interest rate contracts	(12.5		)	(27.8		)
	(12.5		)	(36.7		)
Derivatives subject to utility rate regulation:
Commodity contracts	(5.2		)	(0.7		)
Derivatives not designated as hedging instruments:
Commodity contracts	(163.1		)	(27.9		)
Total derivative liabilities	$	(180.8	)	$	(65.3	)

(a) Certain immaterial amounts have been revised to correct the classification of derivatives.

Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities are presented net by counterparty on our Condensed Consolidated Balance Sheets if the right of offset exists. Our derivative 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.

- 19 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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 over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, 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 table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.

The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of March 31, 2015 and 2014:

	Gross Amounts Recognized			Gross Amounts Offset in Balance Sheet			Net Amounts Recognized			Cash Collateral (Received) Pledged		Net Amounts Recognized in Balance Sheet
March 31, 2015
Derivative assets	$	67.8		$	(13.8	)	$	54.0		$	—	$	54.0
Derivative liabilities	$	(180.8	)	$	13.8		$	(167.0	)	$	3.7	$	(163.3	)
March 31, 2014
Derivative assets	$	31.6		$	(8.6	)	$	23.0		$	—	$	23.0
Derivative liabilities	$	(65.3	)	$	8.6		$	(56.7	)	$	—	$	(56.7	)

- 20 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Effect of Derivative Instruments

The following tables provide information on the effects of derivative instruments in the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three and six months ended March 31, 2015 and 2014:

	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 Interests into Income
Three Months Ended March 31,	2015			2014			2015			2014
Cash Flow Hedges:
Commodity contracts	$	—		$	7.8		$	0.1		$	39.9		Cost of sales
Foreign currency contracts	23.7			(0.2		)	6.5			(1.4		)	Cost of sales
Cross-currency contracts	5.4			0.1			(0.1		)	0.2			Interest expense
Interest rate contracts	1.6			(1.8		)	(3.5		)	(4.0		)	Interest expense
Total	$	30.7		$	5.9		$	3.0		$	34.7
	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Three Months Ended March 31,	2015			2014
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	(12.3	)	$	(22.2	)	Cost of sales
Commodity contracts	(4.6		)	—			Revenues
Commodity contracts	—			—			Operating expenses / other operating income, net
Total	$	(16.9	)	$	(22.2	)
	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 Interests into Income
Six Months Ended March 31,	2015			2014			2015			2014
Cash Flow Hedges:
Commodity contracts	$	—		$	61.2		$	(2.3	)	$	62.2		Cost of sales
Foreign currency contracts	32.4			(2.7		)	9.2			(3.5		)	Cost of sales
Cross-currency contracts	7.5			(1.1		)	(0.1		)	(0.1		)	Interest expense
Interest rate contracts	2.4			(3.5		)	(7.4		)	(8.1		)	Interest expense
Total	$	42.3		$	53.9		$	(0.6	)	$	50.5
	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Six Months Ended March 31,	2015			2014
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	(304.8	)	$	(9.4	)	Cost of sales
Commodity contracts	(0.8		)	—			Revenues
Commodity contracts	(0.5		)	0.1			Operating expenses / other operating income, net
Total	$	(306.1	)	$	(9.3	)

The amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material for the three and six months ended March 31, 2015 and 2014.

- 21 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery, or sale, of energy products, 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, certain of these contracts qualify for NPNS 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.

Note 13 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI during the three and six months ended March 31, 2015 and 2014:

Three Months Ended March 31, 2015	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - December 31, 2014	$	(20.0	)	$	1.7		$	(21.8	)	$	(40.1	)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			20.2			(64.5		)	(44.3		)
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0.6			(3.0		)	—			(2.4		)
Reclassification adjustments tax expense	(0.2		)	1.1			—			0.9
Reclassification adjustments (after-tax)	0.4			(1.9		)	—			(1.5		)
Other comprehensive income (loss)	0.4			18.3			(64.5		)	(45.8		)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			0.5			—			0.5
Other comprehensive income (loss) attributable to UGI	0.4			18.8			(64.5		)	(45.3		)
AOCI - March 31, 2015	$	(19.6	)	$	20.5		$	(86.3	)	$	(85.4	)
Three Months Ended March 31, 2014	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - December 31, 2013	$	(16.0	)	$	(15.8	)	$	64.0		$	32.2
Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			6.3			(0.6		)	5.7
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0.3			(34.7		)	—			(34.4		)
Reclassification adjustments tax benefit	(0.1		)	3.3			—			3.2
Reclassification adjustments (after-tax)	0.2			(31.4		)	—			(31.2		)
Other comprehensive income (loss)	0.2			(25.1		)	(0.6		)	(25.5		)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			17.6			—			17.6
Other comprehensive income (loss) attributable to UGI	0.2			(7.5		)	(0.6		)	(7.9		)
AOCI - March 31, 2014	$	(15.8	)	$	(23.3	)	$	63.4		$	24.3

- 22 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Six Months Ended March 31, 2015	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - September 30, 2014	$	(20.6	)	$	(9.3	)	$	8.7		$	(21.2	)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			27.9			(95.0		)	(67.1		)
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	1.6			0.6			—			2.2
Reclassification adjustments tax expense	(0.6		)	(0.4		)	—			(1.0		)
Reclassification adjustments (after-tax)	1.0			0.2			—			1.2
Other comprehensive income (loss)	1.0			28.1			(95.0		)	(65.9		)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			1.7			—			1.7
Other comprehensive income (loss) attributable to UGI	1.0			29.8			(95.0		)	(64.2		)
AOCI - March 31, 2015	$	(19.6	)	$	20.5		$	(86.3	)	$	(85.4	)
Six Months Ended March 31, 2014	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - September 30, 2013	$	(16.4	)	$	(26.9	)	$	51.7		$	8.4
Other comprehensive income before reclassification adjustments (after-tax)	—			46.8			11.7			58.5
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0.6			(50.5		)	—			(49.9		)
Reclassification adjustments tax benefit	—			5.3			—			5.3
Reclassification adjustments (after-tax)	0.6			(45.2		)	—			(44.6		)
Other comprehensive income	0.6			1.6			11.7			13.9
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			2.0			—			2.0
Other comprehensive income attributable to UGI	0.6			3.6			11.7			15.9
AOCI - March 31, 2014	$	(15.8	)	$	(23.3	)	$	63.4		$	24.3

For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 12.

- 23 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

Note 14 — 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, “Summary of Significant Accounting Policies,” in the Company’s 2014 Annual Report. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization as adjusted for net gains and losses on commodity derivative instruments not associated with current-period transactions (“Partnership Adjusted EBITDA”). Although we use Partnership Adjusted 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 Adjusted 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 as adjusted for gains and losses on commodity derivative instruments not associated with current-period transactions. Net gains and losses on commodity derivative instruments not associated with current-period transactions are reflected in Corporate & Other because the Company’s chief operating decision maker does not consider such items when evaluating the financial performance of our reportable segments.

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Three Months Ended March 31, 2015
Revenues	$	2,455.6		$	(114.7	)	(c)	$	1,100.3		$	468.0		$	409.4		$	24.8	$	347.2		$	172.9		$	47.7
Cost of sales	$	1,205.4		$	(114.0	)	(c)	$	505.2		$	258.2		$	296.5		$	9.4	$	200.3		$	123.3		$	(73.5	)
Segment profit:
Operating income	$	702.1		$	0.1			$	296.9		$	139.3		$	93.9		$	8.0	$	53.2		$	11.5		$	99.2
Loss from equity investees	(0.1		)	—				—			—			—			—		(0.1		)	—			—
Interest expense	(58.2		)	—				(41.1		)	(10.1		)	(0.5		)	—		(4.9		)	(0.9		)	(0.7		)
Income before income taxes	$	643.8		$	0.1			$	255.8		$	129.2		$	93.4		$	8.0	$	48.2		$	10.6		$	98.5
Partnership Adjusted EBITDA (a)								$	342.1
Noncontrolling interests’ net income	$	235.7		$	—			$	88.3		$	—		$	—		$	—	$	0.3		$	—		$	147.1
Depreciation and amortization	$	88.0		$	(0.1	)		$	48.1		$	14.5		$	3.6		$	3.3	$	11.8		$	5.2		$	1.6
Capital expenditures	$	91.4		$	—			$	26.8		$	39.2		$	5.9		$	2.3	$	9.6		$	5.4		$	2.2

- 24 -

UGI CORPORATION AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Three Months Ended March 31, 2014
Revenues	$	3,163.3		$	(164.7	)	(c)	$	1,493.7		$	480.1		$	588.9		$	25.1	$	412.0		$	277.2		$	51.0
Cost of sales	$	2,001.3		$	(164.0	)	(c)	$	885.5		$	278.8		$	457.9		$	9.4	$	266.7		$	222.7		$	44.3
Segment profit:
Operating income (loss)	$	588.6		$	0.2			$	284.8		$	134.5		$	111.5		$	9.9	$	52.9		$	10.9		$	(16.1	)
Income from equity investees	—			—				—			—			—			—		—			—			—
Interest expense	(59.5		)	—				(42.0		)	(8.4		)	(1.0		)	—		(6.4		)	(1.1		)	(0.6		)
Income (loss) before income taxes	$	529.1		$	0.2			$	242.8		$	126.1		$	110.5		$	9.9	$	46.5		$	9.8		$	(16.7	)
Partnership Adjusted EBITDA (a)								$	331.2
Noncontrolling interests’ net income	$	173.4		$	—			$	173.2		$	—		$	—		$	—	$	0.2		$	—		$	—
Depreciation and amortization	$	87.7		$	(0.1	)		$	49.2		$	13.6		$	3.2		$	2.7	$	10.3		$	7.2		$	1.6
Capital expenditures	$	85.3		$	—			$	27.7		$	30.0		$	8.4		$	1.8	$	11.3		$	4.2		$	1.9

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Six Months Ended March 31, 2015
Revenues	$	4,460.2		$	(182.4	)	(c)	$	1,989.1		$	728.5		$	706.4		$	41.3	$	685.1		$	397.5		$	94.7
Cost of sales	$	2,610.0		$	(181.0	)	(c)	$	967.6		$	385.4		$	530.9		$	17.4	$	409.6		$	295.9		$	184.2
Segment profit:
Operating income (loss)	$	785.4		$	0.1			$	436.6		$	211.1		$	140.1		$	7.3	$	91.6		$	26.6		$	(128.0	)
Loss from equity investees	(1.1		)	—				—			—			—			—		(1.1		)	—			—
Interest expense	(117.2		)	—				(82.1		)	(20.2		)	(1.1		)	—		(10.5		)	(1.9		)	(1.4		)
Income (loss) before income taxes	$	667.1		$	0.1			$	354.5		$	190.9		$	139.0		$	7.3	$	80.0		$	24.7		$	(129.4	)
Partnership Adjusted EBITDA (a)								$	530.6
Noncontrolling interests’ net income	$	201.8		$	—			$	155.1		$	—		$	—		$	—	$	0.4		$	—		$	46.3
Depreciation and amortization	$	179.0		$	(0.1	)		$	97.5		$	28.8		$	7.2		$	6.0	$	25.1		$	11.3		$	3.2
Capital expenditures	$	214.9		$	—			$	57.2		$	92.7		$	18.7		$	8.9	$	21.7		$	11.8		$	3.9
As of March 31, 2015
Total assets	$	10,182.7		$	(109.5	)		$	4,423.8		$	2,359.1		$	690.8		$	281.2	$	1,569.2		$	539.7		$	428.4
Short-term borrowings	$	89.9		$	—			$	55.0		$	30.5		$	—		$	—	$	0.1		$	4.3		$	—
Goodwill	$	2,731.2		$	—			$	1,949.7		$	182.1		$	5.6		$	—	$	510.9		$	76.7		$	6.2

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Notes to Condensed Consolidated Financial Statements

(unaudited)

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

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Six Months Ended March 31, 2014
Revenues	$	5,479.2		$	(230.2	)	(c)	$	2,539.5		$	751.7		$	861.6		$	45.9	$	837.3		$	570.5		$	102.9
Cost of sales	$	3,431.2		$	(228.4	)	(c)	$	1,468.2		$	414.3		$	685.0		$	20.0	$	549.2		$	454.4		$	68.5
Segment profit:
Operating income (loss)	$	952.3		$	0.1			$	464.5		$	216.6		$	143.3		$	14.3	$	96.1		$	24.6		$	(7.2	)
Income from equity investees	—			—				—			—			—			—		—			—			—
Interest expense	(118.8		)	—				(83.6		)	(16.8		)	(2.0		)	—		(12.8		)	(2.4		)	(1.2		)
Income (loss) before income taxes	$	833.5		$	0.1			$	380.9		$	199.8		$	141.3		$	14.3	$	83.3		$	22.2		$	(8.4	)
Partnership EBITDA (a)								$	561.5
Noncontrolling interests’ net income	$	268.9		$	—			$	268.6		$	—		$	—		$	—	$	0.3		$	—		$	—
Depreciation and amortization	$	181.7		$	(0.1	)		$	101.5		$	27.0		$	5.8		$	5.3	$	25.3		$	13.8		$	3.1
Capital expenditures	$	188.1		$	(1.2	)		$	51.0		$	62.9		$	30.1		$	11.1	$	21.1		$	8.8		$	4.3
As of March 31, 2014
Total assets	$	10,720.5		$	(116.3	)		$	4,692.3		$	2,195.4		$	643.2		$	283.9	$	1,923.2		$	660.4		$	438.4
Short-term borrowings	$	260.1		$	—			$	198.0		$	6.5		$	51.5		$	—	$	—		$	4.1		$	—
Goodwill	$	2,886.0		$	—			$	1,939.0		$	182.1		$	2.8		$	—	$	655.3		$	99.8		$	7.0

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

	Three Months Ended March 31,						Six Months Ended March 31,
	2015			2014			2015			2014
Partnership Adjusted EBITDA	$	342.1		$	331.2		$	530.6		$	561.5
Depreciation and amortization	(48.1		)	(49.2		)	(97.5		)	(101.5		)
Noncontrolling interests (i)	2.9			2.8			3.5			4.5
Operating income	$	296.9		$	284.8		$	436.6		$	464.5

(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) net expenses of UGI’s captive general liability insurance company, and (4) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include net gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $102.2 and $(13.2) during the three months ended March 31, 2015 and 2014, respectively, and $(127.5) and $(6.0) during the six months ended March 31, 2015 and 2014, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and, in the three and six months ended March 31, 2014, an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.

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

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UGI CORPORATION AND SUBSIDIARIES

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

Forward-Looking Statements

Information contained in this Quarterly Report on Form 10-Q may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Such statements use forward-looking words such as “believe,” “plan,” “anticipate,” “continue,” “estimate,” “expect,” “may,” 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 liquefied petroleum gases, oil, electricity, and natural gas and the capacity to transport product to our customers; (3) changes in domestic and foreign laws and regulations, including safety, tax, consumer protection and accounting matters; (4) inability to timely recover costs through utility rate proceedings; (5) the impact of pending and future legal proceedings; (6) competitive pressures from the same and alternative energy sources; (7) failure to acquire new customers and retain current customers thereby reducing or limiting any increase in revenues; (8) liability for environmental claims; (9) increased customer conservation measures due to high energy prices and improvements in energy efficiency and technology resulting in reduced demand; (10) adverse labor relations; (11) large customer, counterparty or supplier defaults; (12) liability in excess of insurance coverage for personal injury and property damage arising from explosions and other catastrophic events, including acts of terrorism, resulting from operating hazards and risks incidental to generating and distributing electricity and transporting, storing and distributing natural gas and liquefied petroleum gases (“LPG”); (13) political, regulatory and economic conditions in the United States and in foreign countries, including the current conflicts in the Middle East and those involving Russia, and 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) changes in 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 the Company’s 2014 Annual Report, are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. We undertake no obligation to update publicly any forward-looking statement whether as a result of new information or future events except as required by the federal securities laws.

ANALYSIS OF RESULTS OF OPERATIONS

The following analyses compare the Company’s results of operations for the three months ended March 31, 2015 (“2015 three-month period”) with the three months ended March 31, 2014 (“2014 three-month period”) and the six months ended March 31, 2015 (“2015 six-month period”) with the six months ended March 31, 2014 (“2014 six-month period”). Our analyses of results of operations should be read in conjunction with the segment information included in Note 14 to the condensed consolidated financial statements. 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, excluding the effects of gains and losses on commodity derivative instruments not associated with current period transactions as further discussed below, are significantly higher in our first and second fiscal quarters.

Volatility in net income attributable to UGI as determined in accordance with accounting principles generally accepted in the U.S. (“GAAP”) can occur as a result of gains and losses on commodity derivative instruments not associated with current period transactions. These gains and losses result principally from recording changes in unrealized gains and losses on unsettled commodity derivative instruments and, to a much lesser extent, certain realized gains and losses on settled commodity derivative instruments that are not associated with current-period transactions. As further described below under the caption, “Non-GAAP Financial Measures - Adjusted Net Income Attributable to UGI and Adjusted Earnings Per Diluted Share,” UGI management uses “adjusted net income attributable to UGI” and “adjusted diluted earnings per share,” both of which are non-GAAP financial measures, when

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UGI CORPORATION AND SUBSIDIARIES

evaluating UGI’s overall performance. Adjusted net income attributable to UGI is net income attributable to UGI after excluding net after-tax gains and losses on commodity derivative instruments not associated with current-period transactions and items that management regards as highly unusual and not expected to recur.

Executive Overview

Three Months Ended March 31, 2015 Results

We recorded GAAP net income attributable to UGI Corporation for the 2015 three-month period of $246.5 million, equal to $1.40 per diluted share, compared to GAAP net income attributable to UGI Corporation for the 2014 three-month period of $214.4 million, equal to $1.22 per diluted share. Adjusted net income attributable to UGI (which excludes the effects of gains and losses on commodity derivative instruments not associated with current period transactions) was $215.7 million (equal to $1.23 per diluted share) in the 2015 three-month period compared to $222.1 million (equal to $1.27 per diluted share) in the 2014 three-month period.

The $32.1 million increase in GAAP net income attributable to UGI during the 2015 three-month period includes the effects of after-tax gains on commodity derivative instruments not associated with current-period transactions totaling $30.8 million (equal to $0.17 per diluted share) in the current-year three-month period compared to after-tax losses of $(7.7) million (equal to $(0.05) per diluted share) in the prior-year three-month period. These after-tax gains and losses on commodity derivative instruments are included in “Corporate & Other” in our business unit summary table below.

The $6.4 million decrease in adjusted net income attributable to UGI in the 2015 three-month period includes an $11.5 million decrease in net income from Midstream & Marketing partially offset by a $3.6 million increase in net income from Gas Utility and a $2.8 million increase in net income attributable to UGI from AmeriGas Propane. The decrease in Midstream & Marketing results in the 2015 three-month period principally reflects lower natural gas marketing and peaking total margin, and lower margin from capacity management. Although Midstream & Marketing continued to benefit during the 2015 three-month period from the growing demand for natural gas in the Northeast and Mid-Atlantic regions and the current infrastructure gap that exists in bringing Marcellus Shale gas to markets in these regions, there was greater volatility in capacity prices in the prior-year three-month period due to more extreme winter weather conditions. The higher Gas Utility results principally reflect the effects on volumes sold from weather that was colder than in the prior-year three-month period and year-over-year customer growth, while the increase in AmeriGas Propane results principally reflects lower operating and administrative expenses. UGI International net income attributable to UGI during the 2015 three-month period was $1.3 million lower than in the prior-year period. UGI International net income in the 2015 three-month period includes after-tax expenses of approximately $5.0 million ($0.03 per diluted share) associated with the Company’s proposed Totalgaz acquisition in France. UGI International weather in the 2015 three-month period was colder than in the prior-year period which resulted in higher 2015 three-month period retail volumes sold and greater local currency total margin. Although the euro and the British pound sterling were significantly weaker during the 2015 three-month period compared to the prior-year period, the effects on UGI International net income resulting from these weaker currencies were substantially offset by gains recognized on foreign currency exchange contracts.

Six Months Ended March 31, 2015 Results

We recorded GAAP net income attributable to UGI Corporation for the 2015 six-month period of $280.6 million, equal to $1.60 per diluted share, compared to GAAP net income attributable to UGI Corporation for the 2014 six-month period of $336.4 million, equal to $1.92 per diluted share. Adjusted net income attributable to UGI (which excludes the effects of gains and losses on commodity derivative instruments not associated with current period transactions and, with respect to the 2014 six-month period, the retroactive impact of a change in tax laws in France) was $331.7 million (equal to $1.89 per diluted share) in the 2015 six-month period compared to $345.6 million (equal to $1.98 per diluted share) in the 2014 six-month period.

The $55.8 million decrease in GAAP net income attributable to UGI during the 2015 six-month period reflects the effects of after-tax losses on commodity derivative instruments not associated with current-period transactions totaling $(51.1) million (equal to $(0.29) per diluted share) compared to after-tax losses of $(3.5) million (equal to $(0.02) per diluted share) in the 2014 six-month period. The $51.1 million of after-tax losses on commodity derivative instruments not associated with current-period transactions recorded in the 2015 six-month period reflect the effects of substantial declines in worldwide energy commodity prices. These after-tax gains and losses on commodity derivative instruments not associated with current period transactions are included in “Corporate & Other” in our business unit summary table below. GAAP net income attributable to UGI in the 2014 six-month period also reflects the retroactive effect to Fiscal 2013 of a change in tax laws in France, which increased 2014 six-month period tax expense, and reduced 2014 six-month period GAAP net income attributable to UGI, by $5.7 million or $0.03 per diluted share.

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UGI CORPORATION AND SUBSIDIARIES

The $13.9 million decrease in adjusted net income attributable to UGI in the 2015 six-month period includes a $7.2 million decrease in net income from Midstream & Marketing, a $3.8 million decrease in net income attributable to UGI from AmeriGas Propane, and a $2.9 million decrease in net income from Gas Utility. The decrease in Midstream & Marketing results principally reflects slightly lower total margin and higher operating and depreciation expenses due in part to the expansion of our midstream assets. As previously mentioned, Midstream & Marketing continued to benefit from the growing demand for natural gas in the Northeast and Mid-Atlantic regions and the infrastructure gap that exists in bringing Marcellus Shale gas to markets in these regions. The lower AmeriGas Propane results principally reflect the effects on volumes sold from weather that was warmer than normal and warmer than in the prior-year six-month period. Gas Utility results in the 2015 six-month period were lower, notwithstanding a slight increase in total margin, reflecting higher operating and administrative expenses. UGI International net income attributable to UGI during the 2015 six-month period was $69.7 million, a decline of $2.2 million from the $71.9 million in net income recorded in the 2014 six-month period (excluding the effects in the 2014 six-month period of the $5.7 million French tax law adjustment retroactive to Fiscal 2013). UGI International net income in the 2015 six-month period includes after-tax expenses of approximately $7.0 million ($0.04 per diluted share) associated with the Company’s proposed acquisition of Totalgaz. Although the euro and the British pound sterling were significantly weaker during the 2015 six-month period, the effects of the weaker currencies on UGI International net income were substantially offset by gains on foreign currency exchange contracts. UGI International average temperatures during the 2015 six-month period were warmer than normal but slightly colder than the prior-year six-month period.

We believe each of our business units has sufficient liquidity in the form of revolving credit facilities and, with respect to Energy Services, also an accounts receivable securitization facility, to fund business operations during Fiscal 2015 (see “Financial Condition and Liquidity” below).

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

As previously mentioned, UGI management uses “adjusted net income attributable to UGI” and “adjusted diluted earnings per 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 after excluding net after-tax gains and losses on commodity derivative instruments not associated with current-period transactions, principally comprising changes in unrealized gains and losses on commodity derivative instruments, and items that management regards as highly unusual and not expected to recur.

Midstream & Marketing did not apply cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Effective October 1, 2014, UGI International determined that on a prospective basis it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues.

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) gains and losses on 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.

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

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UGI CORPORATION AND SUBSIDIARIES

	Three Months Ended March 31,					Six Months Ended March 31,
(Millions of dollars, except per share amounts)	2015			2014		2015		2014
Adjusted net income attributable to UGI Corporation:
Net income attributable to UGI Corporation	$	246.5		$	214.4	$	280.6	$	336.4
Net after-tax (gains) losses on commodity derivative instruments not associated with current period transactions (a)	(30.8		)	7.7		51.1		3.5
Retroactive impact of change in French tax law	—			—		—		5.7
Adjusted net income attributable to UGI Corporation	$	215.7		$	222.1	$	331.7	$	345.6
Adjusted diluted earnings per share:
UGI Corporation earnings per share - diluted	$	1.40		$	1.22	$	1.60	$	1.92
Net after-tax (gains) losses on commodity derivative instruments not associated with current period transactions (b)	(0.17		)	0.05		0.29		0.03
Retroactive impact of change in French tax law	—			—		—		0.03
Adjusted diluted earnings per share	$	1.23		$	1.27	$	1.89	$	1.98

(a) Income taxes associated with pre-tax adjustments determined using statutory business unit tax rates.

(b) Includes the effects of rounding.

RESULTS OF OPERATIONS

2015 three-month period compared to the 2014 three-month period

Net Income Attributable to UGI Corporation by Business Unit

For the three months ended March 31,	2015				2014					Variance - Favorable (Unfavorable)
(Dollars in millions)	Amount		% of Total		Amount			% of Total		Amount			% Change
AmeriGas Propane	$	45.5	18.5	%	$	42.7		19.9	%	$	2.8		6.6	%
UGI International	37.5		15.2	%	38.8			18.1	%	(1.3		)	(3.4	)%
Gas Utility	78.0		31.6	%	74.4			34.7	%	3.6			4.8	%
Midstream & Marketing	60.3		24.5	%	71.8			33.5	%	(11.5		)	(16.0	)%
Corporate & Other (a)	25.2		10.2	%	(13.3		)	(6.2	)%	38.5			N.M.
Net income attributable to UGI Corporation	$	246.5	100.0	%	$	214.4		100.0	%	$	32.1		15.0	%

(a) Includes net after-tax gains (losses) on commodity derivative instruments not associated with current-period transactions of $30.8 million and $(7.7) million for the three months ended March 31, 2015 and 2014, respectively.

N.M. — Variance is not meaningful.

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UGI CORPORATION AND SUBSIDIARIES

AmeriGas Propane

For the three months ended March 31,	2015			2014			Increase (Decrease)
(Dollars in millions)
Revenues	$	1,100.3		$	1,493.7		$	(393.4	)	(26.3	)%
Total margin (a)	$	595.1		$	608.2		$	(13.1	)	(2.2	)%
Operating and administrative expenses	$	257.4		$	281.4		$	(24.0	)	(8.5	)%
Partnership Adjusted EBITDA (b)	$	342.1		$	331.2		$	10.9		3.3	%
Operating income (b)	$	296.9		$	284.8		$	12.1		4.2	%
Retail gallons sold (millions)	448.0			474.9			(26.9		)	(5.7	)%
Degree days—% colder than normal (c)	0.3		%	8.1		%	—			—

(a) Total margin represents total revenues less total cost of sales. Total margin for the three months ended March 31, 2015 excludes net pre-tax gains of $74.7 million on AmeriGas Propane commodity derivative instruments not associated with current-period transactions.

(b) Partnership Adjusted EBITDA (earnings before interest expense, income taxes and depreciation and amortization as adjusted for net gains and losses on commodity derivative instruments not associated with current-period transactions) 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 GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 14 to condensed consolidated financial statements).

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

AmeriGas Propane’s retail gallons sold during the 2015 three-month period decreased 5.7% compared with the prior-year period. The decline in retail gallons sold in the 2015 three-month period principally reflects average temperatures based upon heating degree days that were near normal but 7.2% warmer than the prior year three-month period.

Retail propane revenues decreased $351.1 million during the 2015 three-month period reflecting lower average retail selling prices ($273.8 million), principally the result of the significantly lower propane product costs, and, to a much lesser extent, the effects of the lower retail volumes sold ($77.3 million). Wholesale propane revenues decreased $42.2 million during the 2015 three-month period reflecting the effects of lower wholesale volumes sold ($29.6 million) and lower wholesale selling prices ($12.6 million). Average daily wholesale propane commodity prices during the 2015 three-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 60% lower than such prices during the 2014 three-month period. Revenues from fee income and other ancillary sales and services in the 2015 three-month period were equal to such revenues in the prior-year period. Total cost of sales during the 2015 three-month period decreased $380.3 million to $430.6 million principally reflecting the effects of the lower average propane product costs ($306.3 million) and the lower retail and wholesale volumes sold ($74.4 million) on propane cost of sales.

Total margin decreased $13.1 million in the 2015 three-month period principally reflecting lower retail propane total margin ($10.7 million) and, to a much lesser extent, lower margin from wholesale sales and ancillary sales and services. The decrease in retail propane total margin largely reflects the previously mentioned decline in retail gallons sold partially offset by the impact of slightly higher average retail propane unit margin.

Partnership Adjusted EBITDA in the 2015 three-month period increased $10.9 million principally reflecting the lower total margin ($13.1 million) more than offset by lower operating and administrative expenses ($24.0 million). The decrease in operating and administrative expenses reflects, among other things, lower uncollectible accounts expenses ($8.1 million); lower vehicle expenses ($7.4 million) due in large part to lower vehicle fuel expenses; and lower compensation and benefits expenses ($2.0 million). Operating income increased $12.1 million in the 2015 three-month period principally reflecting the higher Partnership Adjusted EBITDA ($10.9 million) and slightly lower depreciation expense.    

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UGI International

For the three months ended March 31,	2015			2014			Increase (Decrease)
(Dollars in millions)
Revenues	$	520.1		$	689.2		$	(169.1	)	(24.5	)%
Total margin (a)	$	196.5		$	199.8		$	(3.3	)	(1.7	)%
Operating and administrative expenses	$	114.9		$	120.6		$	(5.7	)	(4.7	)%
Operating income	$	64.7		$	63.8		$	0.9		1.4	%
Income before income taxes	$	58.8		$	56.3		$	2.5		4.4	%
Retail gallons sold (millions) (b)	190.4			174.9			15.5			8.9	%
Antargaz degree days—% (warmer) than normal (c)	(0.6		)%	(16.5		)%	—			—
Flaga degree days—% (warmer) than normal (c)	(10.9		)%	(18.1		)%	—			—

(a) Total margin represents total revenues less total cost of sales. Total margin for the three months ended March 31, 2015 excludes net pre-tax gains of $26.9 million on UGI International’s commodity derivative instruments not associated with current-period transactions.

(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 2015 three-month period in our UGI International European LPG territories were warmer than normal but colder than in the 2014 three-month period. Total retail gallons sold during the 2015 three-month period were higher principally reflecting the effects of the colder 2015 three-month period weather on heating-related sales. During the 2015 three-month period, average wholesale commodity prices for both propane and butane in northwest Europe were approximately 40% lower than in the prior-year period.

UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during the reporting periods. The functional currency of a significant portion of our UGI International results is the euro. During the 2015 three-month period and the 2014 three-month period, the average un-weighted euro-to-dollar translation rate was approximately $1.13 and $1.37, respectively. The difference in euro-to-U.S. dollar translation rates and, to a lesser extent, the difference in the British pound sterling-to-U.S. dollar translation rates, reduced UGI International net income but the decrease was substantially offset by higher gains from foreign currency exchange contracts during the 2015 three-month period.

UGI International revenues decreased $169.1 million during the 2015 three-month period principally reflecting the combined impact on revenues of the significantly weaker euro and the British pound sterling ($100.9 million), and the effects of lower average LPG selling prices at each of our European LPG businesses as the result of the previously mentioned significant decline in commodity LPG prices. These decreases in revenues were partially offset by the higher retail LPG volumes sold and higher natural gas revenues on higher volumes sold at Antargaz. UGI International cost of sales decreased $165.8 million during the 2015 three-month period principally reflecting the effects of the significantly weaker euro and the British pound sterling and the lower average LPG wholesale prices partially offset by the effects of the greater retail LPG and natural gas volumes sold.

Total UGI International margin decreased $3.3 million during the 2015 three-month period principally reflecting the effects of the significantly weaker euro and the British pound sterling. The effects of the weaker currencies were partially offset by an increase in local currency total retail LPG and natural gas margins at Antargaz; higher local currency LPG total margin at AvantiGas; and gains on foreign currency exchange contracts ($6.5 million) in the 2015 three-month period compared to net losses from foreign currency exchange contracts in the prior-year period ($1.5 million). The higher local currency LPG and natural gas marketing total margin at Antargaz, and the higher LPG total margin at AvantiGas, reflects in large part the effects of the colder 2015 three-month period weather on volumes sold and higher local currency LPG unit margins. These increases in total margin were partially offset by lower local currency total margin at Flaga principally reflecting lower average local currency retail unit margins.

UGI International operating income and income before income taxes during the 2015 three-month period increased slightly from the prior-year period. These increases reflect the previously mentioned slightly lower total margin ($3.3 million) more than offset by lower operating and administrative expenses. Local currency operating expenses were slightly higher than the prior year reflecting, in large part, the increase in activity resulting from the colder weather. UGI International operating and administrative expenses in the 2015 three-month period also include approximately $8.0 million of incremental expenses associated with the previously announced proposed acquisition of Total’s retail LPG distribution business in France by UGI’s indirect wholly owned French subsidiary, UGI France (formerly UGI Bordeaux Holding). These increases in local currency operating and administrative

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expenses were more than offset by the currency translation effects of the weaker euro and British pound sterling on U.S. dollar operating and administrative expenses. The $2.5 million increase in UGI International income before income taxes reflects the slightly higher operating income ($0.9 million) and lower U.S. dollar-denominated interest expense principally reflecting the effects of the weaker euro on interest expense at Antargaz and Flaga.

Gas Utility

For the three months ended March 31,	2015			2014			Increase (Decrease)
(Dollars in millions)
Revenues	$	468.0		$	480.1		$	(12.1	)	(2.5	)%
Total margin (a)	$	209.8		$	201.3		$	8.5		4.2	%
Operating and administrative expenses	$	57.1		$	52.4		$	4.7		9.0	%
Operating income	$	139.3		$	134.5		$	4.8		3.6	%
Income before income taxes	$	129.2		$	126.1		$	3.1		2.5	%
System throughput—billions of cubic feet (“bcf”) —
Core market	44.3			41.8			2.5			6.0	%
Total	81.0			78.5			2.5			3.2	%
Degree days—% colder than normal (b)	22.1		%	19.3		%	—			—

(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 during the 2015 three-month period based upon heating degree days were 22.1% colder than normal and 2.3% colder than the prior-year three-month period. Total distribution system throughput increased 2.5 bcf (3.2%) principally reflecting higher core market volumes due to an increase in heating degree days and 1.7% year-over-year growth in the number of core market customers. Gas Utility’s core market customers comprise firm- residential, commercial and industrial (“retail core-market”) customers who purchase their gas from Gas Utility and, to a much lesser extent, residential and small commercial customers who purchase their gas from alternate suppliers.

Gas Utility revenues decreased $12.1 million during the 2015 three-month period principally reflecting lower revenues from off-system sales ($25.9 million) partially offset by higher revenues from core market customers ($16.3 million). The increase in core market revenues principally reflects the effects of the higher core market throughput offset by slightly lower average purchased gas cost (“PGC”) rates during the 2015 three-month period. Increases or decreases in retail core-market revenues and cost of sales principally result from changes in retail core-market volumes, distribution rates and PGC gas rates. Under the PGC recovery mechanism, Gas Utility records the cost of gas associated with sales to retail core-market customers at amounts included in PGC rates. The difference between actual gas costs and the amounts included in rates is deferred on the balance sheet as a regulatory asset or liability and represents amounts to be collected from, or refunded to, customers in a future period. As a result of this PGC recovery mechanism, increases or decreases in the cost of gas associated with retail core-market customers have no direct effect on retail core-market margin. Gas Utility’s cost of sales was $258.2 million in the 2015 three-month period compared with $278.8 million in the 2014 three-month period principally reflecting the effects of the lower off-system sales ($25.9 million) and lower average PGC rates ($4.4 million) partially offset by higher core-market volumes sold ($11.5 million).

Gas Utility 2015 three-month period total margin increased $8.5 million principally reflecting higher core market total margin ($9.1 million). The higher core market total margin reflects the effects of the previously mentioned colder weather on heating related sales and continued customer growth.

Gas Utility operating income and income before income taxes during the 2015 three-month period increased $4.8 million and $3.1 million, respectively, over the 2014 three-month period. The increase in Gas Utility operating income principally reflects the $8.5 million increase in total margin and increased other operating income, offset by higher operating and administrative expenses and slightly higher depreciation expense. Operating and administrative expenses were modestly higher than the prior-year period principally reflecting, among other things, higher 2015 three-month period distribution system maintenance ($1.6 million) and employee benefit and information technology expenses. Gas Utility other operating income increased due primarily to a reduction in out-of-state environmental remediation reserves. The increase in Gas Utility income before income taxes reflects the higher operating income partially offset by higher interest expense.

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Midstream & Marketing

For the three months ended March 31,	2015		2014		Decrease
(Dollars in millions)
Revenues (a)	$	430.5	$	605.6	$	(175.1	)	(28.9	)%
Total margin (b)	$	128.3	$	146.7	$	(18.4	)	(12.5	)%
Operating and administrative expenses	$	19.4	$	19.6	$	(0.2	)	(1.0	)%
Operating income	$	101.9	$	121.4	$	(19.5	)	(16.1	)%
Income before income taxes	$	101.4	$	120.4	$	(19.0	)	(15.8	)%

(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 (losses) gains from changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments, and pre-tax (losses) gains on certain settled commodity derivative instruments not associated with current period transactions, of $0.5 million and $(13.2) million during the 2015 three-month period and the 2014 three-month period, respectively.

Midstream & Marketing 2015 three-month period total revenues were $175.1 million lower than the 2014 three-month period principally reflecting lower natural gas ($142.4 million), retail power ($19.0 million) and peaking ($13.7 million) revenues. The decrease in natural gas revenues reflects lower wholesale and retail natural gas prices during the 2015 three-month period. The lower retail power revenues principally reflect the effects of lower volumes sold and lower average retail selling prices for electricity while the decline in peaking revenues reflects lower peaking activity in the 2015 three-month period compared with the prior-year period which experienced extreme winter temperature volatility. Midstream & Marketing cost of sales decreased to $302.2 million in the 2015 three-month period compared to $458.9 million in the 2014 three-month period principally reflecting lower natural gas cost of sales ($129.3 million) on lower natural gas prices and lower cost of sales associated with the decline in retail power sales in the 2015 three-month period ($23.4 million).

Midstream & Marketing total margin decreased $18.4 million in the 2015 three-month period principally reflecting lower natural gas marketing total margin ($13.2 million) and a decline in peaking and capacity management total margin ($10.3 million). These declines were partially offset principally by higher total margin from retail power total margin ($4.4 million). The decline in natural gas marketing total margin principally reflects the effects of lower average unit margins due in large part to the timing of natural gas basis margin associated with fixed-basis customers. The lower peaking and capacity management margin in the 2015 three-month period principally reflects lower average natural gas prices, and lower average year-over-year prices for pipeline capacity as the prior-year period experienced higher locational basis differences due to greater volatility in capacity values between Marcellus and non-Marcellus delivery points. Electric Generation total margin was slightly lower than the prior-year period, on comparable volumes generated, due primarily to lower capacity revenue.

Midstream & Marketing operating income and income before income taxes during the 2015 three-month period decreased $19.5 million and $19.0 million, respectively, principally reflecting the previously mentioned decrease in total margin ($18.4 million). Operating and administrative expenses were about equal to the prior year as slightly higher compensation and benefits expenses were offset by lower business development and uncollectible accounts expenses and lower taxes other than income taxes. Depreciation expense was slightly greater in the 2015 three-month period principally reflecting incremental depreciation expense associated with Electric Generation assets.

Interest Expense and Income Taxes

Our consolidated interest expense during the 2015 three-month period was $58.2 million, slightly lower than the $59.5 million of interest expense recorded during the 2014 three-month period. The lower interest expense reflects in large part the effects of the weaker euro and slightly lower long-term debt outstanding on UGI International interest expense partially offset by higher interest expense on long-term debt at UGI Utilities. Our effective income tax rate (excluding the effects on such rate of pretax income associated with noncontrolling interests not subject to federal income taxes) in the 2015 three-month period was comparable with the effective income tax rate in the 2014 three-month period.

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UGI CORPORATION AND SUBSIDIARIES

2015 six-month period compared to the 2014 six-month period

Net Income Attributable to UGI Corporation by Business Unit

For the six months ended March 31,	2015					2014					Variance - Favorable (Unfavorable)
(Dollars in millions)	Amount			% of Total		Amount			% of Total		Amount			% Change
AmeriGas Propane	$	64.4		23.0	%	$	68.2		20.3	%	$	(3.8	)	(5.6	)%
UGI International (a)	69.7			24.8	%	66.2			19.7	%	3.5			5.3	%
Gas Utility	114.9			40.9	%	117.8			35.0	%	(2.9		)	(2.5	)%
Midstream & Marketing	86.6			30.9	%	93.8			27.9	%	(7.2		)	(7.7	)%
Corporate & Other (b)	(55.0		)	(19.6	)%	(9.6		)	(2.9	)%	(45.4		)	N.M.
Net income attributable to UGI Corporation	$	280.6		100.0	%	$	336.4		100.0	%	$	(55.8	)	(16.6	)%

(a) Six months ended March 31, 2014 includes income tax expense of $5.7 million to reflect the retroactive effects of a change in tax laws in France.

(b) Includes net after-tax (losses) on commodity derivative instruments not associated with current-period transactions of $(51.1) million and $(3.5) million for the six months ended March 31, 2015 and 2014, respectively.

N.M. — Variance is not meaningful.

AmeriGas Propane

For the six months ended March 31,	2015			2014			Decrease
(Dollars in millions)
Revenues	$	1,989.1		$	2,539.5		$	(550.4	)	(21.7	)%
Total margin (a)	$	1,021.5		1,071.3			$	(49.8	)	(4.6	)%
Operating and administrative expenses	$	504.8		$	519.0		$	(14.2	)	(2.7	)%
Partnership Adjusted EBITDA (b)	$	530.6		$	561.5		$	(30.9	)	(5.5	)%
Operating income (b)	$	436.6		$	464.5		$	(27.9	)	(6.0	)%
Retail gallons sold (millions)	788.2			849.0			(60.8		)	(7.2	)%
Degree days—% (warmer) colder than normal (c)	(2.5		)%	6.2		%	—			—

(a) Total margin represents total revenues less total cost of sales. Total margin for the six months ended March 31, 2015 excludes net pre-tax losses of $63.5 million on AmeriGas Propane commodity derivative instruments not associated with current-period transactions.

(b) Partnership Adjusted EBITDA 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 GAAP. Management uses Partnership Adjusted EBITDA as the primary measure of segment profitability for the AmeriGas Propane segment (see Note 14 to condensed consolidated financial statements).

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

AmeriGas Propane’s retail gallons sold during the 2015 six-month period decreased 7.2% compared with the prior-year period. The decline in retail gallons sold in the 2015 six-month period principally reflects average temperatures based upon heating degree days that were 2.5% warmer than normal and 8.2% warmer than the prior-year period.

Retail propane revenues decreased $471.4 million during the 2015 six-month period reflecting lower average retail selling prices ($307.9 million), principally the result of the lower propane product costs, and the effects of lower retail volumes sold ($163.5 million). Wholesale propane revenues decreased $79.5 million during the 2015 six-month period reflecting the effects of lower wholesale volumes sold ($62.4 million) and lower wholesale selling prices ($17.1 million). Average daily wholesale propane commodity prices during the 2015 six-month period at Mont Belvieu, Texas, one of the major supply points in the U.S., were approximately 48% lower than such prices during the 2014 six-month period. Revenues from fee income and other ancillary sales

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UGI CORPORATION AND SUBSIDIARIES

and services in the 2015 six-month period were about equal to such revenues in the prior-year period. Total cost of sales during the 2015 six-month period decreased $500.6 million principally reflecting the effects of the significantly lower average propane product costs ($348.0 million) and the effects of the lower retail and wholesale volumes sold ($154.9 million) on propane cost of sales.

Total margin decreased $49.8 million in the 2015 six-month period principally reflecting lower retail propane total margin ($44.8 million) and, to a much lesser extent, lower margin from wholesale sales and ancillary sales and services. The decrease in retail propane total margin largely reflects the previously mentioned decline in retail gallons sold partially offset by slightly higher average propane retail unit margin.

Partnership Adjusted EBITDA in the 2015 six-month period decreased $30.9 million principally reflecting the lower total margin ($49.8 million) offset in part by lower operating and administrative expenses ($14.2 million) and higher other operating income resulting, in large part, from sales of excess assets. The decrease in operating and administrative expenses reflects, among other things, lower uncollectible accounts expenses ($8.7 million), reflecting lower propane prices, and lower vehicle expenses ($9.9 million), principally reflecting lower vehicle fuel expenses. Operating income decreased $27.9 million in the 2015 six-month period principally reflecting the lower Partnership Adjusted EBITDA ($30.9 million) partially offset by lower depreciation expense.

UGI International

For the six months ended March 31,	2015			2014			Increase (Decrease)
(Dollars in millions)
Revenues	$	1,082.6		$	1,407.8		$	(325.2	)	(23.1	)%
Total margin (a)	$	377.1		$	404.2		$	(27.1	)	(6.7	)%
Operating and administrative expenses	$	226.1		$	247.2		$	(21.1	)	(8.5	)%
Operating income	$	118.2		$	120.7		$	(2.5	)	(2.1	)%
Income before income taxes	$	104.7		$	105.5		$	(0.8	)	(0.8	)%
Retail gallons sold (millions) (b)	370.2			369.2			1.0			0.3	%
Antargaz degree days—% (warmer) than normal (c)	(9.2		)%	(12.4		)%	—			—
Flaga degree days—% (warmer) than normal (c)	(13.8		)%	(15.8		)%	—			—

(a) Total margin represents total revenues less total cost of sales. Total margin for the six months ended March 31, 2015 excludes net pre-tax losses of $19.1 million on UGI International’s commodity derivative instruments not associated with current-period transactions.

(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 2015 six-month period in our UGI International European LPG territories were significantly warmer than normal but slightly colder than in the 2014 six-month period. Total retail gallons sold during the 2015 six-month period were approximately equal to the prior-year six-month period. During the 2015 six-month period, average wholesale commodity prices for propane and butane in northwest Europe were each approximately 40% lower than in the prior-year period.

UGI International base-currency results are translated into U.S. dollars based upon exchange rates experienced during the reporting periods. The functional currency of a significant portion of our UGI International results is the euro. During the 2015 six-month period and the 2014 six-month period, the average un-weighted euro-to-U.S. dollar translation rate was approximately $1.19 and $1.36, respectively. The difference in euro-to-U.S. dollar translation rates and, to a lesser extent, the difference in British pound sterling-to-U.S. dollar translation rates, reduced UGI International net income but the decrease was substantially offset by higher gains from foreign currency exchange contracts during the 2015 six-month period.

UGI International revenues decreased $325.2 million during the 2015 six-month period principally reflecting the combined impact on revenues of the significantly weaker euro and the British pound sterling ($148.8 million) and to a lesser extent the effects of lower average LPG selling prices at each of our European LPG businesses, principally the result of the previously mentioned significant decline in commodity LPG prices. These decreases in revenues were partially offset by higher natural gas revenues on higher natural gas volumes at Antargaz. UGI International cost of sales decreased $298.1 million during the 2015 six-month period principally reflecting the effects of the significantly weaker euro and the British pound sterling and, to a lesser extent, the effects of the lower average LPG wholesale prices partially offset by the higher natural gas volumes sold.

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UGI CORPORATION AND SUBSIDIARIES

Total UGI International margin decreased $27.1 million during the 2015 six-month period principally reflecting the effects of the significantly weaker euro and the British pound sterling on local currency total margin partially offset by (1) higher local currency retail LPG total margin at Antargaz and AvantiGas principally resulting from higher retail LPG unit margins; (2) higher local currency natural gas marketing total margin at Antargaz; and (3) greater income from foreign currency exchange contracts ($12.7 million). The increases in local currency total margin at Antargaz and AvantiGas were partially offset by lower total LPG margin at Flaga reflecting lower retail unit margins.

UGI International operating income and income before income taxes during the 2015 six-month period decreased slightly from the prior-year period. The decreases reflect the previously mentioned lower total margin ($27.1 million) substantially offset by lower U.S. dollar-denominated operating and administrative expenses. Local currency operating and administrative expenses at our UGI International operating units were approximately equal to the prior-year period. However, UGI International operating and administrative expenses in the 2015 six-month period also include approximately $11.0 million of incremental expenses associated with the proposed acquisition of Total’s retail LPG distribution business in France by UGI’s indirect wholly owned French subsidiary, UGI France (formerly UGI Bordeaux Holding). Notwithstanding the higher overall local currency operating and administrative expenses, UGI International U.S. dollar-denominated operating and administrative expenses were lower reflecting the currency translation effects of the weaker euro and British pound sterling. The $0.8 million decrease in UGI International income before income taxes reflects the slightly lower operating income ($2.5 million) partially offset by lower U.S. dollar-denominated interest expense principally reflecting the effects of the weaker euro on interest expense at Antargaz and Flaga.

Gas Utility

For the six months ended March 31,	2015			2014			Increase (Decrease)
(Dollars in millions)
Revenues	$	728.5		$	751.7		$	(23.2	)	(3.1	)%
Total margin (a)	$	343.1		$	337.4		$	5.7		1.7	%
Operating and administrative expenses	$	102.1		$	91.0		$	11.1		12.2	%
Operating income	$	211.1		$	216.6		$	(5.5	)	(2.5	)%
Income before income taxes	$	190.9		199.8			$	(8.9	)	(4.5	)%
System throughput—bcf —
Core market	67.5			65.9			1.6			2.4	%
Total	137.8			135.3			2.5			1.8	%
Degree days—% colder than normal (b)	11.2		%	12.5		%	—			—

(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 Gas Utility’s service territory in the 2015 six-month period based upon heating degree days were 11.2% colder than normal and 1.1% warmer than the 2014 six-month period. Total distribution system throughput increased 2.5 bcf (1.8%), notwithstanding the slightly warmer weather, principally reflecting 1.7% year-over-year growth in the number of core market customers.

Gas Utility revenues decreased $23.2 million during the 2015 six-month period principally reflecting lower revenues from off-system sales ($28.8 million) partially offset by higher revenues from core market customers ($8.2 million). The increase in core market revenues principally reflects the effects of the higher core market throughput offset by slightly lower average PGC rates during the 2015 six-month period. Gas Utility’s cost of sales was $385.4 million in the 2015 six-month period compared with $414.3 million in the 2014 six-month period principally reflecting the effects of the lower off-system sales ($28.8 million).

Gas Utility 2015 six-month period total margin increased $5.7 million principally reflecting higher core market total margin ($6.2 million). The higher core market total margin reflects the effects of the previously mentioned year-over-year customer growth.

Gas Utility operating income and income before income taxes during the 2015 six-month period decreased $5.5 million and $8.9 million, respectively. The decrease in Gas Utility operating income principally reflects an $11.1 million increase in operating and administrative expenses and slightly higher depreciation expenses partially offset by the $5.7 million increase in total margin and, to a much lesser extent, slightly higher other operating income. Operating and administrative expenses were higher than the prior year principally reflecting, among other things, higher 2015 six-month period distribution system maintenance ($4.3 million), and

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employee benefit and information technology expenses. The decrease in Gas Utility income before income taxes reflects the lower operating income ($5.5 million) and slightly higher interest expense.

Midstream & Marketing

For the six months ended March 31,	2015		2014		Increase (Decrease)
(Dollars in millions)
Revenues (a)	$	739.9	$	894.6	$	(154.7	)	(17.3	)%
Total margin (b)	$	199.4	$	202.5	$	(3.1	)	(1.5	)%
Operating and administrative expenses	$	38.7	$	33.8	$	4.9		14.5	%
Operating income	$	147.4	$	157.6	$	(10.2	)	(6.5	)%
Income before income taxes	$	146.3	$	155.6	$	(9.3	)	(6.0	)%

(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 net pre-tax losses from changes in the fair values of Midstream & Marketing’s unsettled commodity derivative instruments, and net pre-tax losses on certain settled commodity derivative instruments not associated with current period transactions, of $45.0 million and $6.0 million during the 2015 six-month period and the 2014 six-month period, respectively.

Midstream & Marketing 2015 six-month period total revenues were $154.7 million lower than the 2014 six-month period principally reflecting lower natural gas ($121.7 million), retail power ($28.7 million) and peaking ($13.3 million) revenues partially offset by higher capacity management total revenues ($7.3 million). The decrease in natural gas revenues principally reflects lower wholesale and retail natural gas prices during the 2015 six-month period. The lower 2015 six-month period retail power revenues principally reflect lower sales volumes and, to a lesser extent, lower average prices. The greater capacity management revenues principally reflect the full-period effects of higher average prices for pipeline capacity. Such higher prices for pipeline capacity began primarily during the second quarter of Fiscal 2014 during which time the Company experienced significantly higher locational basis differences due to greater volatility in capacity values between Marcellus and non-Marcellus delivery points. These higher locational basis differences continued during the 2015 six-month period, although at a lower level than was experienced during the more volatile second quarter of Fiscal 2014. Midstream & Marketing cost of sales decreased to $540.5 million in the 2015 six-month period compared to $692.1 million in the 2014 six-month period principally reflecting lower natural gas ($108.3 million), retail power ($34.6 million) and peaking ($9.0 million) cost of sales.

Midstream & Marketing total margin decreased $3.1 million in the 2015 six-month period principally reflecting lower natural gas marketing total margin ($13.4 million) and a decline in peaking total margin ($4.3 million) and Electric Generation total margin($2.2 million). These declines were partially offset principally by higher total margin from capacity management ($7.3 million), higher retail power total margin ($5.8 million), and higher natural gas gathering and storage total margin ($4.7 million). The decline in natural gas marketing total margin principally reflects the effects of lower average unit margins due in large part to the timing of natural gas basis margin associated with fixed-basis customers. The lower peaking total margin in the 2015 six-month period principally reflects lower natural gas prices while the higher capacity management total margin principally reflects higher year-over-year prices for pipeline capacity. Electric Generation total margin declined during the 2015 six-month period principally the result of lower volumes generated due to scheduled generation plant outages earlier in the 2015 six-month period.

Midstream & Marketing operating income and income before income taxes during the 2015 six-month period decreased $10.2 million and $9.3 million, respectively, principally reflecting the previously mentioned decrease in total margin ($3.1 million) and higher operating and administrative costs. The higher operating and administrative expenses include, among other things, increased operating expenses associated with planned outages at the Hunlock Station and Conemaugh generating units earlier in the period and higher operating expenses associated with our expanded natural gas gathering assets including the impact of the Auburn pipeline extension. Depreciation expense was greater in the 2015 six-month period reflecting incremental depreciation associated with storage and natural gas gathering assets.

Interest Expense and Income Taxes

Our consolidated interest expense during the 2015 six-month period was $117.2 million, slightly lower than the $118.8 million of interest expense recorded during the 2014 six-month period. The decrease in interest expense principally reflects slightly lower long-term debt and the effects of the weaker euro on UGI International interest expense and lower interest expense on short-term borrowings at AmeriGas Propane and Midstream & Marketing partially offset by higher long-term debt interest at UGI Utilities. Our effective income tax rate (excluding the effects on such rate of pretax income associated with noncontrolling interests not

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UGI CORPORATION AND SUBSIDIARIES

subject to federal income taxes) in the 2015 six-month period was slightly lower than such rate calculated in the prior-year six-month period, which included $5.7 million of income taxes associated with the change in tax laws in France that was retroactive to Fiscal 2013.

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.

The primary sources of UGI’s cash and cash equivalents are the dividends and other cash payments made to UGI or its corporate subsidiaries by its principal business units. Our cash and cash equivalents, excluding cash in commodity futures brokerage accounts that is restricted from withdrawal, totaled $445.5 million at March 31, 2015, compared with $419.5 million at September 30, 2014. Excluding cash and cash equivalents that reside at UGI’s operating subsidiaries, at March 31, 2015 and September 30, 2014, UGI had $211.7 million and $245.9 million of cash and cash equivalents, respectively. Such cash is available to pay dividends on UGI Common Stock and for investment purposes.

Long-term Debt and Short-term Debt

The Company’s debt outstanding at March 31, 2015, totaled $3,518.6 million (including current maturities of long-term debt of $470.5 million and short-term borrowings of $89.9 million) compared to debt outstanding at September 30, 2014, of $3,721.6 million (including current maturities of long-term debt of $77.2 million and short-term borrowings of $210.8 million). Total debt outstanding at March 31, 2015, consists of (1) $2,345.1 million of Partnership debt; (2) $489.1 million of UGI International debt; (3) $672.5 million of UGI Utilities debt; (4) $0.9 million of Energy Services debt; and (5) $11.0 million of other debt.

AmeriGas Partners. AmeriGas Partners’ total debt at March 31, 2015, includes $2,250.8 million of AmeriGas Partners’ Senior Notes, $55.0 million of AmeriGas OLP short-term borrowings and $39.3 million of other long-term debt.

UGI International. UGI International’s total debt at March 31, 2015, includes $367.1 million (€342 million) outstanding under Antargaz’ 2011 Senior Facilities Agreement, $52 million under Flaga’s U.S. dollar-denominated term loan and a combined $63.4 million (€59.1 million) outstanding under Flaga’s euro-denominated term loans. Total UGI International debt outstanding at March 31, 2015, also includes $4.3 million (€4.0 million) of Flaga short-term borrowings and $2.3 million (€2.1 million) of other long-term debt.

UGI Utilities. UGI Utilities’ total debt at March 31, 2015, includes $450.0 million of Senior Notes, $192.0 million of Medium-Term Notes and $30.5 million of short-term borrowings.

Short-term Debt

Additional information related to the Company’s credit agreements can be found in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in the Company’s 2014 Annual Report. The discussion below provides updates to this information for the six months ended March 31, 2015.

UGI Utilities. On March 27, 2015, UGI Utilities entered into an unsecured revolving credit agreement (the “UGI Utilities 2015 Credit Agreement”) with a group of banks providing for borrowings up to $300 million (including a $100 million sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2015 Credit Agreement, UGI Utilities terminated its then-existing $300 million revolving credit agreement dated as of May 25, 2011. Under the UGI Utilities 2015 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2015 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.0. The UGI Utilities 2015 Credit Agreement is currently scheduled to expire in March 2016, but may be extended by UGI Utilities to March 2020 if on or before March 25, 2016, the Company satisfies certain requirements relating to approval by the Pennsylvania Public Utility Commission. The Company intends to seek such regulatory approval.

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UGI CORPORATION AND SUBSIDIARIES

UGI International. 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 of which are scheduled to expire in September 2015. Flaga expects to extend these facilities prior to their expiration in September 2015.

In anticipation of its pending acquisition of Totalgaz (see “Pending Acquisition of Totalgaz” below), on April 30, 2015, UGI France (formerly UGI Bordeaux Holding), an indirect wholly owned subsidiary of UGI, entered into the 2015 Senior Facilities Agreement which permits UGI France to borrow up to €600 million, via a variable-rate term loan, and €60 million, via a revolving credit facility. UGI France expects to enter into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan. The term loan proceeds from the 2015 Senior Securities Facility will be used to (1) fund a portion of the acquisition of Totalgaz, including related fees and expenses; (2) prepay €342.0 million principal amount, plus accrued interest, outstanding under the Antargaz 2011 Senior Facilities Agreement due March 2016; (3) settle Antargaz’ existing pay-fixed, receive-variable interest rate swaps associated with the 2011 Senior Facilities Agreement; and (4) for general corporate purposes. As of March 31, 2015, the fair value of the interest rate swaps was a loss of $10.3 million. UGI France does not intend to draw on either the term loan or the revolving credit facility until the closing date of the Totalgaz acquisition, which is required to occur no later than June 30, 2015, pursuant to the terms of the 2015 Senior Facilities Agreement. For further information on the 2015 Senior Facilities Agreement, see Note 8 to the condensed consolidated financial statements. Effective April 30, 2015, UGI International, Inc., an indirect wholly owned subsidiary of UGI, terminated its €300 million Senior Secured Bridge Facility Agreement, as amended. The Senior Secured Bridge Facility Agreement had previously been entered into in order to provide an additional source of financing, if necessary, to fund a portion of the acquisition of Totalgaz.

Information about the Company’s principal credit agreements (excluding the Energy Services Receivables Facility discussed below) as of March 31, 2015 and 2014, is presented in the table below.

(Millions of dollars or euros)	Total Capacity	Borrowings Outstanding	Letters of Credit and Guarantees Outstanding	Available Capacity
As of March 31, 2015
AmeriGas Credit Agreement	$525.0	$55.0	$64.7	$405.3
Antargaz Credit Facility	€40.0	€0.0	€0.0	€40.0
Flaga Credit Agreements	€58.0	€3.5	€20.8	€33.7
UGI Utilities Credit Agreement	$300.0	$30.5	$2.0	$267.5
Energy Services Credit Agreement	$240.0	$0.0	$0.0	$240.0
As of March 31, 2014
AmeriGas Credit Agreement	$525.0	$198.0	$64.7	$262.3
Antargaz Credit Facility	€40.0	€0.0	€0.0	€40.0
Flaga Credit Agreements	€58.0	€1.2	€32.3	€24.5
UGI Utilities Credit Agreement	$300.0	$6.5	$2.0	$291.5
Energy Services Credit Agreement	$240.0	$41.0	$0.0	$199.0

The average daily and peak short-term borrowings under the Company’s principal credit agreements during the six months ended March 31, 2015 and 2014 are as follows:

	For the six months ended March 31, 2015		For the six months ended March 31, 2014
(Millions of dollars or euros)	Average	Peak	Average	Peak
AmeriGas Credit Agreement	$179.5	$349.0	$203.4	$320.0
Antargaz Credit Facility	N.A.	N.A.	N.A.	N.A.
Flaga Credit Agreements	€2.9	€3.5	€2.2	€3.6
UGI Utilities Credit Agreement	$108.9	$163.6	$45.6	$84.0
Energy Services Credit Agreement	$0.3	$7.0	$78.4	$114.0

Energy Services has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2015. The Receivables Facility provides Energy Services with the ability to borrow

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UGI CORPORATION AND SUBSIDIARIES

up to $150 million of eligible receivables during the period November through May and up to $75 million of eligible receivables during the period June through October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes. Energy Services intends to extend its Receivables Facility prior to its scheduled expiration.

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, 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. At March 31, 2015, the outstanding balance of ESFC trade receivables was $96.9 million and there were no amounts sold to the bank. At March 31, 2014, the outstanding balance of ESFC trade receivables was $124.1 million and there was $10.5 million that was sold to the bank. Amounts sold to the bank are reflected as short-term borrowings on the Condensed Consolidated Balance Sheets.

During the six months ended March 31, 2015 and 2014, Energy Services transferred trade receivables to ESFC totaling $692.0 million and $820.7 million, respectively. During the six months ended March 31, 2015 and 2014, ESFC sold an aggregate $216.5 million and $251.0 million, respectively, of undivided interests in its trade receivables to the bank. During the six months ended March 31, 2015 and 2014, peak sales of receivables were $67.5 million and $70.0 million, respectively, and average daily amounts sold were $24.7 million and $28.2 million, respectively.

Dividends and Distributions

On April 28, 2015, UGI’s Board of Directors approved an increase in the quarterly dividend rate on UGI Common Stock to $0.2275 per Common Share, or $0.91 on an annual basis. The new dividend rate reflects an approximately 4.6% increase from the previous quarterly rate of $0.2175. The new quarterly dividend rate is effective with the dividend payable on July 1, 2015, to shareholders of record on June 15, 2015.

On April 27, 2015, the General Partner’s Board of Directors approved an increase in the quarterly dividend rate on AmeriGas Partners Common Units to $0.92 per Common Unit, equal to an annual rate of $3.68 per Common Unit. The distribution reflects a 4.5% increase from the previous quarterly rate of $0.88. The new quarterly rate is effective with the distribution payable on May 18, 2015, to unitholders of record on May 11, 2015.

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 and services 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 $657.8 million in the 2015 six-month period compared to cash flow provided by operating activities of $483.0 million in the 2014 six-month period. The Company’s operating cash flow during the six months ended March 31, 2015, benefited from lower net operating working capital amounts as a result of significant declines in LPG and natural gas commodity costs. Cash flow from operating activities before changes in operating working capital was $780.6 million in the 2015 six-month period compared to $832.6 million in the prior-year six-month period. Cash used to fund changes in operating working capital totaled $122.8 million in the 2015 six-month period compared to $349.6 million in the prior-year six-month period. The significant decrease in net cash used to fund changes in working capital reflects, in large part, the impact of the previously mentioned significant decline in LPG and natural gas commodity costs.

Investing Activities.Cash flow used by investing activities was $265.8 million in the 2015 six-month period compared with $237.3 million in the prior-year period. Investing activity cash flow is principally affected by expenditures for property, plant and equipment; cash paid for acquisitions of businesses; changes in restricted cash balances; and proceeds from sales of assets. Cash payments for property, plant and equipment was $233.5 million in the 2015 six-month period compared to $224.4 million in the prior-year six-month period. The significant increase in restricted cash during the 2015 six-month period reflects the impact of the previously mentioned decline in energy commodity prices on margin requirements in our NYMEX brokerage accounts.

Financing Activities. Cash flow used by financing activities was $337.9 million in the 2015 six-month period compared with $145.4 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 short-term borrowings; dividends and distributions on UGI Common Stock and AmeriGas Partners Common Units; and issuances of UGI and AmeriGas Partners equity instruments. The increase in cash used by financing activities in the

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UGI CORPORATION AND SUBSIDIARIES

2015 six-month period principally reflects higher repayments of short-term borrowings at UGI Utilities and AmeriGas Propane due to the higher cash generated from operations.

The decrease in cash from changes in foreign currency exchange rates during the 2015 six-month period reflects the effects of the significantly weaker euro and British pound sterling on cash balances at our UGI International business units.

Pending Acquisition of Totalgaz

On November 11, 2014, UGI Corporation’s indirect wholly owned subsidiary, UGI Bordeaux Holding (now known as UGI France), entered into a Share Purchase Agreement with Total Marketing Services, a subsidiary of Total, to acquire all of the outstanding shares of Totalgaz, Total’s LPG distribution business in France, for a purchase price between €400 million and €450 million in cash, subject to working capital and other adjustments. Totalgaz distributed over 265 million retail gallons of LPG in 2013, serving residential, commercial, industrial and autogas customers. The transaction is subject to customary closing conditions, including regulatory approvals. The acquisition is expected to occur during the third quarter of Fiscal 2015. As previously mentioned, the Company expects to use a portion of the proceeds from the 2015 Senior Facilities Agreement entered into on April 30, 2015, as well as existing cash balances, to fund the pending acquisition of Totalgaz.

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. Our UGI International operations use 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 economically 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 March 31, 2015, the fair values of Gas Utility’s natural gas futures and option contracts were net losses of $3.4 million.

Electric Utility's DS tariffs contain clauses which permit recovery of all prudently incurred power costs, including the cost of financial instruments used to hedge electricity costs, through the application of DS rates. Because of this ratemaking mechanism, there is limited power cost risk, including the cost of FTRs and forward electricity purchase contracts, associated with our Electric Utility operations. At March 31, 2015, the fair values of Electric Utility’s electricity supply contracts were net losses of $1.2 million. At March 31, 2015, the fair values of Electric Utility’s FTRs 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, ICE and over-the-counter natural gas and electricity futures and natural gas basis swap contracts or enters into fixed-price supply arrangements. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to 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

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UGI CORPORATION AND SUBSIDIARIES

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 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 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.

Midstream & Marketing 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, Midstream & Marketing 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 Midstream & Marketing’s results.

The fair value of unsettled commodity price risk sensitive derivative instruments held at March 31, 2015 (excluding those Gas Utility and Electric Utility commodity derivative instruments that are refundable to, or recoverable from, customers) was a loss of $140.9 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 $48.4 million at March 31, 2015.

Interest Rate Risk

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

Our variable-rate debt at March 31, 2015, includes our short-term 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 March 31, 2015, combined borrowings outstanding under these variable-rate debt agreements, excluding Antargaz’ and Flaga’s effectively fixed-rate debt, totaled $89.9 million.

The fair value of unsettled interest rate risk sensitive derivative instruments held at March 31, 2015 (including pay-fixed, receive-variable interest rate swaps) was a loss of $12.5 million. A 50 basis point adverse change in the three-month euribor rate would result in a decrease in fair value of approximately $2.1 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 March 31, 2015, there were no unsettled net investment hedges outstanding. With respect to our net investments in our International Propane operations, a 10% decline in the value of the associated foreign currencies versus the U.S. dollar, excluding the effects of any net investment hedges, would reduce their aggregate net book value at March 31, 2015, by approximately $90.0 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 fair value of unsettled foreign currency exchange rate risk sensitive derivative instruments held at March 31, 2015, was a gain of $45.5 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 $23.1 million.

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UGI CORPORATION AND SUBSIDIARIES

Derivative Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative 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 March 31, 2015 and 2014, restricted cash in brokerage accounts totaled $56.7 million and $4.4 million, respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at March 31, 2015. 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 March 31, 2015, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

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

(b) Change in Internal Control over Financial Reporting

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

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PART II OTHER INFORMATION

ITEM 1A. RISK FACTORS

In addition to the 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, 2014, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Company. Other unknown or unpredictable factors could also have material adverse effects on future results.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth information with respect to the Company’s repurchases of its common stock during the quarter ended March 31, 2015.

Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share (or Unit)	(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs (1)	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
January 1, 2015 to January 31, 2015	—	$0.00	—	13.8 million
February 1, 2015 to February 28, 2015	410,000	$34.63	410,000	13.4 million
March 1, 2015 to March 31, 2015	90,000	$33.91	90,000	13.3 million
Total	500,000		500,000

(1) Shares of UGI Corporation Common Stock are repurchased through a share repurchase program announced by the Company on January 30, 2014. The Board of Directors authorized the repurchase of up to 15 million shares of UGI Corporation Common Stock over a four-year period.

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 last date of the period for which it was filed, and the exhibit number in such filing):

Incorporation by Reference

Exhibit No.	Exhibit	Registrant	Filing	Exhibit
10.1	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Employees, dated January 1, 2015.
10.2	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Stock Unit Grant Letter for Non Employee Directors, dated January 8, 2015.
10.3	Form of UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 8, 2015.
10.4	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2015.
10.5	Letter of Amendment dated as of January 30, 2015 to Senior Secured Bridge Facility Agreement dated as of October 17, 2014 by and between UGI International Enterprises, Inc., as borrower, Credit Suisse AG, London Branch, Bank of America Merrill Lynch International Limited and Natixis, New York Branch, as mandated lead arrangers, and Credit Suisse AG, Cayman Island Branch, as agent and security agent.	UGI	Form 8-K (1/30/2015)	10.1

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UGI CORPORATION AND SUBSIDIARIES

10.6	Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Performance Unit Grant Letter for Employees dated January 21, 2015.	AmeriGas Partners, L.P.	Form 10-Q (3/31/2015)	10.1
10.7	Form of AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P., Phantom Unit Grant Letter for Non Employee Directors, dated January 8, 2015.	AmeriGas Partners, L.P.	Form 10-Q (3/31/2015)	10.2
10.8	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for AmeriGas Employees, dated January 21, 2015.	AmeriGas Partners, L.P.	Form 10-Q (3/31/2015)	10.3
10.9	Description of oral compensation arrangement between AmeriGas Propane, Inc. and Mr. Anthony Rosback.	AmeriGas Partners, L.P.	Form 8-K (3/2/2015)	10.1
10.10	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Utilities Employees, dated January 1, 2015.	Utilities	Form 10-Q (3/31/2015)	10.1
10.11	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Utilities Employees, dated January 1, 2015.	Utilities	Form 10-Q (3/31/2015)	10.2
10.12	Credit Agreement, dated as of March 27, 2015 among UGI Utilities, Inc., as borrower, PNC Bank, National Association, as administrative agent, Citizens Bank of Pennsylvania, as syndication agent, PNC Capital Markets LLC and Citizens Bank, N.A., as joint lead arrangers and joint bookrunners, and PNC Bank, National Association, Citizens Bank of Pennsylvania, Citibank, N.A., Credit Suisse AG, Cayman Islands Branch, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, The Bank of New York Mellon, Bank of America, N.A., and the other financial institutions from time to time parties thereto.	Utilities	Form 8-K (3/27/15)	10.1
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL.Instance
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

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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:	May 8, 2015	By:	/s/ Kirk R. Oliver
			Kirk R. Oliver
			Chief Financial Officer
Date:	May 8, 2015	By:	/s/ Davinder S. Athwal
			Davinder S. Athwal
			Vice President - Accounting and
			Financial Control and Chief Risk Officer

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EXHIBIT INDEX

10.1	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Performance Unit Grant Letter for UGI Employees, dated January 1, 2015.
10.2	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan, Stock Unit Grant Letter for Non Employee Directors, dated January 8, 2015.
10.3	Form of UGI Corporation 2004 Omnibus Equity Compensation Plan Nonqualified Stock Option Grant Letter for Non Employee Directors, dated January 8, 2015.
10.4	Form of UGI Corporation 2013 Omnibus Incentive Compensation Plan Nonqualified Stock Option Grant Letter for UGI Employees, dated January 1, 2015.
31.1	Certification by the Chief Executive Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification by the Chief Executive Officer and the Chief Financial Officer relating to the Registrant’s Report on Form 10-Q for the quarter ended March 31, 2015, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Labels Linkbase
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EX-10.1

EXHIBIT 10.1

UGI Employees

UGI CORPORATION
2013 OMNIBUS INCENTIVE COMPENSATION PLANPERFORMANCE UNIT GRANT LETTER

This PERFORMANCE UNIT GRANT, dated January 1, 2015 (the “Date of Grant”), is delivered by UGI Corporation (“UGI”) to you (the “Participant”).

RECITALS

The UGI Corporation 2013 Omnibus Incentive Compensation Plan (the “Plan”) provides for the grant of performance units (“Performance Units”) with respect to shares of common stock of UGI (“Shares”). The Compensation and Management Development Committee of the Board of Directors of UGI (the “Committee”) has decided to grant Performance Units to the Participant. The Participant’s portal in the Morgan Stanley website for Plan participants (the “Grant Summary”) sets forth the number of Performance Units granted to the Participant with respect to this grant.

NOW, THEREFORE, the parties to this Grant Letter, intending to be legally bound hereby, agree as follows:

1.Grant of Performance Units. Subject to the terms and conditions set forth in this Grant Letter and in the Plan, the Committee hereby grants to the Participant a target award of the number of Performance Units specified in the Grant Summary (the “Target Award”). The Performance Units are contingently awarded and will be earned and payable if and to the extent that the Performance Goals (defined below) and other conditions of the Grant Letter are met. The Performance Units are granted with Dividend Equivalents (as defined in Section 7).

2.Performance Goals.

(a)The Participant shall earn the right to payment of the Performance Units if the Performance Goals are met for the Performance Period, and if the Participant continues to be employed by, or provide service to, the Company (as defined in Section 7) through December 31, 2017. The Performance Period is the period beginning January 1, 2015 and ending December 31, 2017. The Total Shareholder Return (“TSR”) goals and other requirements of this Section 2 are referred to as the “Performance Goals.”

(b)The Target Award level of Performance Units and Dividend Equivalents will be payable if UGI’s TSR equals the median TSR of the comparison group designated by the Committee (the “Peer Group”) for the Performance Period. The Peer Group is the group of companies that comprises the Russell Midcap Utilities Index, excluding telecommunications companies, as of the beginning of the Performance Period, as set forth on the attached Exhibit A, and as described herein. If a company is added to the Russell Midcap Utilities Index during the Performance Period, that company is not included in the TSR calculation. A company that is included in the Russell Midcap Utilities Index at the beginning of the Performance Period will be

removed from the TSR calculation only if the company ceases to exist as a publicly traded company during the Performance Period (including by way of a merger or similar transaction in which the company is not the surviving company), consistent with the methodology described in subsection (c) below. Companies that are designated at the beginning of the Performance Period as telecommunications companies in the Russell Midcap Utilities Index shall be excluded from the TSR calculation. The actual amount of the award of Performance Units may be higher or lower than the Target Award, or it may be zero, based on UGI’s TSR percentile rank relative to the companies in the Peer Group, as follows:

UGI’s TSR RankPercentage of Target Award Earned(Percentile)

90th                        200%

75th                        162.5%

60th                        125%

50th                        100%

40th                         70%

25th                         25%

Less than 25th                     0%

The award percentage earned will be interpolated between each of the measuring points.

(c)TSR shall be calculated by UGI using the comparative returns methodology used by Bloomberg L.P. or its successor at the time of the calculation. The share price used for determining TSR at the beginning and the end of the Performance Period will be the average price for the calendar quarter preceding the beginning of the Performance Period (i.e., the calendar quarter ending on December 31, 2014) and the calendar quarter ending on the last day of the Performance Period (i.e., the calendar quarter ending on December 31, 2017), respectively. The TSR calculation gives effect to all dividends throughout the three-year Performance Period as if they had been reinvested.

(d)The Target Award is the amount designated for 100% (50th TSR rank) performance. The Participant can earn up to 200% of the Target Award if UGI’s TSR percentile rank exceeds the 50th TSR percentile rank, according to the foregoing schedule.

(e)At the end of the Performance Period, the Committee will determine whether and to what extent the Performance Goals have been met and the amount to be paid with respect to the Performance Units. Except as described in Sections 3 and 6 below, the Participant must be employed by, or providing service to, the Company on December 31, 2017 in order for the Participant to receive payment with respect to the Performance Units.

3.Termination of Employment or Service.

(a)Except as described below, if the Participant ceases to be employed by, or provide services to, the Company before December 31, 2017, the Performance Units and all Dividend Equivalents credited under this Grant Letter will be forfeited.

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(b)If the Participant terminates employment or service on account of Retirement (as defined in Section 7), Disability (as defined in Section 7) or death, the Participant will earn a pro-rata portion of the Participant’s outstanding Performance Units and Dividend Equivalents, if the Performance Goals and the requirements of this Grant Letter are met. The prorated portion will be determined as the amount that would otherwise be paid after the end of the Performance Period, based on achievement of the Performance Goals, multiplied by a fraction, the numerator of which is the number of calendar years during the Performance Period in which the Participant has been employed by, or provided service to, the Company and the denominator of which is three. For purposes of the proration calculation, the calendar year in which the Participant’s termination of employment or service on account of Retirement, Disability, or death occurs will be counted as a full year.

(c)In the event of termination of employment or service on account of Retirement, Disability or death, the prorated amount shall be paid after the end of the Performance Period, pursuant to Section 4 below, except as provided in Section 6.

4.Payment with Respect to Performance Units. If the Committee determines that the conditions to payment of the Performance Units have been met, the Company shall pay to the Participant (i) Shares equal to the number of Performance Units to be paid according to achievement of the Performance Goals, up to the Target Award, provided that the Company may withhold Shares to cover required tax withholding in an amount equal to the minimum statutory tax withholding requirement in respect of the Performance Units earned up to the Target Award, and (ii) cash in an amount equal to the Fair Market Value (as defined in the Plan) of the number of Shares equal to the Performance Units to be paid in excess of the Target Award, subject to applicable tax withholding. Payment shall be made between January 1, 2018 and March 15, 2018, except as provided in Section 6 below.

5.Dividend Equivalents with Respect to Performance Units.

(a)Dividend Equivalents shall accrue with respect to Performance Units and shall be payable subject to the same Performance Goals and terms as the Performance Units to which they relate. Dividend Equivalents shall be credited with respect to the Target Award of Performance Units from the Date of Grant until the payment date. If and to the extent that the underlying Performance Units are forfeited, all related Dividend Equivalents shall also be forfeited.

(b)While the Performance Units are outstanding, the Company will keep records of Dividend Equivalents in a bookkeeping account for the Participant. On each payment date for a dividend paid by UGI on its common stock, the Company shall credit to the Participant’s account an amount equal to the Dividend Equivalents associated with the Target Award of Performance Units held by the Participant on the record date for the dividend. No interest will be credited to any such account.

(c)The target amount of Dividend Equivalents (100% of the Dividend Equivalents credited to the Participant’s account) will be earned if UGI’s TSR rank is at the 50th TSR percentile rank for the Performance Period. The Participant can earn up to 200% of the target

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amount of Dividend Equivalents if UGI’s TSR percentile rank exceeds the 50th TSR rank, according to the schedule in Section 2 above. Except as described in Section 3(b) above, or Section 6, if the Participant’s employment or service with the Company terminates before December 31, 2017, all Dividend Equivalents will be forfeited.

(d)Dividend Equivalents will be paid in cash at the same time as the underlying Performance Units are paid, after the Committee determines that the conditions to payment have been met. Notwithstanding anything in this Grant Letter to the contrary, the Participant may not accrue Dividend Equivalents in excess of $1,000,000 during any calendar year under all grants under the Plan.

6.Change of Control.

(a)If a Change of Control (as defined in the Plan) occurs, the Performance Units and Dividend Equivalents shall not automatically become payable upon the Change of Control, but, instead, shall become payable as described in this Section 6. The Committee may take such other actions with respect to the Performance Units and Dividend Equivalents as it deems appropriate pursuant to the Plan.

(b)If a Change of Control occurs during the Performance Period, the Committee shall calculate a Change of Control Amount as follows:

(i)The Performance Period shall end as of the closing date of the Change of Control (the “Change of Control Date”) and the TSR ending date calculation for the Performance Period shall be based on the 90 calendar day period ending on the Change of Control Date.

(ii)The Committee shall calculate a “Change of Control Amount” equal to the greater of (i) the Target Award amount or (ii) the amount of Performance Units that would be payable based on the Company’s achievement of the Performance Goals as of the Change of Control Date, as determined by the Committee. The Change of Control Amount shall include related Dividend Equivalents and, if applicable, interest as described below.

(iii)The Committee shall determine whether the Change of Control Amount attributable to Performance Units shall be (A) converted to units with respect to shares or other equity interests of the acquiring company or its parent (“Successor Units”), in which case Dividend Equivalents shall continue to be credited on the Successor Units, or (B) valued based on the Fair Market Value of the Performance Units as of the Change of Control Date and credited to a bookkeeping account for the Participant, in which case interest shall be credited on the amount so determined at a market rate for the period between the Change of Control Date and the applicable payment date.  Notwithstanding the provisions of Section 4, all payments on and after a Change of Control shall be made in cash.  If alternative (A) above is used, the cash payment shall equal the Fair Market Value on the date of payment of the number of shares or other equity interests underlying

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the Successor Units, plus accrued Dividend Equivalents.  All payments shall be subject to applicable tax withholding. 

(c)If a Change of Control occurs during the Performance Period and the Participant continues in employment or service through December 31, 2017, the Change of Control Amount shall be paid in cash between January 1, 2018 and March 15, 2018.

(d)If a Change of Control occurs during the Performance Period, and the Participant has a Termination without Cause or a Good Reason Termination upon or within two years after the Change of Control Date and before December 31, 2017, the Change of Control Amount shall be paid in cash within 30 days after the Participant’s separation from service, subject to Section 13 below.

(e)If a Change of Control occurs during the Performance Period, and the Participant terminates employment or service on account of Retirement, Disability or death upon or after the Change of Control Date and before December 31, 2017, the Change of Control Amount shall be paid in cash within 30 days after the Participant’s separation from service, subject to Section 13 below; provided that, if required by section 409A, if the Participant’s Retirement, Disability or death occurs more than two years after the Change of Control Date, payment will be made between January 1, 2018 and March 15, 2018, and not upon the earlier separation from service.

(f)If a Participant’s employment or service terminates on account of Retirement, death or Disability before a Change of Control, and a Change of Control subsequently occurs before the end of the Performance Period, the prorated amount in Section 3(b) shall be calculated by multiplying the fraction described in Section 3(b) by the Change of Control Amount. The prorated Change of Control Amount shall be paid in cash within 30 days after the Change of Control Date, subject to Section 13 below.

7.Definitions. For purposes of this Grant Letter, the following terms will have the meanings set forth below:

(a)“Company” means UGI and its Subsidiaries (as defined in the Plan).

(b)“Disability” means a long-term disability as defined in the Company’s long-term disability plan applicable to the Participant.

(c)“Dividend Equivalent” means an amount determined by multiplying the number of shares of UGI common stock subject to the target award of Performance Units by the per-share cash dividend, or the per-share fair market value of any dividend in consideration other than cash, paid by UGI on its common stock.

(d)“Employed by, or provide service to, the Company” shall mean employment or service as an employee or director of the Company. The Participant shall not be considered to have a termination of employment or service under this Grant Letter until the Participant is no longer employed by, or performing services for, the Company.

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(e)“Good Reason Termination” shall mean a termination of employment or service initiated by the Participant upon or after a Change of Control upon one or more of the following events:

(i)a material diminution in the authority, duties or responsibilities held by the Participant immediately prior to the Change of Control;

(ii)a material diminution in the Participant’s base salary as in effect immediately prior to the Change of Control; or

(iii)a material change in the geographic location at which the Participant must perform services (which, for purposes of this Agreement, means the Participant is required to report, other than on a temporary basis (less than 12 months), to a location which is more than 50 miles from the Participant’s principal place of business immediately before the Change of Control, without the Participant’s express written consent).

Notwithstanding the foregoing, the Participant shall be considered to have a Good Reason Termination only if the Participant provides written notice to the Company, pursuant to Section 15, specifying in reasonable detail the events or conditions upon which the Participant is basing such Good Reason Termination and the Participant provides such notice within 90 days after the event that gives rise to the Good Reason Termination. Within 30 days after notice has been provided, the Company shall have the opportunity, but shall have no obligation, to cure such events or conditions that give rise to the Good Reason Termination. If the Company does not cure such events or conditions within the 30-day period, the Participant may terminate employment or service with the Company based on Good Reason Termination within 30 days after the expiration of the cure period.

Notwithstanding the foregoing, if the Participant has in effect a Change in Control Agreement with the Company or an Affiliate, the term “Good Reason Termination” shall have the meaning given that term in the Change in Control Agreement.

(f)“Performance Unit” means a hypothetical unit that represents the value of one share of UGI common stock.

(g)Retirement” means the Participant’s retirement under the Retirement Income Plan for Employees of UGI Utilities, Inc., if the Participant is covered by that Retirement Income Plan. “Retirement” for other Company employees means termination of employment or service after attaining (i) age 55 with ten or more years of service with the Company or (ii) age 65 with five or more years of service with the Company.

(h)“Termination without Cause” means termination of employment or service by the Company for the convenience of the Company for any reason other than (i) theft or misappropriation of funds or conduct that has an adverse effect on the reputation of the Company, (ii) conviction of a felony or a crime involving moral turpitude, (iii) material breach of the Company’s written code of conduct, or other material written employment policies,

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applicable to the Participant, (iv) breach of any written confidentiality, non-competition or non-solicitation covenant between the Participant and the Company, (v) gross misconduct in the performance of duties, or (vi) intentional refusal or failure to perform the material duties of the Participant’s position.

8.Withholding. All payments under this Grant Letter are subject to applicable tax withholding. The Participant shall be required to pay to the Company, or make other arrangements satisfactory to the Company to provide for the payment of, any federal (including FICA), state, local or other taxes that the Company is required to withhold with respect to the payments under this Grant Letter. The Company may withhold from cash distributions to cover required tax withholding, or may withhold Shares to cover required tax withholding in an amount equal to the minimum applicable tax withholding amount.

9.Grant Subject to Plan Provisions and Company Policies.

(a)This grant is made pursuant to the Plan, which is incorporated herein by reference, and in all respects shall be interpreted in accordance with the Plan. The grant and payment of Performance Units and Dividend Equivalents are subject to interpretations, regulations and determinations concerning the Plan established from time to time by the Committee in accordance with the provisions of the Plan, including, but not limited to, provisions pertaining to (i) the registration, qualification or listing of the Shares, (ii) adjustments pursuant to Section 5(d) of the Plan, and (iii) other requirements of applicable law. The Committee shall have the authority to interpret and construe the grant pursuant to the terms of the Plan, and its decisions shall be conclusive as to any questions arising hereunder.

(b)This Performance Unit grant and Shares issued pursuant to this Performance Unit grant shall be subject to the UGI Corporation Stock Ownership Policy as adopted by the Board of Directors of UGI and any applicable clawback and other policies implemented by the Board of Directors of UGI, as in effect from time to time.

10.No Employment or Other Rights. The grant of Performance Units shall not confer upon the Participant any right to be retained by or in the employ or service of the Company and shall not interfere in any way with the right of the Company to terminate the Participant’s employment or service at any time. The right of the Company to terminate at will the Participant’s employment or service at any time for any reason is specifically reserved.

11.No Shareholder Rights. Neither the Participant, nor any person entitled to receive payment in the event of the Participant’s death, shall have any of the rights and privileges of a shareholder with respect to the Shares related to the Performance Units, unless and until certificates for Shares have been distributed to the Participant or successor.

12.Assignment and Transfers. The rights and interests of the Participant under this Grant Letter may not be sold, assigned, encumbered or otherwise transferred except, in the event of the death of the Participant, by will or by the laws of descent and distribution. If the Participant dies, any payments to be made under this Grant Letter after the Participant’s death shall be paid to the

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Participant’s estate. The rights and protections of the Company hereunder shall extend to any successors or assigns of the Company and to the Company’s parents, subsidiaries, and affiliates.

13.Compliance with Code Section 409A. Notwithstanding the other provisions hereof, this Grant Letter is intended to comply with the requirements of section 409A of the Internal Revenue Code of 1986, as amended, or an exception, and shall be administered accordingly. Any reference to a Participant’s termination of employment shall mean a Participant’s “separation from service,” as such term is defined under section 409A. For purposes of section 409A, each payment of compensation under this Grant Letter shall be treated as a separate payment. Notwithstanding anything in this Grant Letter to the contrary, if the Participant is a “key employee” under section 409A and if payment of any amount under this Grant Letter is required to be delayed for a period of six months after separation from service pursuant to section 409A, payment of such amount shall be delayed as required by section 409A and shall be paid within 10 days after the end of the six-month period. If the Participant dies during such six-month period, the amounts withheld on account of section 409A shall be paid to the personal representative of the Participant’s estate within 60 days after the date of the Participant’s death. Notwithstanding anything in this Grant Letter to the contrary, if a Change of Control is not a “change in control event” under section 409A, any Performance Units and Dividend Equivalents that are payable pursuant to Section 6 shall be paid to the Participant between January 1, 2018 and March 15, 2018, and not upon the earlier separation from service, if required by section 409A.

14.Applicable Law. The validity, construction, interpretation and effect of this Grant Letter shall be governed by and construed in accordance with the laws of the Commonwealth of Pennsylvania, without giving effect to the conflicts of laws provisions thereof.

15.Notice. Any notice to UGI provided for in this Grant Letter shall be addressed to UGI in care of the Corporate Secretary at UGI’s headquarters, and any notice to the Participant shall be addressed to such Participant at the current address shown on the payroll of the Company, or to such other address as the Participant may designate to the Company in writing. Any notice shall be delivered by hand, sent by telecopy or enclosed in a properly sealed envelope addressed as stated above, registered and deposited, postage prepaid, in a post office regularly maintained by the United States Postal Service.

16.Acceptance. By accepting this grant through the Morgan Stanley on-line system, the Participant (i) acknowledges receipt of the Plan incorporated herein, (ii) acknowledges that he or she has read the Grant Summary and Grant Letter and understands the terms and conditions of them, (iii) accepts the Performance Units described in the Grant Letter, (iv) agrees to be bound by the terms of the Plan, including the Grant Letter, and (v) agrees that all the decisions and determinations of the Board or the Committee shall be final and binding on the Participant and any other person having or claiming a right under this Grant.

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EXHIBIT A

UGI CORPORATION

PERFORMANCE UNIT PEER GROUP

RUSSELL MIDCAP UTILITIES

(EXCLUDING TELECOMS)

as of 1/1/2015

AES Corp (AES) AGL Resources Inc (GAS) Alliant Energy Corp (LNT) Ameren Corp (AEE) American Water Works Co Inc (AWK) Aqua America Inc (WTR) Atmos Energy Corp (ATO) Calpine Corp (CPN) CenterPoint Energy Inc (CNP) CMS Energy Corp (CMS) Consolidated Edison Inc (ED) DTE Energy Co (DTE) Edison International (EIX) Energen Corp (EGN) Entergy Corp (ETR) FirstEnergy Corp (FE) Great Plains Energy Inc (GXP) Hawaiian Electric Industries Inc (HE) Integrys Energy Group Inc (TEG) ITC Holdings Corp (ITC) MDU Resources Group Inc (MDU) National Fuel Gas Co (NFG) NiSource Inc (NI) Northeast Utilities (NU) NRG Energy Inc (NRG) OGE Energy Corp (OGE) Pepco Holdings Inc (POM) Pinnacle West Capital Corp (PNW) PPL Corp (PPL) Public Service Enterprise Group Inc (PEG) Questar Corp (STR) SCANA Corp (SCG) Sempra Energy (SRE) TECO Energy Inc (TE) UGI Corp (UGI) Vectren Corp (VVC) Westar Energy Inc (WR) Wisconsin Energy Corp (WEC) Xcel Energy Inc (XEL)

A-1

EX-10.2

EXHIBIT 10.2

Non-Employee Directors

UGI CORPORATION
2013 OMNIBUS INCENTIVE COMPENSATION PLANSTOCK UNIT GRANT LETTER

This STOCK UNIT GRANT LETTER is dated as of January 8, 2015 (the “Date of Grant”) and delivered by UGI Corporation (“UGI”), to _______________________ (the “Participant”) (the “Grant Letter”).

RECITALS

The UGI Corporation 2013 Omnibus Incentive Compensation Plan, as amended (the “Plan”) provides for the grant of stock units with respect to shares of common stock of UGI (“Shares”). The Board of Directors of UGI (the “Board”) has decided to make a stock unit grant to the Participant.

NOW, THEREFORE, the parties to this Grant Letter, intending to be legally bound hereby, agree as follows:

1.Grant of Stock Units.

(a)Subject to the terms and conditions set forth in this Grant Letter, the Board hereby awards the Participant an award of 3,750 Stock Units (as defined in Section 4). The Stock Units are granted with Dividend Equivalents (as defined in Section 4).

(b)UGI shall keep records in an Account (as defined in Section 4) to reflect the number of Stock Units and Dividend Equivalents credited to the Participant. Fractional Stock Units shall accumulate in the Participant’s Account and shall be added to other fractional Stock Units to create whole Stock Units.

2.Dividend Equivalents with Respect to Stock Units.

(a)Crediting of Dividend Equivalents. From the Date of Grant until the Participant’s Account has been fully distributed, on each payment date for a dividend paid by UGI on its Shares, UGI shall credit to the Participant’s Account an amount equal to the Dividend Equivalent associated with the Stock Units credited to the Participant on the record date for the dividend.

(b)Conversion to Stock Units. On the last day of each Plan Year (as defined in Section 4), the amount of the Dividend Equivalents credited to the Participant’s Account during that Plan Year shall be converted to a number of Stock Units, based on the Unit Value (as defined in Section 4) on the last day of the Plan Year. In the event of a Change of Control (as defined in the Plan) or in the event the Participant dies or Separates from Service (as defined in Section 4) prior to the last day of the Plan Year, as soon as practicable following such event, and in no event later than the date on which Stock Units are redeemed in accordance with Section 3, UGI shall convert the amount of Dividend Equivalents previously credited to the Participant’s Account during the Plan Year to a number of Stock Units based on the Unit Value on the date of such Change of Control, death or Separation from Service.

3.Events Requiring Redemption of Stock Units.

(a)Redemption. UGI shall redeem Stock Units credited to the Participant’s Account at the times and in the manner prescribed by this Section 3. When Stock Units are to be redeemed, UGI will determine the Unit Value of the Stock Units credited to the Participant’s Account as of the date of the Participant’s Separation from Service or death. Except as described in subsection (c) below, an amount equal to 65% of the aggregate Unit Value will be paid in the form of whole Shares (with fractional Shares paid in cash), and the remaining 35% of the aggregate Unit Value will be paid in cash.

(b)Separation from Service or Death. In the event the Participant Separates from Service or dies, UGI shall redeem all the Stock Units then credited to the Participant’s Account as of the date of the Participant’s Separation from Service or death. In the event of a Separation from Service, the redemption amount shall be paid within 30 business days after the date of the Participant’s Separation from Service. In the event of death, the redemption amount shall be paid to the Participant’s estate within 60 business days after the Participant’s death.

(c)Change of Control. In the event of a Change of Control, UGI shall redeem all the Stock Units then credited to the Participant’s Account. The redemption amount shall be paid in cash on the closing date of the Change of Control (except as described below). The amount paid shall equal the product of the number of Stock Units being redeemed multiplied by the Unit Value at the date of the Change of Control. However, in the event that the transaction constituting a Change of Control is not a change in control event under section 409A of the Code (as defined in Section 4), the Participant’s Stock Units shall be redeemed and paid in cash upon Separation from Service on the applicable date described in subsection (b) above (based on the aggregate Unit Value on the date of Separation from Service as determined by the Board), instead of upon the Change of Control pursuant to this subsection (c). If payment is delayed after the Change of Control, pursuant to the preceding sentence, the Board may provide for the Stock Units to be valued as of the date of the Change of Control and interest to be credited on the amount so determined at a market rate for the period between the Change of Control date and the payment date.

(d)Deferral Elections. Notwithstanding the foregoing, pursuant to the Deferral Plan, the Participant may make a one-time, irrevocable election to elect to have all of the Participant’s Stock Units credited to the Participant’s account under the Deferral Plan on the date of the Participant’s Separation from Service, in lieu of the redemption and payments described in subsection (b) above. If the Participant makes a deferral election, the Participant’s Stock Units will be credited to the Participant’s account under the Deferral Plan at Separation from Service and the amount credited to the Deferral Plan shall be distributed in accordance with the provisions of the Deferral Plan. If the Participant makes a deferral election under the Deferral Plan and a Change of Control occurs: (i) subsection (c) above shall apply if the Change of Control occurs before the Participant’s Separation from Service and (ii) the terms of the Deferral Plan shall apply if the Change of Control occurs after or simultaneously with the Participant’s Separation from Service. An election under the Deferral Plan shall be made in writing, on a form

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and at a time prescribed by the committee that administers the Deferral Plan and shall be irrevocable upon submission to the Corporate Secretary.

4.Definitions. For purposes of this Grant Letter, the following terms will have the meanings set forth below:

(a)“Account” means UGI’s bookkeeping account established pursuant to Section 1, which reflects the number of Stock Units and the amount of Dividend Equivalents standing to the credit of the Participant.

(b)“Dividend Equivalent” means an amount determined by multiplying the number of Shares subject to Stock Units by the per-share cash dividend, or the per-share fair market value of any dividend in consideration other than cash, paid by UGI on its common stock.

(c)“Code” means the Internal Revenue Code of 1986, as amended.

(d)“Deferral Plan” means the UGI Corporation 2009 Deferral Plan.

(e)“Plan Year” means the calendar year.

(f)“Separates from Service” or “Separation from Service” means the Participant’s termination of service as a non‑employee director and as an employee of UGI for any reason other than death and shall be determined in accordance with section 409A of the Code.

(g)“Stock Unit” means the right of the Participant to receive a Share of UGI common stock, or an amount based on the value of a Share of UGI common stock, subject to the terms and conditions of this Grant Letter and the Plan.

(h)“Unit Value” means, at any time, the value of each Stock Unit, which value shall be equal to the Fair Market Value (as defined in the Plan)of a Share on such date.

5.Taxes. All obligations of UGI under this Grant Letter shall be subject to the rights of UGI as set forth in the Plan to withhold amounts required to be withheld for any taxes, if applicable.

6.Conditions. The obligation of UGI to deliver Shares shall also be subject to the condition that if at any time the Board shall determine in its discretion that the listing, registration or qualification of the Shares upon any securities exchange or under any state or federal law, or the consent or approval of any governmental regulatory body is necessary or desirable as a condition of, or in connection with, the issue of Shares, the Shares may not be issued in whole or in part unless such listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to the Board. The issuance of Shares to the Participant pursuant to this Grant Letter is subject to any applicable taxes and other laws or regulations of the United States or of any state having jurisdiction thereof.

7.Grant Subject to Plan Provisions and Company Policies.

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(a)This grant is made pursuant to the Plan which is incorporated herein by reference, and in all respects shall be interpreted in accordance with the Plan. The grant and payment of the Stock Units are subject to interpretations, regulations and determinations concerning the Plan established from time to time by the Board in accordance with the provisions of the Plan, including, but not limited to, provisions pertaining to (i) the registration, qualification or listing of the Shares issued under the Plan, (ii) changes in capitalization of UGI and (iii) other requirements of applicable law. The Board shall have the authority to interpret and construe this Grant Letter pursuant to the terms of the Plan, and its decisions shall be conclusive as to any questions arising hereunder.

(b)All Shares issued pursuant to this Stock Unit grant shall be subject to any applicable policies implemented by the Board of Directors of UGI, as in effect from time to time.

8.No Shareholder Rights. Neither the Participant, nor any person entitled to receive payment in the event of the Participant’s death, shall have any of the rights and privileges of a shareholder with respect to Shares, until certificates for Shares have been issued upon payment of Stock Units. The Participant shall not have any interest in any fund or specific assets of UGI by reason of this award or the Stock Unit account established for the Participant.

9.Assignment and Transfers. The rights and interests of the Participant under this Grant Letter may not be sold, assigned, encumbered or otherwise transferred except, in the event of the death of the Participant, by will or by the laws of descent and distribution. If the Participant dies, any payments to be made under this Grant Letter after the Participant’s death shall be paid to the Participant’s estate. The rights and protections of UGI hereunder shall extend to any successors or assigns of UGI and to UGI’s parents, subsidiaries, and affiliates.

10.Compliance with Code Section 409A. Notwithstanding any other provisions hereof, this Agreement is intended to comply with the requirements of section 409A of the Code. For purposes of section 409A, each payment of compensation under this Agreement shall be treated as a separate payment.

11.Applicable Law. The validity, construction, interpretation and effect of this instrument shall be governed by and construed in accordance with the laws of the Commonwealth of Pennsylvania, without giving effect to the conflicts of laws provisions thereof.

12.Notice. Any notice to UGI provided for in this instrument shall be addressed to UGI in care of the Corporate Secretary at UGI’s headquarters, and any notice to the Participant shall be addressed to such Participant at the current address shown on the records of UGI, or to such other address as the Participant may designate to UGI in writing. Any notice shall be delivered by hand, sent by telecopy or enclosed in a properly sealed envelope addressed as stated above, registered and deposited, postage prepaid, in a post office regularly maintained by the United States Postal Service.

4

IN WITNESS WHEREOF, the parties have executed this Stock Unit Grant Letter as of the Date of Grant.

Attest:                        UGI Corporation

By:                         Name:                                                  Title:

I hereby (i) acknowledge receipt of the Plan incorporated herein, (ii) acknowledge that I have read the Grant Letter and understand the terms and conditions of it, (iii) accept the Stock Units described in the Grant Letter, (iv) agree to be bound by the terms of the Plan and the Grant Letter, and (v) agree that all the decisions and determinations of the Board or the Committee shall be final and binding on me and any other person having or claiming a right under this Grant.

Participant

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EX-10.3

EXHIBIT 10.3

Non-Employee Directors

UGI CORPORATION
2004 OMNIBUS EQUITY COMPENSATION PLANNONQUALIFIED STOCK OPTION GRANT LETTER

This STOCK OPTION GRANT, dated as of January 8, 2015 (the “Date of Grant”), is delivered by UGI Corporation (“UGI”) to ______________________ (the “Participant”).

RECITALS

The UGI Corporation 2004 Omnibus Equity Compensation Plan, as amended (the “Plan”) provides for the grant of options to purchase shares of common stock of UGI. The Board of Directors of UGI (the “Board”) has decided to make a stock option grant to the Participant.

NOW, THEREFORE, the parties to this Grant Letter, intending to be legally bound hereby, agree as follows:

1.Grant of Option. Subject to the terms and conditions set forth in this Grant Letter and in the Plan, the Board hereby grants to the Participant a nonqualified stock option (the “Option”) to purchase 11,250 shares of common stock of UGI (“Shares”) at an exercise price of $37.15 per Share. The Option shall be fully and immediately exercisable on the Date of Grant.

2.Term of Option.

(a)The Option shall have a term of ten years from the Date of Grant and shall terminate at the expiration of that period (5:00 p.m. EST on January 7, 2025), unless it is terminated at an earlier date pursuant to the provisions of this Grant Letter or the Plan.

(b)The Option, to the extent that it has not previously been exercised, will terminate when the Participant Separates from Service (as defined below) with the Company (as defined below). However, if the Participant Separates from Service by reason of Retirement (as defined below), Disability (as defined below), or death, the Option will thereafter be exercisable pursuant to the following:

(i)Retirement. If the Participant Separates from Service on account of Retirement, the Option held by such Participant may be exercised at any time prior to the expiration date of the Option.

(ii)Disability. If the Participant is determined to be Disabled by the Board, the Option may be exercised at any time prior to the earlier of the expiration date of the Option or the expiration of the 36-month period following the Participant’s Separation from Service on account of Disability.

(iii)Death. In the event of the death of the Participant while serving as a non‑employee director or employee of the Company, the Option may be exercised by the

personal representative of the Participant’s estate, or the personal representative under applicable law if the Participant dies intestate, at any time prior to the earlier of the expiration date of the Option or the expiration of the 12-month period following the Participant’s death.

(c)In no event may the Option be exercised after the date that is immediately before the tenth anniversary of the Date of Grant.

3.Exercise Procedures.

(a)Subject to the provisions of Section 2 above, the Participant may exercise part or all of the exercisable Option by giving UGI irrevocable written notice of intent to exercise on a form provided by UGI and delivered in the manner provided in Section 11 below. Payment of the exercise price must be made prior to issuance of the Shares. The Participant shall pay the exercise price (i) in cash, (ii) by delivering Shares, which shall be valued at their fair market value on the date of delivery, which shall have been held by the Participant for at least six months, and which shall have a fair market value on the date of exercise equal to the exercise price, (iii) by payment through a broker in accordance with procedures permitted by Regulation T of the Federal Reserve Board, (iv) by a “net exercise” in accordance with procedures established by the Committee, or (v) by such other method as the Board may approve.

(b)The obligation of UGI to deliver Shares upon exercise of the Option shall be subject to all applicable laws, rules, and regulations and such approvals by governmental agencies as may be deemed appropriate by the Board, including such actions as UGI’s counsel shall deem necessary or appropriate to comply with relevant securities laws and regulations. UGI may require that the Participant (or other person exercising the Option after the Participant’s death) represent that the Participant is purchasing Shares for the Participant’s own account and not with a view to or for sale in connection with any distribution of the Shares, or such other representation as UGI deems appropriate.

(c)All obligations of UGI under this Grant Letter shall be subject to the rights of the Company as set forth in the Plan to withhold amounts required to be withheld for any taxes, if applicable.

4.Definitions. Whenever used in this Grant Letter, the following terms will have the meanings set forth below:

(a)“Company” means UGI and its Subsidiaries (as defined in the Plan).

(b)“Disability” means the Participant’s physical or mental disability, as determined by the Board in its sole discretion.

(c)“Retirement” means the Participant’s Separation from Service after (1) attaining age 65 with five or more years of service with the Company or (2) ten or more years of service with the Company.

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(d)“Separates from Service” or “Separation from Service” means the Participant’s termination of service as a non-employee director and as an employee of the Company for any reason other than death.

(e)“Termination without Cause” means termination of employment or service by the Company for the convenience of the Company for any reason other than (i) theft or misappropriation of funds or conduct that has an adverse effect on the reputation of the Company, (ii) conviction of a felony or a crime involving moral turpitude, (iii) material breach of the Company’s written code of conduct, or other material written employment policies, applicable to the Participant, (iv) breach of any written confidentiality, non-competition or non-solicitation covenant between the Participant and the Company, (v) gross misconduct in the performance of duties, or (vi) intentional refusal or failure to perform the material duties of the Participant’s position.

5.Change of Control. The provisions of the Plan applicable to a Change of Control (as defined in the Plan) shall apply to the Option, and, in the event of a Change of Control, the Board may take such actions as it deems appropriate pursuant to the Plan.

6.Restrictions on Exercise. Only the Participant may exercise the Option during the Participant’s lifetime and, after the Participant’s death, the Option shall be exercisable by the Participant’s estate, to the extent that the Option is exercisable pursuant to this Grant Letter.

7.Grant Subject to Plan Provisions and Company Policies.

(a)This grant is made pursuant to the Plan which is incorporated herein by reference, and in all respects shall be interpreted in accordance with the Plan. The grant and exercise of the Option are subject to interpretations, regulations and determinations concerning the Plan established from time to time by the Board in accordance with the provisions of the Plan, including, but not limited to, provisions pertaining to (i) the registration, qualification or listing of the Shares, (ii) changes in capitalization of the Company and (iii) other requirements of applicable law. The Board shall have the authority to interpret and construe the Option pursuant to the terms of the Plan, and its decisions shall be conclusive as to any questions arising hereunder.

(b)All Shares issued pursuant to this grant shall be subject to any applicable policies implemented by the Board of Directors of UGI as in effect from time to time.

8.No Shareholder Rights. Neither the Participant, nor any person entitled to exercise the Participant’s rights in the event of the Participant’s death, shall have any of the rights and privileges of a shareholder with respect to the Shares subject to the Option, until certificates for Shares have been issued upon the exercise of the Option.

9.Assignment and Transfers. Except as the Board may otherwise permit pursuant to the Plan, the rights and interests of the Participant under this Grant Letter may not be sold, assigned, encumbered or otherwise transferred except, in the event of the death of the Participant, by will or by the laws of descent and distribution. The rights and protections of the Company hereunder

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shall extend to any successors or assigns of the Company and to the Company’s parents, subsidiaries, and affiliates.

10.Applicable Law. The validity, construction, interpretation and effect of this instrument shall be governed by and construed in accordance with the laws of the Commonwealth of Pennsylvania, without giving effect to the conflicts of laws provisions thereof.

11.Notice. Any notice to UGI provided for in this instrument shall be addressed to UGI in care of the Corporate Secretary at UGI’s headquarters, and any notice to the Participant shall be addressed to such Participant at the current address shown on the records of the Company, or to such other address as the Participant may designate to the Company in writing. Any notice shall be delivered by hand, sent by telecopy or enclosed in a properly sealed envelope addressed as stated above, registered and deposited, postage prepaid, in a post office regularly maintained by the United States Postal Service.

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IN WITNESS WHEREOF, UGI has caused its duly authorized officers to execute and attest this Grant Letter, and the Participant has executed this Grant Letter, effective as of the Date of Grant.

Attest:                        UGI Corporation

By:                         Name:                                                  Title:

I hereby (i) acknowledge receipt of the Plan incorporated herein, (ii) acknowledge that I have read the Grant Letter and understand the terms and conditions of it, (iii) accept the Option described in the Grant Letter, (iv) agree to be bound by the terms of the Plan and the Grant Letter, and (v) agree that all the decisions and determinations of the Board or the Committee shall be final and binding on me and any other person having or claiming a right under this Grant.

Participant

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EX-10.4

EXHIBIT 10.4

UGI Employees

UGI CORPORATION
2013 OMNIBUS INCENTIVE COMPENSATION PLANNONQUALIFIED STOCK OPTION GRANT LETTER

This STOCK OPTION GRANT, dated January 1, 2015 (the “Date of Grant”), is delivered by UGI Corporation (“UGI”) to you (the “Participant”).

RECITALS

The UGI Corporation 2013 Omnibus Incentive Compensation Plan (the “Plan”), provides for the grant of options to purchase shares of common stock of UGI. The Compensation and Management Development Committee of the Board of Directors of UGI (the “Committee”) has decided to make a stock option grant to the Participant. The Participant’s portal in the Morgan Stanley website for Plan participants (the “Grant Summary”) sets forth the number of shares subject to the Option granted to the Participant in this grant.

NOW, THEREFORE, the parties to this Grant Letter, intending to be legally bound hereby, agree as follows:

1.Grant of Option. Subject to the terms and conditions set forth in this Grant Letter and in the Plan, the Committee hereby grants to the Participant a nonqualified stock option (the “Option”) to purchase the number of shares of common stock of UGI (“Shares”) specified in the Grant Summary at an exercise price of $37.98 per Share. The Option shall become exercisable according to Section 2 below.

2.Exercisability of Option. The Option shall become exercisable on the following dates, if the Participant is employed by, or providing service to, the Company (as defined below) on the applicable date:

Date	Shares for Which the Option is Exercisable
January 1, 2016	33⅓%
January 1, 2017	33⅓%
January 1, 2018	33⅓%

The exercisability of the Option is cumulative, but shall not exceed 100% of the Shares subject to the Option. If the foregoing schedule would produce fractional Shares, the number of Shares for which the Option becomes exercisable shall be rounded down to the nearest whole Share.

3.Term of Option.

(a)The Option shall have a term of ten years from the Date of Grant and shall terminate at the expiration of that period (5:00 p.m. EST on December 31, 2024), unless it is terminated at an earlier date pursuant to the provisions of this Grant Letter or the Plan.

(b)If the Participant ceases to be employed by, or provide service to, the Company, the Option will terminate on the date the Participant ceases such employment or service. However, if the Participant ceases to be employed by, or provide service to, the Company by reason of one of the following events, the Option held by the Participant will thereafter be exercisable pursuant to the following terms:

(i)Termination without Cause. If the Participant terminates employment or service on account of a Termination without Cause, the Option will thereafter be exercisable only with respect to that number of Shares with respect to which the Option is already exercisable on the date the Participant’s employment or service terminates, except as provided in subsection (v) below. Such portion of the Option will terminate upon the earlier of the expiration date of the Option or the expiration of the 13-month period commencing on the date the Participant ceases to be employed by, or provide service to, the Company.

(ii)Retirement. If the Participant ceases to be employed by, or provide service to, the Company on account of Retirement, the Option will thereafter become exercisable as if the Participant had continued to be employed by, or provide service to, the Company after the date of such Retirement. The Option will terminate upon the expiration date of the Option.

(iii)Disability. If the Participant ceases to be employed by, or provide service to, the Company on account of Disability, the Option will thereafter become exercisable as if the Participant had continued to provide service to the Company for 36 months after the date of such termination of employment or service. The Option will terminate upon the earlier of the expiration date of the Option or the expiration of such 36-month period.

(iv)Death. In the event of the death of the Participant while employed by, or providing service to, the Company, the Option will be fully and immediately exercisable and may be exercised at any time prior to the earlier of the expiration date of the Option or the expiration of the 12-month period following the Participant’s death. Death of the Participant after the Participant has ceased to be employed by, or provide service to, the Company will not affect the otherwise applicable period for exercise of the Option determined pursuant to subsections (i), (ii), (iii) or (v). After the Participant’s death, the Participant’s Option may be exercised by the Participant’s estate.

(v)Termination without Cause or Good Reason Termination upon or within two years after a Change of Control. Notwithstanding the foregoing, if the Participant’s employment or service terminates on account of a Termination without Cause or a Good Reason Termination upon or within two years after a Change of Control, the Option will

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be fully and immediately exercisable. The Option will terminate upon the earlier of the expiration date of the Option or the expiration of the 13-month period commencing on the date the Participant ceases to be employed by, or provide service to, the Company; provided that if the Participant is eligible for Retirement at the date of such termination of employment, the Option will terminate on the expiration date of the Option.

4.Exercise Procedures.

(a)Subject to the provisions of Sections 2 and 3 above, the Participant may exercise part or all of the exercisable Option through the Morgan Stanley website for Plan participants. Payment of the exercise price and any applicable withholding taxes must be made prior to issuance of the Shares. The Participant shall pay the exercise price (i) in cash, (ii) by “net exercise,” which is the surrender of shares for which the Option is exercisable to the Company in exchange for a distribution of Shares equal to the amount by which the then fair market value of the Shares subject to the exercised Option exceeds the applicable Option Price, (iii) by payment through a broker in accordance with procedures acceptable to the Committee and permitted by Regulation T of the Federal Reserve Board or (iv) by such other method as the Committee may approve. The Committee may impose such limitations as it deems appropriate on the use of Shares to exercise the Option.

(b)The obligation of UGI to deliver Shares upon exercise of the Option shall be subject to all applicable laws, rules, and regulations and such approvals by governmental agencies as may be deemed appropriate by the Committee, including such actions as UGI’s counsel shall deem necessary or appropriate to comply with relevant securities laws and regulations. UGI may require that the Participant (or other person exercising the Option after the Participant’s death) represent that the Participant is purchasing Shares for the Participant’s own account and not with a view to or for sale in connection with any distribution of the Shares, or such other representation as UGI deems appropriate.

(c)All obligations of UGI under this Grant Letter shall be subject to the rights of the Company as set forth in the Plan to withhold amounts required to be withheld for any taxes, if applicable.

5.Definitions. Whenever used in this Grant Letter, the following terms shall have the meanings set forth below:

(a)“Change of Control”shall have the meaning given that term in the Plan.

(b)“Company” means UGI and its Subsidiaries (as defined in the Plan).

(c)“Disability” means a long-term disability as defined in the Company’s long-term disability plan applicable to the Participant.

(d)“Employed by, or provide service to, the Company” shall mean employment or service as an employee or director of the Company.

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(e)“Good Reason Termination” shall mean a termination of employment or service initiated by the Participant upon or within two years after a Change of Control upon one or more of the following occurrences:

(i)a material diminution in the authority, duties or responsibilities held by the Participant immediately prior to the Change of Control;

(ii)a material diminution in the Participant’s base salary as in effect immediately prior to the Change of Control; or

(iii)a material change in the geographic location at which the Participant must perform services (which, for purposes of this Grant Letter, means the Participant is required to report, other than on a temporary basis (less than 12 months), to a location which is more than 50 miles from the Participant’s principal place of business immediately preceding the Change of Control, without the Participant’s express written consent).

Notwithstanding the foregoing, the Participant shall be considered to have a Good Reason Termination only if the Participant provides written notice to the Company, pursuant to Section 13, specifying in reasonable detail the events or conditions upon which the Participant is basing such Good Reason Termination and the Participant provides such notice within 90 days after the event that gives rise to the Good Reason Termination. Within 30 days after notice has been provided, the Company shall have the opportunity, but shall have no obligation, to cure such events or conditions that give rise to the Good Reason Termination. If the Company does not cure such events or conditions within the 30-day period, the Participant may terminate employment or service with the Company based on Good Reason Termination within 30 days after the expiration of the cure period.

Notwithstanding the foregoing, if the Participant has in effect a Change in Control Agreement with the Company or an Affiliate, the term “Good Reason Termination” shall have the meaning given that term in the Change in Control Agreement.

(f)“Retirement” means the Participant’s retirement under the Retirement Income Plan for Employees of UGI Utilities, Inc., if the Participant is covered by that Retirement Income Plan. “Retirement” for other Company employees means termination of employment or service after attaining (i) age 55 with ten or more years of service with the Company or (ii) age 65 with five or more years of service with the Company.

(g)“Termination without Cause” means termination of employment or service by the Company for the convenience of the Company for any reason other than (i) theft or misappropriation of funds or conduct that has an adverse effect on the reputation of the Company, (ii) conviction of a felony or a crime involving moral turpitude, (iii) material breach of the Company’s written code of conduct, or other material written employment policies, applicable to the Participant, (iv) breach of any written confidentiality, non-competition or non-solicitation covenant between the Participant and the Company, (v) gross misconduct in the

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performance of duties, or (vi) intentional refusal or failure to perform the material duties of the Participant’s position.

6.Change of Control. If a Change of Control occurs, the Committee may take such actions with respect to the Option as it deems appropriate pursuant to the Plan. The Option shall not automatically become exercisable upon a Change of Control but, instead, shall become exercisable as described in Sections 2 and 3 above.

7.Restrictions on Exercise. Except as the Committee may otherwise permit pursuant to the Plan, only the Participant may exercise the Option during the Participant’s lifetime and, after the Participant’s death, the Option shall be exercisable by the Participant’s estate, to the extent that the Option is exercisable pursuant to this Grant Letter.

8.Grant Subject to Plan Provisions and Company Policies.

(a)This grant is made pursuant to the Plan, which is incorporated herein by reference, and in all respects shall be interpreted in accordance with the Plan. The grant and exercise of the Option are subject to interpretations, regulations and determinations concerning the Plan established from time to time by the Committee in accordance with the provisions of the Plan, including, but not limited to, provisions pertaining to (i) the registration, qualification or listing of the Shares, (ii) changes in capitalization of the Company and (iii) other requirements of applicable law. The Committee shall have the authority to interpret and construe the Option pursuant to the terms of the Plan, and its decisions shall be conclusive as to any questions arising hereunder.

(b)All Shares issued pursuant to this Option grant shall be subject to the UGI Corporation Stock Ownership Policy. This Option grant and all Shares issued pursuant to this Option grant shall be subject to any applicable clawback and other policies implemented by the Board of Directors of UGI, as in effect from time to time.

9.No Employment or Other Rights. The grant of the Option shall not confer upon the Participant any right to be retained by or in the employ or service of the Company and shall not interfere in any way with the right of the Company to terminate the Participant’s employment or service at any time. The right of the Company to terminate at will the Participant’s employment or service at any time for any reason is specifically reserved.

10.No Shareholder Rights. Neither the Participant, nor any person entitled to exercise the Participant’s rights in the event of the Participant’s death, shall have any of the rights and privileges of a shareholder with respect to the Shares subject to the Option, until certificates for Shares have been issued upon the exercise of the Option.

11.Assignment and Transfers. The rights and interests of the Participant under this Grant Letter may not be sold, assigned, encumbered or otherwise transferred except, in the event of the death of the Participant, by will or by the laws of descent and distribution. The rights and protections of the Company hereunder shall extend to any successors or assigns of the Company and to the Company’s parents, subsidiaries, and affiliates.

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12.Applicable Law. The validity, construction, interpretation and effect of this instrument shall be governed by and construed in accordance with the laws of the Commonwealth of Pennsylvania, without giving effect to the conflicts of laws provisions thereof.

13.Notice. Any notice to UGI provided for in this instrument shall be addressed to UGI in care of the Corporate Secretary at UGI’s headquarters, and any notice to the Participant shall be addressed to such Participant at the current address shown on the payroll of the Company, or to such other address as the Participant may designate to the Company in writing. Any notice shall be delivered by hand, sent by telecopy or enclosed in a properly sealed envelope addressed as stated above, registered and deposited, postage prepaid, in a post office regularly maintained by the United States Postal Service.

14.Acceptance. By accepting this grant through the Morgan Stanley on-line system, the Participant (i) acknowledges receipt of the Plan incorporated herein, (ii) acknowledges that he or she has read the Grant Summary and Grant Letter and understands the terms and conditions of them, (iii) accepts the Option described in the Grant Letter, (iv) agrees to be bound by the terms of the Plan, including the Grant Letter, and (v) agrees that all the decisions and determinations of the Board or the Committee shall be final and binding on the Participant and any other person having or claiming a right under this Grant.

* * *

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EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, John L. Walsh, certify that:

1. I have reviewed this periodic report on Form 10-Q of UGI Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 8, 2015
		/s/ John L. Walsh
		John L. Walsh President and Chief Executive Officer of UGI Corporation

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Kirk R. Oliver, certify that:

1. I have reviewed this periodic report on Form 10-Q of UGI Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 8, 2015
		/s/ Kirk R. Oliver
		Kirk R. Oliver
		Chief Financial Officer of UGI Corporation

EX-32

EXHIBIT 32

Certification by the Chief Executive Officer and Chief Financial Officer

Relating to a Periodic Report Containing Financial Statements

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

(1) The Company’s periodic report on Form 10-Q for the period ended March 31, 2015 (the “Form 10-Q”) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended; and

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

CHIEF EXECUTIVE OFFICER		CHIEF FINANCIAL OFFICER
/s/ John L. Walsh		/s/ Kirk R. Oliver
John L. Walsh		Kirk R. Oliver
Date:	May 8, 2015	Date:	May 8, 2015

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Goodwill and Intangible Assets - Components of Company's Intangible Assets (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Sep. 30, 2014	Mar. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill (not subject to amortization)	$ 2,731.2	$ 2,833.4	$ 2,886.0
Intangible assets:
Customer relationships, noncompete agreements and other	670.2	712.0	727.5
Accumulated amortization	(254.1)	(263.8)	(251.6)
Intangible assets, net (definite-lived)	416.1	448.2	475.9
Trademarks and tradenames (indefinite-lived)	121.4	128.2	132.3
Total intangible assets, net	$ 537.5	$ 576.4	$ 608.2

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Segment Information (Details)	6 Months Ended
	Mar. 31, 2015 segment
Segment Reporting [Abstract]
Number of reportable segments (in reportable segments)	6

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Fair Value Measurements - Financial Assets and Liabilities that are Measured at Fair Value on a Recurring Basis (Details) (Fair Value, Measurements, Recurring, USD $) In Millions, unless otherwise specified	Mar. 31, 2015		Sep. 30, 2014		Mar. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	$ 31.8	[1]	$ 30.0	[1]	$ 29.8	[1],[2]
Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	22.2		30.4		31.5	[2]
Derivative financial instruments, liabilities	(168.3)		(54.1)		(29.7)	[2]
Foreign Currency Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	35.8		12.8		0.1	[2]
Derivative financial instruments, liabilities			(0.1)		(5.6)	[2]
Interest Rate Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0.1		0.1
Derivative financial instruments, liabilities	(12.5)		(21.0)		(27.8)	[2]
Cross-Currency Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	9.7		2.1
Derivative financial instruments, liabilities					(2.2)	[2]
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	31.8	[1]	30.0	[1]	29.8	[1],[2]
Level 1 | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	13.9		10.6		17.5	[2]
Derivative financial instruments, liabilities	(64.0)		(21.2)		(10.0)	[2]
Level 1 | Foreign Currency Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0		0	[2]
Derivative financial instruments, liabilities			0		0	[2]
Level 1 | Interest Rate Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0
Derivative financial instruments, liabilities	0		0		0	[2]
Level 1 | Cross-Currency Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0
Derivative financial instruments, liabilities					0	[2]
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	0	[1]	0	[1]	0	[1],[2]
Level 2 | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	8.3		19.8		14.0	[2]
Derivative financial instruments, liabilities	(104.3)		(32.9)		(19.7)	[2]
Level 2 | Foreign Currency Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	35.8		12.8		0.1	[2]
Derivative financial instruments, liabilities			(0.1)		(5.6)	[2]
Level 2 | Interest Rate Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0.1		0.1
Derivative financial instruments, liabilities	(12.5)		(21.0)		(27.8)	[2]
Level 2 | Cross-Currency Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	9.7		2.1
Derivative financial instruments, liabilities					(2.2)	[2]
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	0	[1]	0	[1]	0	[1],[2]
Level 3 | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0		0	[2]
Derivative financial instruments, liabilities	0		0		0	[2]
Level 3 | Foreign Currency Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0		0	[2]
Derivative financial instruments, liabilities			0		0	[2]
Level 3 | Interest Rate Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0
Derivative financial instruments, liabilities	0		0		0	[2]
Level 3 | Cross-Currency Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0
Derivative financial instruments, liabilities					$ 0	[2]

[1] Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.

[2] Certain immaterial amounts have been revised to correct the classification of derivatives.

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Segment Information - Schedule of Segment Reporting Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended
	Mar. 31, 2015		Mar. 31, 2014		Mar. 31, 2015		Mar. 31, 2014		Sep. 30, 2014
Segment Reporting Information
Revenues	$ 2,455.6		$ 3,163.3		$ 4,460.2		$ 5,479.2
Cost of sales	1,205.4		2,001.3		2,610.0		3,431.2
Segment profit:
Operating income	702.1		588.6		785.4		952.3
Loss from equity investees	(0.1)		0		(1.1)		0
Interest expense	(58.2)		(59.5)		(117.2)		(118.8)
Income before income taxes	643.8		529.1		667.1		833.5
Noncontrolling interests’ net income	235.7		173.4		201.8		268.9
Depreciation and amortization	88.0		87.7		179.0		181.7
Capital expenditures	(91.4)		(85.3)		(214.9)		(188.1)
Total assets	10,182.7		10,720.5		10,182.7		10,720.5		10,093.0
Short-term borrowings	89.9		260.1		89.9		260.1		210.8
Goodwill	2,731.2		2,886.0		2,731.2		2,886.0		2,833.4
Gains (losses) on unsettled commodity derivative instruments, net	102.2		(13.2)		(127.5)		(6.0)
Eliminations
Segment Reporting Information
Revenues	(114.7)	[1]	(164.7)	[1]	(182.4)	[1]	(230.2)	[1]
Cost of sales	(114.0)	[1]	(164.0)	[1]	(181.0)	[1]	(228.4)	[1]
Segment profit:
Operating income	0.1		0.2		0.1		0.1
Loss from equity investees	0		0		0		0
Interest expense	0		0		0		0
Income before income taxes	0.1		0.2		0.1		0.1
Noncontrolling interests’ net income	0		0		0		0
Depreciation and amortization	(0.1)		(0.1)		(0.1)		(0.1)
Capital expenditures	0		0		0		1.2
Total assets	(109.5)		(116.3)		(109.5)		(116.3)
Short-term borrowings	0		0		0		0
Goodwill	0		0		0		0
AmeriGas Propane
Segment Reporting Information
Revenues	1,100.3		1,493.7		1,989.1		2,539.5
Cost of sales	505.2		885.5		967.6		1,468.2
Segment profit:
Operating income	296.9		284.8		436.6		464.5
Loss from equity investees	0		0		0		0
Interest expense	(41.1)		(42.0)		(82.1)		(83.6)
Income before income taxes	255.8		242.8		354.5		380.9
Partnership Adjusted EBITDA	342.1	[2]	331.2	[2]	530.6	[2]	561.5	[2]
Noncontrolling interests’ net income	88.3		173.2		155.1		268.6
Depreciation and amortization	48.1		49.2		97.5		101.5
Capital expenditures	(26.8)		(27.7)		(57.2)		(51.0)
Total assets	4,423.8		4,692.3		4,423.8		4,692.3
Short-term borrowings	55.0		198.0		55.0		198.0
Goodwill	1,949.7		1,939.0		1,949.7		1,939.0
Noncontrolling interests	2.9	[3]	2.8	[3]	3.5	[3]	4.5	[3]
Gas Utility
Segment Reporting Information
Revenues	468.0		480.1		728.5		751.7
Cost of sales	258.2		278.8		385.4		414.3
Segment profit:
Operating income	139.3		134.5		211.1		216.6
Loss from equity investees	0		0		0		0
Interest expense	(10.1)		(8.4)		(20.2)		(16.8)
Income before income taxes	129.2		126.1		190.9		199.8
Noncontrolling interests’ net income	0		0		0		0
Depreciation and amortization	14.5		13.6		28.8		27.0
Capital expenditures	(39.2)		(30.0)		(92.7)		(62.9)
Total assets	2,359.1		2,195.4		2,359.1		2,195.4
Short-term borrowings	30.5		6.5		30.5		6.5
Goodwill	182.1		182.1		182.1		182.1
Midstream & Marketing, Energy Services
Segment Reporting Information
Revenues	409.4		588.9		706.4		861.6
Cost of sales	296.5		457.9		530.9		685.0
Segment profit:
Operating income	93.9		111.5		140.1		143.3
Loss from equity investees	0		0		0		0
Interest expense	(0.5)		(1.0)		(1.1)		(2.0)
Income before income taxes	93.4		110.5		139.0		141.3
Noncontrolling interests’ net income	0		0		0		0
Depreciation and amortization	3.6		3.2		7.2		5.8
Capital expenditures	(5.9)		(8.4)		(18.7)		(30.1)
Total assets	690.8		643.2		690.8		643.2
Short-term borrowings	0		51.5		0		51.5
Goodwill	5.6		2.8		5.6		2.8
Midstream & Marketing, Electric Generation
Segment Reporting Information
Revenues	24.8		25.1		41.3		45.9
Cost of sales	9.4		9.4		17.4		20.0
Segment profit:
Operating income	8.0		9.9		7.3		14.3
Loss from equity investees	0		0		0		0
Interest expense	0		0		0		0
Income before income taxes	8.0		9.9		7.3		14.3
Noncontrolling interests’ net income	0		0		0		0
Depreciation and amortization	3.3		2.7		6.0		5.3
Capital expenditures	(2.3)		(1.8)		(8.9)		(11.1)
Total assets	281.2		283.9		281.2		283.9
Short-term borrowings	0		0		0		0
Goodwill	0		0		0		0
UGI International, Antargaz
Segment Reporting Information
Revenues	347.2		412.0		685.1		837.3
Cost of sales	200.3		266.7		409.6		549.2
Segment profit:
Operating income	53.2		52.9		91.6		96.1
Loss from equity investees	(0.1)		0		(1.1)		0
Interest expense	(4.9)		(6.4)		(10.5)		(12.8)
Income before income taxes	48.2		46.5		80.0		83.3
Noncontrolling interests’ net income	0.3		0.2		0.4		0.3
Depreciation and amortization	11.8		10.3		25.1		25.3
Capital expenditures	(9.6)		(11.3)		(21.7)		(21.1)
Total assets	1,569.2		1,923.2		1,569.2		1,923.2
Short-term borrowings	0.1		0		0.1		0
Goodwill	510.9		655.3		510.9		655.3
UGI International, Flaga & Other
Segment Reporting Information
Revenues	172.9		277.2		397.5		570.5
Cost of sales	123.3		222.7		295.9		454.4
Segment profit:
Operating income	11.5		10.9		26.6		24.6
Loss from equity investees	0		0		0		0
Interest expense	(0.9)		(1.1)		(1.9)		(2.4)
Income before income taxes	10.6		9.8		24.7		22.2
Noncontrolling interests’ net income	0		0		0		0
Depreciation and amortization	5.2		7.2		11.3		13.8
Capital expenditures	(5.4)		(4.2)		(11.8)		(8.8)
Total assets	539.7		660.4		539.7		660.4
Short-term borrowings	4.3		4.1		4.3		4.1
Goodwill	76.7		99.8		76.7		99.8
Corporate & Other
Segment Reporting Information
Revenues	47.7	[4]	51.0	[4]	94.7	[4]	102.9	[4]
Cost of sales	(73.5)	[4]	44.3	[4]	184.2	[4]	68.5	[4]
Segment profit:
Operating income	99.2	[4]	(16.1)	[4]	(128.0)	[4]	(7.2)	[4]
Loss from equity investees	0	[4]	0	[4]	0	[4]	0	[4]
Interest expense	(0.7)	[4]	(0.6)	[4]	(1.4)	[4]	(1.2)	[4]
Income before income taxes	98.5	[4]	(16.7)	[4]	(129.4)	[4]	(8.4)	[4]
Noncontrolling interests’ net income	147.1	[4]	0	[4]	46.3	[4]	0	[4]
Depreciation and amortization	1.6	[4]	1.6	[4]	3.2	[4]	3.1	[4]
Capital expenditures	(2.2)	[4]	(1.9)	[4]	(3.9)	[4]	(4.3)	[4]
Total assets	428.4	[4]	438.4	[4]	428.4	[4]	438.4	[4]
Short-term borrowings	0	[4]	0	[4]	0	[4]	0	[4]
Goodwill	$ 6.2	[4]	$ 7.0	[4]	$ 6.2	[4]	$ 7.0	[4]

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

[2] The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income: Three Months EndedMarch 31, Six Months Ended March 31, 2015 2014 2015 2014Partnership Adjusted EBITDA $342.1 $331.2 $530.6 $561.5Depreciation and amortization (48.1) (49.2) (97.5) (101.5)Noncontrolling interests (i) 2.9 2.8 3.5 4.5Operating income $296.9 $284.8 $436.6 $464.5(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

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

[4] Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, and (4) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include net gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $102.2 and $(13.2) during the three months ended March 31, 2015 and 2014, respectively, and $(127.5) and $(6.0) during the six months ended March 31, 2015 and 2014, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and, in the three and six months ended March 31, 2014, an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.

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Defined Benefit Pension and Other Postretirement Plans - Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015	Mar. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 2.5	$ 2.3	$ 4.9	$ 4.7
Interest cost	6.3	6.5	12.6	12.9
Expected return on assets	(8.0)	(7.3)	(15.9)	(14.7)
Amortization of:
Prior service cost (benefit)	0.1	0.1	0.2	0.2
Actuarial loss	2.5	1.9	5.0	3.8
Net benefit cost	3.4	3.5	6.8	6.9
Change in associated regulatory liabilities	0	0	0	0
Net expense	3.4	3.5	6.8	6.9
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	0.1	0.1	0.3	0.3
Interest cost	0.2	0.2	0.4	0.5
Expected return on assets	(0.1)	(0.1)	(0.3)	(0.3)
Amortization of:
Prior service cost (benefit)	(0.1)	(0.1)	(0.2)	(0.2)
Actuarial loss	0	0	0	0
Net benefit cost	0.1	0.1	0.2	0.3
Change in associated regulatory liabilities	1.0	0.9	1.9	1.8
Net expense	$ 1.1	$ 1.0	$ 2.1	$ 2.1

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Nature of Operations (Details) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General Partner held a general partner interest in AmeriGas Partners	1.00%
Percentage of limited partnership interest in AmeriGas Partners	25.30%
Effective ownership interest in AmeriGas OLP	27.10%
Limited Partnership Common Units held in AmeriGas Partners (in units)	23,756,882
General public as limited partner interests in AmeriGas Partners	73.70%
Common Units owned by public (in units)	69,131,947
General Partner incentive distribution	$ 13.1	$ 10.8

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Inventories (Tables)

6 Months Ended

Mar. 31, 2015

Inventory Disclosure [Abstract]

Components of Inventories

Inventories comprise the following:

	March 31, 2015		September 30, 2014		March 31, 2014
Non-utility LPG and natural gas	$	135.8	$	283.6	$	251.4
Gas Utility natural gas	6.3		82.7		7.5
Materials, supplies and other	59.4		56.7		65.5
Total inventories	$	201.5	$	423.0	$	324.4

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Derivative Instruments and Hedging Activities - Fair Value of Derivative Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Derivative assets:
Derivative asset, gross	$ 67.8	$ 31.6	[1]
Derivative liabilities:
Derivative liability, gross	(180.8)	(65.3)	[1]
Designated as Hedging Instrument
Derivative assets:
Derivative asset, gross	45.6	11.0	[1]
Derivative liabilities:
Derivative liability, gross	(12.5)	(36.7)	[1]
Designated as Hedging Instrument | Commodity Contracts
Derivative assets:
Derivative asset, gross	0	10.9	[1]
Derivative liabilities:
Derivative liability, gross	0	(1.1)	[1]
Designated as Hedging Instrument | Foreign Currency Contracts
Derivative assets:
Derivative asset, gross	35.8	0.1	[1]
Derivative liabilities:
Derivative liability, gross	0	(5.6)	[1]
Designated as Hedging Instrument | Cross Currency Contracts
Derivative assets:
Derivative asset, gross	9.7	0	[1]
Derivative liabilities:
Derivative liability, gross	0	(2.2)	[1]
Designated as Hedging Instrument | Interest Rate Contracts
Derivative assets:
Derivative asset, gross	0.1	0	[1]
Derivative liabilities:
Derivative liability, gross	(12.5)	(27.8)	[1]
Derivatives Subject to Utility Rate Regulation | Commodity Contracts
Derivative assets:
Derivative asset, gross	0	3.5	[1]
Derivative liabilities:
Derivative liability, gross	(5.2)	(0.7)	[1]
Derivatives Not Designated as Hedging Instruments | Commodity Contracts
Derivative assets:
Derivative asset, gross	22.2	17.1	[1]
Derivative liabilities:
Derivative liability, gross	$ (163.1)	$ (27.9)	[1]

[1] Certain immaterial amounts have been revised to correct the classification of derivatives.

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Energy Services Accounts Receivable Securitization Facility (Details) (USD $)	6 Months Ended		5 Months Ended	7 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Oct. 31, 2015	May 31, 2015
Energy Services
Accounts, Notes, Loans and Financing Receivable
Sale of trade receivables	$ 692,000,000	$ 820,700,000
Energy Services Funding Corporation
Accounts, Notes, Loans and Financing Receivable
Sale of undivided interests in its trade receivables to the commercial paper conduit	216,500,000	251,000,000
Outstanding balance of trade receivables	96,900,000	124,100,000
Outstanding balance of trade receivables sold	0	10,500,000
Forecast | Maximum
Accounts, Notes, Loans and Financing Receivable
Receivables facility			$ 75,000,000	$ 150,000,000

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Inventories - Components of Inventories (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Sep. 30, 2014	Mar. 31, 2014
Inventory
Inventory, net	$ 201.5	$ 423.0	$ 324.4
Non-utility LPG and Natural Gas
Inventory
Inventory, net	135.8	283.6	251.4
Gas Utility Natural Gas
Inventory
Inventory, net	6.3	82.7	7.5
Materials, Supplies and Other
Inventory
Inventory, net	$ 59.4	$ 56.7	$ 65.5

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Derivative Instruments and Hedging Activities - Effects of Derivative Instruments on the Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments, Gain (Loss)
Document Period End Date			Mar. 31, 2015
Derivatives Not Designated as Hedging Instruments
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	$ (16.9)	$ (22.2)	$ (306.1)	$ (9.3)
Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI and Noncontrolling Interests	30.7	5.9	42.3	53.9
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	3.0	34.7	(0.6)	50.5
Commodity Contracts | Derivatives Not Designated as Hedging Instruments | Cost of Sales
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	(12.3)	(22.2)	(304.8)	(9.4)
Commodity Contracts | Derivatives Not Designated as Hedging Instruments | Revenues
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	(4.6)	0	(0.8)	0
Commodity Contracts | Derivatives Not Designated as Hedging Instruments | Operating Expenses / Other Operating Income, Net
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	0	0	(0.5)	0.1
Commodity Contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI and Noncontrolling Interests	0	7.8	0	61.2
Commodity Contracts | Cash Flow Hedges | Cost of Sales
Derivative Instruments, Gain (Loss)
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	0.1	39.9	(2.3)	62.2
Foreign Currency Contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI and Noncontrolling Interests	23.7	(0.2)	32.4	(2.7)
Foreign Currency Contracts | Cash Flow Hedges | Cost of Sales
Derivative Instruments, Gain (Loss)
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	6.5	(1.4)	9.2	(3.5)
Cross Currency Contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI and Noncontrolling Interests	5.4	0.1	7.5	(1.1)
Cross Currency Contracts | Cash Flow Hedges | Interest Expense
Derivative Instruments, Gain (Loss)
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	(0.1)	0.2	(0.1)	(0.1)
Interest Rate Contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI and Noncontrolling Interests	1.6	(1.8)	2.4	(3.5)
Interest Rate Contracts | Cash Flow Hedges | Interest Expense / Other Operating Income, Net
Derivative Instruments, Gain (Loss)
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	$ (3.5)	$ (4.0)	$ (7.4)	$ (8.1)

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Fair Value Disclosures [Abstract]
Carrying value of long-term debt	$ 3,428.7	$ 3,613.6
Estimated fair value of long-term debt	$ 3,664.2	$ 3,864.4

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Nature of Operations

6 Months Ended

Mar. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations

Note 1 — Nature of Operations

UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports 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, natural gas production and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”

We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”). 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”), which is 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 March 31, 2015, the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises 23,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises 69,131,947 Common Units held by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances as further described in Note 15 of our Annual Report on Form 10-K for the fiscal year ended September 30, 2014 (the “Company’s 2014 Annual Report”). Incentive distributions received by the General Partner during the six months ended March 31, 2015 and 2014 were $13.1 and $10.8, respectively.

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 and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business primarily in the Mid-Atlantic and Northeast U.S. 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 is 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 distribution utility business (“Gas Utility”) is 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.” 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. Electric Utility is subject to regulation by the PUC. Gas Utility and Electric Utility are collectively referred to as “Utilities.”

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Debt (Details)				0 Months Ended				0 Months Ended	55 Months Ended			0 Months Ended				5 Months Ended
	Mar. 31, 2015 USD ($)	Mar. 31, 2014 USD ($)	Mar. 27, 2015 UGI Utilities 2015 Credit Agreement USD ($)	Mar. 27, 2015 UGI Utilities 2015 Credit Agreement Minimum	Mar. 27, 2015 UGI Utilities 2015 Credit Agreement Maximum	Mar. 27, 2015 UGI Utilities 2015 Credit Agreement Letter of Credit USD ($)	Mar. 27, 2015 UGI Utilities 2011 Credit Agreement USD ($)	Apr. 30, 2015 UGI France 2015 Senior Facilities Agreement Subsequent Event	Apr. 30, 2020 UGI France 2015 Senior Facilities Agreement Subsequent Event Maximum	Apr. 30, 2015 UGI France 2015 Senior Facilities Agreement Term Loan Subsequent Event EUR (€)	Apr. 30, 2015 UGI France 2015 Senior Facilities Agreement Revolving Credit Facility Subsequent Event EUR (€)	Apr. 30, 2015 UGI France 2015 Senior Facilities Agreement Revolving Credit Facility Subsequent Event Minimum	Apr. 30, 2015 UGI France 2015 Senior Facilities Agreement Revolving Credit Facility Subsequent Event Maximum	Apr. 30, 2015 UGI France 2015 Senior Facilities Agreement Term Loan Borrowing [Member] Subsequent Event Minimum	Apr. 30, 2015 UGI France 2015 Senior Facilities Agreement Term Loan Borrowing [Member] Subsequent Event Maximum	Sep. 30, 2015 Forecast Antargaz 2011 Senior Facilities Agreement Subsequent Event EUR (€)	Mar. 31, 2015 Antargaz 2011 Senior Facilities Agreement USD ($)
Line of Credit Facility
Maximum borrowing capacity			$ 300,000,000			$ 100,000,000	$ 300,000,000
Basis spread on variable rate				0.00%	1.75%							1.45%	2.55%	1.60%	2.70%
Ratio of consolidated debt to consolidated capital					0.65
Long-term debt	3,428,700,000	3,613,600,000								600,000,000
Maximum borrowing capacity											60,000,000
Repayments of debt																342,000,000
Derivative Instruments and Hedges, Liabilities, Noncurrent																	10,300,000
Repayments of principal in 2018										60,000,000
Repayments of principal in 2019										60,000,000
Repayments of Principal in 2020										€ 480,000,000
Ratio of net debt to EBITDA								3.75	3.50

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Fair Value Measurement (Tables)

6 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Financial Assets and Financial Liabilities that are Measured at Fair Value on a Recurring Basis

The following table presents on a gross basis our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of March 31, 2015, September 30, 2014 and March 31, 2014:

	Asset (Liability)
	Level 1			Level 2			Level 3		Total
March 31, 2015:
Derivative instruments:
Assets:
Commodity contracts	$	13.9		$	8.3		$	—	$	22.2
Foreign currency contracts	$	—		$	35.8		$	—	$	35.8
Interest rate contracts	$	—		$	0.1		$	—	$	0.1
Cross-currency swaps	$	—		$	9.7		$	—	$	9.7
Liabilities:
Commodity contracts	$	(64.0	)	$	(104.3	)	$	—	$	(168.3	)
Interest rate contracts	$	—		$	(12.5	)	$	—	$	(12.5	)
Non-qualified supplemental postretirement grantor trust investments (a)	$	31.8		$	—		$	—	$	31.8
September 30, 2014:
Derivative instruments:
Assets:
Commodity contracts	$	10.6		$	19.8		$	—	$	30.4
Foreign currency contracts	$	—		$	12.8		$	—	$	12.8
Interest rate contracts	$	—		$	0.1		$	—	$	0.1
Cross-currency swaps	$	—		$	2.1		$	—	$	2.1
Liabilities:
Commodity contracts	$	(21.2	)	$	(32.9	)	$	—	$	(54.1	)
Foreign currency contracts	$	—		$	(0.1	)	$	—	$	(0.1	)
Interest rate contracts	$	—		$	(21.0	)	$	—	$	(21.0	)
Non-qualified supplemental postretirement grantor trust investments (a)	$	30.0		$	—		$	—	$	30.0
March 31, 2014 (b):
Derivative instruments:
Assets:
Commodity contracts	$	17.5		$	14.0		$	—	$	31.5
Foreign currency contracts	$	—		$	0.1		$	—	$	0.1
Liabilities:
Commodity contracts	$	(10.0	)	$	(19.7	)	$	—	$	(29.7	)
Foreign currency contracts	$	—		$	(5.6	)	$	—	$	(5.6	)
Interest rate contracts	$	—		$	(27.8	)	$	—	$	(27.8	)
Cross-currency swaps	$	—		$	(2.2	)	$	—	$	(2.2	)
Non-qualified supplemental postretirement grantor trust investments (a)	$	29.8		$	—		$	—	$	29.8

(a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.

(b) Certain immaterial amounts have been revised to correct the classification of derivatives.

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Defined Benefit Pension and Other Postretirement Plans (Tables)

6 Months Ended

Mar. 31, 2015

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

Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs

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

	Pension Benefits						Other Postretirement Benefits
Three Months Ended March 31,	2015			2014			2015			2014
Service cost	$	2.5		$	2.3		$	0.1		$	0.1
Interest cost	6.3			6.5			0.2			0.2
Expected return on assets	(8.0		)	(7.3		)	(0.1		)	(0.1		)
Amortization of:
Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.1		)
Actuarial loss	2.5			1.9			—			—
Net benefit cost	3.4			3.5			0.1			0.1
Change in associated regulatory liabilities	—			—			1.0			0.9
Net expense	$	3.4		$	3.5		$	1.1		$	1.0
	Pension Benefits						Other Postretirement Benefits
Six Months Ended March 31,	2015			2014			2015			2014
Service cost	$	4.9		$	4.7		$	0.3		$	0.3
Interest cost	12.6			12.9			0.4			0.5
Expected return on assets	(15.9		)	(14.7		)	(0.3		)	(0.3		)
Amortization of:
Prior service cost (benefit)	0.2			0.2			(0.2		)	(0.2		)
Actuarial loss	5.0			3.8			—			—
Net benefit cost	6.8			6.9			0.2			0.3
Change in associated regulatory liabilities	—			—			1.9			1.8
Net expense	$	6.8		$	6.9		$	2.1		$	2.1

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Segment Information Segment Information - Reconciliation of Partnership Adjusted EBITDA (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended
	Mar. 31, 2015		Mar. 31, 2014		Mar. 31, 2015		Mar. 31, 2014
Segment Reporting Information
Depreciation and amortization	$ 88.0		$ 87.7		$ 179.0		$ 181.7
Operating income	702.1		588.6		785.4		952.3
General Partnership interest in AmeriGas OLP (percentage)	1.01%		1.01%
Amerigas Propane
Segment Reporting Information
Partnership Adjusted EBITDA	342.1	[1]	331.2	[1]	530.6	[1]	561.5	[1]
Depreciation and amortization	48.1		49.2		97.5		101.5
Noncontrolling interests	2.9	[2]	2.8	[2]	3.5	[2]	4.5	[2]
Operating income	$ 296.9		$ 284.8		$ 436.6		$ 464.5

[1] The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income: Three Months EndedMarch 31, Six Months Ended March 31, 2015 2014 2015 2014Partnership Adjusted EBITDA $342.1 $331.2 $530.6 $561.5Depreciation and amortization (48.1) (49.2) (97.5) (101.5)Noncontrolling interests (i) 2.9 2.8 3.5 4.5Operating income $296.9 $284.8 $436.6 $464.5(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

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

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Mar. 31, 2015 lb	Oct. 31, 2014 lawsuit	Mar. 31, 2014
Commitments and Contingencies
Class action lawsuits (more than 35)		35
Amount of propane in cylinders before reduction	17
Amount of propane in cylinders after reduction	15
PNG MGP
Commitments and Contingencies
Loss contingency, settlement agreement, terms	2 years
Environmental Matters | CPG MGP
Commitments and Contingencies
Environmental expenditures cap during calendar year	1.8
Environmental Matters | PNG MGP
Commitments and Contingencies
Environmental expenditures cap during calendar year	1.1
Environmental Matters | UGI Utilities
Commitments and Contingencies
Base year for determination of investigation and remediation cost (in years)	5 years
CPG and PNG COAs | UGI Utilities
Commitments and Contingencies
Accrual for environmental loss contingencies	9.6		$ 11.1

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Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Balance Sheet Location and Fair Value of Derivative Assets and Liabilities

The following table presents the Company’s derivative assets and liabilities on a gross basis as of March 31, 2015 and 2014:

	March 31, 2015			March 31, 2014 (a)
Derivative assets:
Derivatives designated as hedging instruments:
Commodity contracts	$	—		$	10.9
Foreign currency contracts	35.8			0.1
Cross-currency contracts	9.7			—
Interest rate contracts	0.1			—
	45.6			11.0
Derivatives subject to utility rate regulation:
Commodity contracts	—			3.5
Derivatives not designated as hedging instruments:
Commodity contracts	22.2			17.1
Total derivative assets	$	67.8		$	31.6
Derivative liabilities:
Derivatives designated as hedging instruments:
Commodity contracts	$	—		$	(1.1	)
Foreign currency contracts	—			(5.6		)
Cross-currency contracts	—			(2.2		)
Interest rate contracts	(12.5		)	(27.8		)
	(12.5		)	(36.7		)
Derivatives subject to utility rate regulation:
Commodity contracts	(5.2		)	(0.7		)
Derivatives not designated as hedging instruments:
Commodity contracts	(163.1		)	(27.9		)
Total derivative liabilities	$	(180.8	)	$	(65.3	)

(a) Certain immaterial amounts have been revised to correct the classification of derivatives.

Derivative Assets and Liabilities and the Effects of Offsetting

The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of March 31, 2015 and 2014:

	Gross Amounts Recognized			Gross Amounts Offset in Balance Sheet			Net Amounts Recognized			Cash Collateral (Received) Pledged		Net Amounts Recognized in Balance Sheet
March 31, 2015
Derivative assets	$	67.8		$	(13.8	)	$	54.0		$	—	$	54.0
Derivative liabilities	$	(180.8	)	$	13.8		$	(167.0	)	$	3.7	$	(163.3	)
March 31, 2014
Derivative assets	$	31.6		$	(8.6	)	$	23.0		$	—	$	23.0
Derivative liabilities	$	(65.3	)	$	8.6		$	(56.7	)	$	—	$	(56.7	)

Effects of Derivative Instruments on the Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest

The following tables provide information on the effects of derivative instruments in the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three and six months ended March 31, 2015 and 2014:

	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 Interests into Income
Three Months Ended March 31,	2015			2014			2015			2014
Cash Flow Hedges:
Commodity contracts	$	—		$	7.8		$	0.1		$	39.9		Cost of sales
Foreign currency contracts	23.7			(0.2		)	6.5			(1.4		)	Cost of sales
Cross-currency contracts	5.4			0.1			(0.1		)	0.2			Interest expense
Interest rate contracts	1.6			(1.8		)	(3.5		)	(4.0		)	Interest expense
Total	$	30.7		$	5.9		$	3.0		$	34.7
	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Three Months Ended March 31,	2015			2014
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	(12.3	)	$	(22.2	)	Cost of sales
Commodity contracts	(4.6		)	—			Revenues
Commodity contracts	—			—			Operating expenses / other operating income, net
Total	$	(16.9	)	$	(22.2	)
	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 Interests into Income
Six Months Ended March 31,	2015			2014			2015			2014
Cash Flow Hedges:
Commodity contracts	$	—		$	61.2		$	(2.3	)	$	62.2		Cost of sales
Foreign currency contracts	32.4			(2.7		)	9.2			(3.5		)	Cost of sales
Cross-currency contracts	7.5			(1.1		)	(0.1		)	(0.1		)	Interest expense
Interest rate contracts	2.4			(3.5		)	(7.4		)	(8.1		)	Interest expense
Total	$	42.3		$	53.9		$	(0.6	)	$	50.5
	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Six Months Ended March 31,	2015			2014
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	(304.8	)	$	(9.4	)	Cost of sales
Commodity contracts	(0.8		)	—			Revenues
Commodity contracts	(0.5		)	0.1			Operating expenses / other operating income, net
Total	$	(306.1	)	$	(9.3	)

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Accumulated Other Comprehensive Income (Tables)

6 Months Ended

Mar. 31, 2015

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income

The tables below present changes in AOCI during the three and six months ended March 31, 2015 and 2014:

Three Months Ended March 31, 2015	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - December 31, 2014	$	(20.0	)	$	1.7		$	(21.8	)	$	(40.1	)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			20.2			(64.5		)	(44.3		)
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0.6			(3.0		)	—			(2.4		)
Reclassification adjustments tax expense	(0.2		)	1.1			—			0.9
Reclassification adjustments (after-tax)	0.4			(1.9		)	—			(1.5		)
Other comprehensive income (loss)	0.4			18.3			(64.5		)	(45.8		)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			0.5			—			0.5
Other comprehensive income (loss) attributable to UGI	0.4			18.8			(64.5		)	(45.3		)
AOCI - March 31, 2015	$	(19.6	)	$	20.5		$	(86.3	)	$	(85.4	)
Three Months Ended March 31, 2014	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - December 31, 2013	$	(16.0	)	$	(15.8	)	$	64.0		$	32.2
Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			6.3			(0.6		)	5.7
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0.3			(34.7		)	—			(34.4		)
Reclassification adjustments tax benefit	(0.1		)	3.3			—			3.2
Reclassification adjustments (after-tax)	0.2			(31.4		)	—			(31.2		)
Other comprehensive income (loss)	0.2			(25.1		)	(0.6		)	(25.5		)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			17.6			—			17.6
Other comprehensive income (loss) attributable to UGI	0.2			(7.5		)	(0.6		)	(7.9		)
AOCI - March 31, 2014	$	(15.8	)	$	(23.3	)	$	63.4		$	24.3

Six Months Ended March 31, 2015	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - September 30, 2014	$	(20.6	)	$	(9.3	)	$	8.7		$	(21.2	)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			27.9			(95.0		)	(67.1		)
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	1.6			0.6			—			2.2
Reclassification adjustments tax expense	(0.6		)	(0.4		)	—			(1.0		)
Reclassification adjustments (after-tax)	1.0			0.2			—			1.2
Other comprehensive income (loss)	1.0			28.1			(95.0		)	(65.9		)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			1.7			—			1.7
Other comprehensive income (loss) attributable to UGI	1.0			29.8			(95.0		)	(64.2		)
AOCI - March 31, 2015	$	(19.6	)	$	20.5		$	(86.3	)	$	(85.4	)
Six Months Ended March 31, 2014	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - September 30, 2013	$	(16.4	)	$	(26.9	)	$	51.7		$	8.4
Other comprehensive income before reclassification adjustments (after-tax)	—			46.8			11.7			58.5
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0.6			(50.5		)	—			(49.9		)
Reclassification adjustments tax benefit	—			5.3			—			5.3
Reclassification adjustments (after-tax)	0.6			(45.2		)	—			(44.6		)
Other comprehensive income	0.6			1.6			11.7			13.9
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			2.0			—			2.0
Other comprehensive income attributable to UGI	0.6			3.6			11.7			15.9
AOCI - March 31, 2014	$	(15.8	)	$	(23.3	)	$	63.4		$	24.3

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Condensed Consolidated Statements of Changes in Equity (unaudited) (USD $) In Millions, unless otherwise specified	Total	Parent	Common Stock, Without Par Value	Retained Earnings	Accumulated Other Comprehensive (Loss) Income	Treasury Stock	Noncontrolling Interests
Balance, beginning of period at Sep. 30, 2013			$ 1,208.1	$ 1,308.3	$ 8.4	$ (32.3)	$ 1,055.4
Increase (Decrease) in Stockholders' Equity
Common Stock issued in connection with employee and director plans (including (losses) gains on treasury stock transactions), net of tax withheld			(5.2)
Excess tax benefits realized on equity-based compensation			5.9
Equity-based compensation expense			6.8
Net income	605.3			336.4			268.9
Cash dividends on Common Stock				(64.8)
Net gains on derivative instruments, net of tax	46.8				13.5
Reclassification of net losses (gains) on derivative instruments, net of tax	(45.2)				(9.9)
Benefit plans, net of tax	0.6				0.6
Foreign currency, net of tax	11.7				11.7
Common stock issued in connection with employee and director plans, net of tax withheld						29.9
Repurchases of Common Stock						(4.5)
Reacquired common stock - employee and director plans						(17.7)
Net gains on derivative instruments							33.3
Reclassification of net gains on derivative instruments							(35.3)
Dividends and distributions							(116.1)
Other							0.7
Balance, end of period at Mar. 31, 2014	4,002.1	2,795.2	1,215.6	1,579.9	24.3	(24.6)	1,206.9
Balance, beginning of period at Sep. 30, 2014	3,663.2		1,215.6	1,509.4	(21.2)	(44.7)	1,004.1
Increase (Decrease) in Stockholders' Equity
Common Stock issued in connection with employee and director plans (including (losses) gains on treasury stock transactions), net of tax withheld			(15.1)
Excess tax benefits realized on equity-based compensation			5.0
Equity-based compensation expense			9.5
Net income	482.4			280.6			201.8
Cash dividends on Common Stock				(75.0)
Net gains on derivative instruments, net of tax	27.9				27.9
Reclassification of net losses (gains) on derivative instruments, net of tax	0.2				1.9
Benefit plans, net of tax	1.0				1.0
Foreign currency, net of tax	(95.0)				(95.0)
Common stock issued in connection with employee and director plans, net of tax withheld						24.7
Repurchases of Common Stock						(17.3)
Reacquired common stock - employee and director plans						(4.3)
Net gains on derivative instruments							0
Reclassification of net gains on derivative instruments							(1.7)
Dividends and distributions							(122.2)
Other							(1.3)
Balance, end of period at Mar. 31, 2015	$ 3,883.7	$ 2,803.0	$ 1,215.0	$ 1,715.0	$ (85.4)	$ (41.6)	$ 1,080.7

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Segment Information (Tables)

6 Months Ended

Mar. 31, 2015

Segment Reporting [Abstract]

Schedule of Segment Reporting Information

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Three Months Ended March 31, 2015
Revenues	$	2,455.6		$	(114.7	)	(c)	$	1,100.3		$	468.0		$	409.4		$	24.8	$	347.2		$	172.9		$	47.7
Cost of sales	$	1,205.4		$	(114.0	)	(c)	$	505.2		$	258.2		$	296.5		$	9.4	$	200.3		$	123.3		$	(73.5	)
Segment profit:
Operating income	$	702.1		$	0.1			$	296.9		$	139.3		$	93.9		$	8.0	$	53.2		$	11.5		$	99.2
Loss from equity investees	(0.1		)	—				—			—			—			—		(0.1		)	—			—
Interest expense	(58.2		)	—				(41.1		)	(10.1		)	(0.5		)	—		(4.9		)	(0.9		)	(0.7		)
Income before income taxes	$	643.8		$	0.1			$	255.8		$	129.2		$	93.4		$	8.0	$	48.2		$	10.6		$	98.5
Partnership Adjusted EBITDA (a)								$	342.1
Noncontrolling interests’ net income	$	235.7		$	—			$	88.3		$	—		$	—		$	—	$	0.3		$	—		$	147.1
Depreciation and amortization	$	88.0		$	(0.1	)		$	48.1		$	14.5		$	3.6		$	3.3	$	11.8		$	5.2		$	1.6
Capital expenditures	$	91.4		$	—			$	26.8		$	39.2		$	5.9		$	2.3	$	9.6		$	5.4		$	2.2

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Three Months Ended March 31, 2014
Revenues	$	3,163.3		$	(164.7	)	(c)	$	1,493.7		$	480.1		$	588.9		$	25.1	$	412.0		$	277.2		$	51.0
Cost of sales	$	2,001.3		$	(164.0	)	(c)	$	885.5		$	278.8		$	457.9		$	9.4	$	266.7		$	222.7		$	44.3
Segment profit:
Operating income (loss)	$	588.6		$	0.2			$	284.8		$	134.5		$	111.5		$	9.9	$	52.9		$	10.9		$	(16.1	)
Income from equity investees	—			—				—			—			—			—		—			—			—
Interest expense	(59.5		)	—				(42.0		)	(8.4		)	(1.0		)	—		(6.4		)	(1.1		)	(0.6		)
Income (loss) before income taxes	$	529.1		$	0.2			$	242.8		$	126.1		$	110.5		$	9.9	$	46.5		$	9.8		$	(16.7	)
Partnership Adjusted EBITDA (a)								$	331.2
Noncontrolling interests’ net income	$	173.4		$	—			$	173.2		$	—		$	—		$	—	$	0.2		$	—		$	—
Depreciation and amortization	$	87.7		$	(0.1	)		$	49.2		$	13.6		$	3.2		$	2.7	$	10.3		$	7.2		$	1.6
Capital expenditures	$	85.3		$	—			$	27.7		$	30.0		$	8.4		$	1.8	$	11.3		$	4.2		$	1.9

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Six Months Ended March 31, 2015
Revenues	$	4,460.2		$	(182.4	)	(c)	$	1,989.1		$	728.5		$	706.4		$	41.3	$	685.1		$	397.5		$	94.7
Cost of sales	$	2,610.0		$	(181.0	)	(c)	$	967.6		$	385.4		$	530.9		$	17.4	$	409.6		$	295.9		$	184.2
Segment profit:
Operating income (loss)	$	785.4		$	0.1			$	436.6		$	211.1		$	140.1		$	7.3	$	91.6		$	26.6		$	(128.0	)
Loss from equity investees	(1.1		)	—				—			—			—			—		(1.1		)	—			—
Interest expense	(117.2		)	—				(82.1		)	(20.2		)	(1.1		)	—		(10.5		)	(1.9		)	(1.4		)
Income (loss) before income taxes	$	667.1		$	0.1			$	354.5		$	190.9		$	139.0		$	7.3	$	80.0		$	24.7		$	(129.4	)
Partnership Adjusted EBITDA (a)								$	530.6
Noncontrolling interests’ net income	$	201.8		$	—			$	155.1		$	—		$	—		$	—	$	0.4		$	—		$	46.3
Depreciation and amortization	$	179.0		$	(0.1	)		$	97.5		$	28.8		$	7.2		$	6.0	$	25.1		$	11.3		$	3.2
Capital expenditures	$	214.9		$	—			$	57.2		$	92.7		$	18.7		$	8.9	$	21.7		$	11.8		$	3.9
As of March 31, 2015
Total assets	$	10,182.7		$	(109.5	)		$	4,423.8		$	2,359.1		$	690.8		$	281.2	$	1,569.2		$	539.7		$	428.4
Short-term borrowings	$	89.9		$	—			$	55.0		$	30.5		$	—		$	—	$	0.1		$	4.3		$	—
Goodwill	$	2,731.2		$	—			$	1,949.7		$	182.1		$	5.6		$	—	$	510.9		$	76.7		$	6.2

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Six Months Ended March 31, 2014
Revenues	$	5,479.2		$	(230.2	)	(c)	$	2,539.5		$	751.7		$	861.6		$	45.9	$	837.3		$	570.5		$	102.9
Cost of sales	$	3,431.2		$	(228.4	)	(c)	$	1,468.2		$	414.3		$	685.0		$	20.0	$	549.2		$	454.4		$	68.5
Segment profit:
Operating income (loss)	$	952.3		$	0.1			$	464.5		$	216.6		$	143.3		$	14.3	$	96.1		$	24.6		$	(7.2	)
Income from equity investees	—			—				—			—			—			—		—			—			—
Interest expense	(118.8		)	—				(83.6		)	(16.8		)	(2.0		)	—		(12.8		)	(2.4		)	(1.2		)
Income (loss) before income taxes	$	833.5		$	0.1			$	380.9		$	199.8		$	141.3		$	14.3	$	83.3		$	22.2		$	(8.4	)
Partnership EBITDA (a)								$	561.5
Noncontrolling interests’ net income	$	268.9		$	—			$	268.6		$	—		$	—		$	—	$	0.3		$	—		$	—
Depreciation and amortization	$	181.7		$	(0.1	)		$	101.5		$	27.0		$	5.8		$	5.3	$	25.3		$	13.8		$	3.1
Capital expenditures	$	188.1		$	(1.2	)		$	51.0		$	62.9		$	30.1		$	11.1	$	21.1		$	8.8		$	4.3
As of March 31, 2014
Total assets	$	10,720.5		$	(116.3	)		$	4,692.3		$	2,195.4		$	643.2		$	283.9	$	1,923.2		$	660.4		$	438.4
Short-term borrowings	$	260.1		$	—			$	198.0		$	6.5		$	51.5		$	—	$	—		$	4.1		$	—
Goodwill	$	2,886.0		$	—			$	1,939.0		$	182.1		$	2.8		$	—	$	655.3		$	99.8		$	7.0

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

	Three Months Ended March 31,						Six Months Ended March 31,
	2015			2014			2015			2014
Partnership Adjusted EBITDA	$	342.1		$	331.2		$	530.6		$	561.5
Depreciation and amortization	(48.1		)	(49.2		)	(97.5		)	(101.5		)
Noncontrolling interests (i)	2.9			2.8			3.5			4.5
Operating income	$	296.9		$	284.8		$	436.6		$	464.5

(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) net expenses of UGI’s captive general liability insurance company, and (4) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include net gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $102.2 and $(13.2) during the three months ended March 31, 2015 and 2014, respectively, and $(127.5) and $(6.0) during the six months ended March 31, 2015 and 2014, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and, in the three and six months ended March 31, 2014, an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.

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

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

	Three Months Ended March 31,						Six Months Ended March 31,
	2015			2014			2015			2014
Partnership Adjusted EBITDA	$	342.1		$	331.2		$	530.6		$	561.5
Depreciation and amortization	(48.1		)	(49.2		)	(97.5		)	(101.5		)
Noncontrolling interests (i)	2.9			2.8			3.5			4.5
Operating income	$	296.9		$	284.8		$	436.6		$	464.5

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

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Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Sep. 30, 2014	Mar. 31, 2014
Gas Utility
Regulatory Assets
Fair value of unrealized gains (losses)	$ (3.4)	$ (1.4)	$ 2.4
Electric Utility Electric Supply Contracts
Regulatory Assets
Fair value of unrealized gains (losses)	$ (1.2)	$ 0.3	$ 0.4

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Accumulated Other Comprehensive Income - Schedule of Accumulated Other Comprehensive Income (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015	Mar. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax
AOCI - balance at beginning of period	$ (40.1)	$ 32.2	$ (21.2)	$ 8.4
Other comprehensive income (loss) before reclassification adjustments (after-tax)	(44.3)	5.7	(67.1)	58.5
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	(2.4)	(34.4)	2.2	(49.9)
Reclassification adjustments tax benefit	0.9	3.2	(1.0)	5.3
Reclassification adjustments (after-tax)	(1.5)	(31.2)	1.2	(44.6)
Other comprehensive (loss) income	(45.8)	(25.5)	(65.9)	13.9
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	0.5	17.6	1.7	2.0
Other comprehensive income (loss) attributable to UGI	(45.3)	(7.9)	(64.2)	15.9
AOCI - balance at end of period	(85.4)	24.3	(85.4)	24.3
Postretirement Benefit Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax
AOCI - balance at beginning of period	(20.0)	(16.0)	(20.6)	(16.4)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	0	0	0	0
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0.6	0.3	1.6	0.6
Reclassification adjustments tax benefit	(0.2)	(0.1)	(0.6)	0
Reclassification adjustments (after-tax)	0.4	0.2	1.0	0.6
Other comprehensive (loss) income	0.4	0.2	1.0	0.6
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	0	0	0	0
Other comprehensive income (loss) attributable to UGI	0.4	0.2	1.0	0.6
AOCI - balance at end of period	(19.6)	(15.8)	(19.6)	(15.8)
Derivative Instruments
Accumulated Other Comprehensive Income (Loss), Net of Tax
AOCI - balance at beginning of period	1.7	(15.8)	(9.3)	(26.9)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	20.2	6.3	27.9	46.8
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	(3.0)	(34.7)	0.6	(50.5)
Reclassification adjustments tax benefit	1.1	3.3	(0.4)	5.3
Reclassification adjustments (after-tax)	(1.9)	(31.4)	0.2	(45.2)
Other comprehensive (loss) income	18.3	(25.1)	28.1	1.6
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	0.5	17.6	1.7	2.0
Other comprehensive income (loss) attributable to UGI	18.8	(7.5)	29.8	3.6
AOCI - balance at end of period	20.5	(23.3)	20.5	(23.3)
Foreign Currency
Accumulated Other Comprehensive Income (Loss), Net of Tax
AOCI - balance at beginning of period	(21.8)	64.0	8.7	51.7
Other comprehensive income (loss) before reclassification adjustments (after-tax)	(64.5)	(0.6)	(95.0)	11.7
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0	0	0	0
Reclassification adjustments tax benefit	0	0	0	0
Reclassification adjustments (after-tax)	0	0	0	0
Other comprehensive (loss) income	(64.5)	(0.6)	(95.0)	11.7
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	0	0	0	0
Other comprehensive income (loss) attributable to UGI	(64.5)	(0.6)	(95.0)	11.7
AOCI - balance at end of period	$ (86.3)	$ 63.4	$ (86.3)	$ 63.4

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Condensed Consolidated Balance Sheets (unaudited) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Sep. 30, 2014	Mar. 31, 2014
Current assets:
Cash and cash equivalents	$ 445.5	$ 419.5	$ 493.6
Restricted cash	56.7	16.6	4.4
Accounts receivable (less allowances for doubtful accounts of $42.7, $39.1 and $57.9, respectively)	1,046.0	684.7	1,323.3
Accrued utility revenues	42.1	14.3	49.7
Inventories	201.5	423.0	324.4
Deferred income taxes	49.6	10.1	10.8
Utility regulatory assets	0.6	13.2	4.2
Derivative instruments	33.1	14.5	22.2
Prepaid expenses and other current assets	83.9	67.1	48.5
Total current assets	1,959.0	1,663.0	2,281.1
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,691.0, $2,633.0 and $2,637.8, respectively)	4,486.3	4,543.7	4,519.1
Goodwill	2,731.2	2,833.4	2,886.0
Intangible assets, net	537.5	576.4	608.2
Derivative instruments	20.9	12.5	0.8
Other assets	447.8	464.0	425.3
Total assets	10,182.7	10,093.0	10,720.5
Current liabilities:
Current maturities of long-term debt	470.5	77.2	65.0
Short-term borrowings	89.9	210.8	260.1
Accounts payable	440.8	459.8	634.1
Derivative instruments	129.0	40.2	27.5
Other current liabilities	719.5	642.9	668.6
Total current liabilities	1,849.7	1,430.9	1,655.3
Long-term debt	2,958.2	3,433.6	3,548.6
Deferred income taxes	942.0	1,005.1	984.4
Deferred investment tax credits	3.8	3.9	4.1
Derivative instruments	34.3	16.6	29.2
Other noncurrent liabilities	511.0	539.7	496.8
Total liabilities	6,299.0	6,429.8	6,718.4
Commitments and contingencies (Note 9)
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized—450,000,000 shares; issued—173,788,741, 173,770,641 and 173,729,541 shares, respectively)	1,215.0	1,215.6	1,215.6
Retained earnings	1,715.0	1,509.4	1,579.9
Accumulated other comprehensive (loss) income	(85.4)	(21.2)	24.3
Treasury stock, at cost	(41.6)	(44.7)	(24.6)
Total UGI Corporation stockholders’ equity	2,803.0	2,659.1	2,795.2
Noncontrolling interests, principally in AmeriGas Partners	1,080.7	1,004.1	1,206.9
Total equity	3,883.7	3,663.2	4,002.1
Total liabilities and equity	$ 10,182.7	$ 10,093.0	$ 10,720.5

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Defined Benefit Pension and Other Postretirement Plans (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015	Mar. 31, 2014
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Contribution made to Pension Plan			$ 5.6	$ 7.0
Expected contribution to pensions plans during remainder of fiscal year			5.6
Net cost to sponsor unfunded and non-qualified supplemental executive retirement plans	$ 0.6	$ 0.9	$ 1.3	$ 1.7

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Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015	Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
Tax on (loss) gain on derivative instruments	$ (10.4)	$ 0.4	$ (14.3)	$ (7.1)
Tax on reclassification on derivative instruments	1.1	3.3	(0.4)	5.3
Tax on foreign currency adjustments	35.0	0.6	50.6	(3.1)
Tax on benefit plans	$ (0.2)	$ (0.1)	$ (0.6)	$ 0

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Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015	Mar. 31, 2014
Denominator (thousands of shares):
Average common shares outstanding for basic computation	173,154	172,760	173,055	172,494
Incremental shares issuable for stock options and awards	2,474	2,361	2,660	2,295
Average common shares outstanding for diluted computation	175,628	175,121	175,715	174,789

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Segment Information

6 Months Ended

Mar. 31, 2015

Segment Reporting [Abstract]

Segment Information

Note 14 — 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, “Summary of Significant Accounting Policies,” in the Company’s 2014 Annual Report. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization as adjusted for net gains and losses on commodity derivative instruments not associated with current-period transactions (“Partnership Adjusted EBITDA”). Although we use Partnership Adjusted 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 Adjusted 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 as adjusted for gains and losses on commodity derivative instruments not associated with current-period transactions. Net gains and losses on commodity derivative instruments not associated with current-period transactions are reflected in Corporate & Other because the Company’s chief operating decision maker does not consider such items when evaluating the financial performance of our reportable segments.

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Three Months Ended March 31, 2015
Revenues	$	2,455.6		$	(114.7	)	(c)	$	1,100.3		$	468.0		$	409.4		$	24.8	$	347.2		$	172.9		$	47.7
Cost of sales	$	1,205.4		$	(114.0	)	(c)	$	505.2		$	258.2		$	296.5		$	9.4	$	200.3		$	123.3		$	(73.5	)
Segment profit:
Operating income	$	702.1		$	0.1			$	296.9		$	139.3		$	93.9		$	8.0	$	53.2		$	11.5		$	99.2
Loss from equity investees	(0.1		)	—				—			—			—			—		(0.1		)	—			—
Interest expense	(58.2		)	—				(41.1		)	(10.1		)	(0.5		)	—		(4.9		)	(0.9		)	(0.7		)
Income before income taxes	$	643.8		$	0.1			$	255.8		$	129.2		$	93.4		$	8.0	$	48.2		$	10.6		$	98.5
Partnership Adjusted EBITDA (a)								$	342.1
Noncontrolling interests’ net income	$	235.7		$	—			$	88.3		$	—		$	—		$	—	$	0.3		$	—		$	147.1
Depreciation and amortization	$	88.0		$	(0.1	)		$	48.1		$	14.5		$	3.6		$	3.3	$	11.8		$	5.2		$	1.6
Capital expenditures	$	91.4		$	—			$	26.8		$	39.2		$	5.9		$	2.3	$	9.6		$	5.4		$	2.2

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Three Months Ended March 31, 2014
Revenues	$	3,163.3		$	(164.7	)	(c)	$	1,493.7		$	480.1		$	588.9		$	25.1	$	412.0		$	277.2		$	51.0
Cost of sales	$	2,001.3		$	(164.0	)	(c)	$	885.5		$	278.8		$	457.9		$	9.4	$	266.7		$	222.7		$	44.3
Segment profit:
Operating income (loss)	$	588.6		$	0.2			$	284.8		$	134.5		$	111.5		$	9.9	$	52.9		$	10.9		$	(16.1	)
Income from equity investees	—			—				—			—			—			—		—			—			—
Interest expense	(59.5		)	—				(42.0		)	(8.4		)	(1.0		)	—		(6.4		)	(1.1		)	(0.6		)
Income (loss) before income taxes	$	529.1		$	0.2			$	242.8		$	126.1		$	110.5		$	9.9	$	46.5		$	9.8		$	(16.7	)
Partnership Adjusted EBITDA (a)								$	331.2
Noncontrolling interests’ net income	$	173.4		$	—			$	173.2		$	—		$	—		$	—	$	0.2		$	—		$	—
Depreciation and amortization	$	87.7		$	(0.1	)		$	49.2		$	13.6		$	3.2		$	2.7	$	10.3		$	7.2		$	1.6
Capital expenditures	$	85.3		$	—			$	27.7		$	30.0		$	8.4		$	1.8	$	11.3		$	4.2		$	1.9

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Six Months Ended March 31, 2015
Revenues	$	4,460.2		$	(182.4	)	(c)	$	1,989.1		$	728.5		$	706.4		$	41.3	$	685.1		$	397.5		$	94.7
Cost of sales	$	2,610.0		$	(181.0	)	(c)	$	967.6		$	385.4		$	530.9		$	17.4	$	409.6		$	295.9		$	184.2
Segment profit:
Operating income (loss)	$	785.4		$	0.1			$	436.6		$	211.1		$	140.1		$	7.3	$	91.6		$	26.6		$	(128.0	)
Loss from equity investees	(1.1		)	—				—			—			—			—		(1.1		)	—			—
Interest expense	(117.2		)	—				(82.1		)	(20.2		)	(1.1		)	—		(10.5		)	(1.9		)	(1.4		)
Income (loss) before income taxes	$	667.1		$	0.1			$	354.5		$	190.9		$	139.0		$	7.3	$	80.0		$	24.7		$	(129.4	)
Partnership Adjusted EBITDA (a)								$	530.6
Noncontrolling interests’ net income	$	201.8		$	—			$	155.1		$	—		$	—		$	—	$	0.4		$	—		$	46.3
Depreciation and amortization	$	179.0		$	(0.1	)		$	97.5		$	28.8		$	7.2		$	6.0	$	25.1		$	11.3		$	3.2
Capital expenditures	$	214.9		$	—			$	57.2		$	92.7		$	18.7		$	8.9	$	21.7		$	11.8		$	3.9
As of March 31, 2015
Total assets	$	10,182.7		$	(109.5	)		$	4,423.8		$	2,359.1		$	690.8		$	281.2	$	1,569.2		$	539.7		$	428.4
Short-term borrowings	$	89.9		$	—			$	55.0		$	30.5		$	—		$	—	$	0.1		$	4.3		$	—
Goodwill	$	2,731.2		$	—			$	1,949.7		$	182.1		$	5.6		$	—	$	510.9		$	76.7		$	6.2

														Midstream & Marketing					UGI International
	Total			Elim- inations				AmeriGas Propane			Gas Utility			Energy Services			Electric Generation		Antargaz			Flaga & Other			Corporate & Other (b)
Six Months Ended March 31, 2014
Revenues	$	5,479.2		$	(230.2	)	(c)	$	2,539.5		$	751.7		$	861.6		$	45.9	$	837.3		$	570.5		$	102.9
Cost of sales	$	3,431.2		$	(228.4	)	(c)	$	1,468.2		$	414.3		$	685.0		$	20.0	$	549.2		$	454.4		$	68.5
Segment profit:
Operating income (loss)	$	952.3		$	0.1			$	464.5		$	216.6		$	143.3		$	14.3	$	96.1		$	24.6		$	(7.2	)
Income from equity investees	—			—				—			—			—			—		—			—			—
Interest expense	(118.8		)	—				(83.6		)	(16.8		)	(2.0		)	—		(12.8		)	(2.4		)	(1.2		)
Income (loss) before income taxes	$	833.5		$	0.1			$	380.9		$	199.8		$	141.3		$	14.3	$	83.3		$	22.2		$	(8.4	)
Partnership EBITDA (a)								$	561.5
Noncontrolling interests’ net income	$	268.9		$	—			$	268.6		$	—		$	—		$	—	$	0.3		$	—		$	—
Depreciation and amortization	$	181.7		$	(0.1	)		$	101.5		$	27.0		$	5.8		$	5.3	$	25.3		$	13.8		$	3.1
Capital expenditures	$	188.1		$	(1.2	)		$	51.0		$	62.9		$	30.1		$	11.1	$	21.1		$	8.8		$	4.3
As of March 31, 2014
Total assets	$	10,720.5		$	(116.3	)		$	4,692.3		$	2,195.4		$	643.2		$	283.9	$	1,923.2		$	660.4		$	438.4
Short-term borrowings	$	260.1		$	—			$	198.0		$	6.5		$	51.5		$	—	$	—		$	4.1		$	—
Goodwill	$	2,886.0		$	—			$	1,939.0		$	182.1		$	2.8		$	—	$	655.3		$	99.8		$	7.0

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

	Three Months Ended March 31,						Six Months Ended March 31,
	2015			2014			2015			2014
Partnership Adjusted EBITDA	$	342.1		$	331.2		$	530.6		$	561.5
Depreciation and amortization	(48.1		)	(49.2		)	(97.5		)	(101.5		)
Noncontrolling interests (i)	2.9			2.8			3.5			4.5
Operating income	$	296.9		$	284.8		$	436.6		$	464.5

(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) net expenses of UGI’s captive general liability insurance company, and (4) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include net gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $102.2 and $(13.2) during the three months ended March 31, 2015 and 2014, respectively, and $(127.5) and $(6.0) during the six months ended March 31, 2015 and 2014, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and, in the three and six months ended March 31, 2014, an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.

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

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Inventories (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Mar. 31, 2015 Bcf Storage_Agreement	Sep. 30, 2014 Bcf	Mar. 31, 2014 Bcf
Inventory Disclosure [Abstract]
Number of storage agreements	3
SCAA contract term (in years)	3 years
Volume of gas storage inventories released under SCAAs with non-affiliates (in cubic feet)	0.2	3.9	0.2
Carrying value of gas storage inventories released under SCAAs with non-affiliates	$ 0.7	$ 16.8	$ 0.8

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Mar. 31, 2015

Accounting Policies [Abstract]

Shares Used in Computing Basic and Diluted Earnings Per Share

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

	Three Months Ended March 31,		Six Months Ended March 31,
	2015	2014	2015	2014
Denominator (thousands of shares):
Average common shares outstanding for basic computation	173,154	172,760	173,055	172,494
Incremental shares issuable for stock options and awards	2,474	2,361	2,660	2,295
Average common shares outstanding for diluted computation	175,628	175,121	175,715	174,789

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Condensed Consolidated Statements of Cash Flows (unaudited) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 482.4	$ 605.3
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	179.0	181.7
Deferred income tax (benefit) expense, net	(33.7)	13.0
Provision for uncollectible accounts	20.7	31.4
Unrealized losses on derivative instruments	125.2	8.0
Other, net	7.0	(6.8)
Net change in:
Accounts receivable and accrued utility revenues	(469.7)	(632.5)
Inventories	208.0	43.0
Utility deferred fuel and power costs, net of changes in unsettled derivatives	55.8	(10.2)
Accounts payable	31.8	194.1
Other current assets	(8.3)	3.6
Other current liabilities	59.6	52.4
Net cash provided by operating activities	657.8	483.0
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(233.5)	(224.4)
Acquisitions of businesses, net of cash acquired	(7.3)	(21.3)
(Increase) decrease in restricted cash	(40.1)	3.9
Other, net	15.1	4.5
Net cash used by investing activities	(265.8)	(237.3)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(75.0)	(64.8)
Distributions on AmeriGas Partners publicly held Common Units	(121.7)	(116.1)
Issuances of debt	0	175.1
Repayments of debt	(6.9)	(182.8)
(Decrease) increase in short-term borrowings	(112.2)	51.5
Receivables Facility net repayments	(7.5)	(19.5)
Issuances of UGI Common Stock	5.0	10.3
Repurchases of UGI Common Stock	(17.3)	(4.5)
Other	(2.3)	5.4
Net cash used by financing activities	(337.9)	(145.4)
EFFECT OF EXCHANGE RATE CHANGES ON CASH	(28.1)	4.0
Cash and cash equivalents increase	26.0	104.3
Cash and cash equivalents:
End of period	445.5	493.6
Beginning of period	$ 419.5	$ 389.3

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Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2015	Sep. 30, 2014	Mar. 31, 2014
Statement of Financial Position [Abstract]
Accounts receivable, allowances for doubtful accounts	$ 42.7	$ 39.1	$ 57.9
Property, plant and equipment, accumulated depreciation and amortization	$ 2,691.0	$ 2,633.0	$ 2,637.8
UGI Common Stock, without par value (in shares)
UGI Common Stock, without par value, shares authorized (in shares)	450,000,000	450,000,000	450,000,000
UGI Common Stock, without par value, shares issued (in shares)	173,788,741	173,770,641	173,729,541

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Commitments and Contingencies

6 Months Ended

Mar. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 9 — 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 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 March 31, 2015 and 2014, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $9.6 and $11.1, respectively. We have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable.

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

UGI Utilities does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At March 31, 2015, 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 UGI Utilities 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.

Other Matters

Purported Class Action Lawsuits.  Between May and October of 2014, more than 35 purported class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI Corporation and a competitor by certain of their direct and indirect customers.  The class action lawsuits allege, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce the fill level of portable propane cylinders from 17 pounds to 15 pounds and combined to persuade its common customer, Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in violation of federal and certain state antitrust laws.  The claims seek treble damages, injunctive relief, attorneys’ fees and costs on behalf of the putative classes.  On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to the Western Division of the Western District of Missouri.  We are unable to reasonably estimate the impact, if any, arising from such litigation.  We believe we have strong defenses to the claims and intend to vigorously defend against them.

In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our consolidated financial position, results of operations or cash flows.

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Document and Entity Information	6 Months Ended
	Mar. 31, 2015	Apr. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	UGI CORP /PA/
Entity Central Index Key	0000884614
Document Type	10-Q
Document Period End Date	Mar. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--09-30
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		172,497,596

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Defined Benefit Pension and Other Postretirement Plans

6 Months Ended

Mar. 31, 2015

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

Defined Benefit Pension and Other Postretirement Plans

Note 10 — Defined Benefit Pension and Other Postretirement Plans

In the U.S., we sponsor a 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 (“U.S. Pension Plan”). We also provide postretirement health care benefits to certain retirees and active employees and postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, Antargaz employees are covered by certain defined benefit pension and postretirement plans.

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

	Pension Benefits						Other Postretirement Benefits
Three Months Ended March 31,	2015			2014			2015			2014
Service cost	$	2.5		$	2.3		$	0.1		$	0.1
Interest cost	6.3			6.5			0.2			0.2
Expected return on assets	(8.0		)	(7.3		)	(0.1		)	(0.1		)
Amortization of:
Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.1		)
Actuarial loss	2.5			1.9			—			—
Net benefit cost	3.4			3.5			0.1			0.1
Change in associated regulatory liabilities	—			—			1.0			0.9
Net expense	$	3.4		$	3.5		$	1.1		$	1.0
	Pension Benefits						Other Postretirement Benefits
Six Months Ended March 31,	2015			2014			2015			2014
Service cost	$	4.9		$	4.7		$	0.3		$	0.3
Interest cost	12.6			12.9			0.4			0.5
Expected return on assets	(15.9		)	(14.7		)	(0.3		)	(0.3		)
Amortization of:
Prior service cost (benefit)	0.2			0.2			(0.2		)	(0.2		)
Actuarial loss	5.0			3.8			—			—
Net benefit cost	6.8			6.9			0.2			0.3
Change in associated regulatory liabilities	—			—			1.9			1.8
Net expense	$	6.8		$	6.9		$	2.1		$	2.1

The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. During the six months ended March 31, 2015 and 2014, the Company made cash contributions to the U.S. Pension Plan of $5.6 and $7.0, respectively. The Company expects to make additional discretionary cash contributions of approximately $5.6 to the U.S. Pension Plan during the remainder of Fiscal 2015.

UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the six months ended March 31, 2015 and 2014.

We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans (“Supplemental Defined Benefit Plans”). We recorded pre-tax expense associated with these plans of $0.6 and $0.9 in the three months ended March 31, 2015 and 2014, respectively. We recorded pre-tax expense associated with these plans of $1.3 and $1.7 in the six months ended March 31, 2015 and 2014, respectively.

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Condensed Consolidated Statements of Income (unaudited) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015	Mar. 31, 2014
Income Statement [Abstract]
Revenues	$ 2,455.6	$ 3,163.3	$ 4,460.2	$ 5,479.2
Costs and expenses:
Cost of sales (excluding depreciation shown below)	1,205.4	2,001.3	2,610.0	3,431.2
Operating and administrative expenses	466.6	492.0	902.3	923.5
Utility taxes other than income taxes	4.8	4.8	8.9	9.0
Depreciation	73.8	76.8	149.6	155.4
Amortization	14.2	10.9	29.4	26.3
Other operating income, net	(11.3)	(11.1)	(25.4)	(18.5)
Total costs and expenses	1,753.5	2,574.7	3,674.8	4,526.9
Operating income	702.1	588.6	785.4	952.3
Loss from equity investees	(0.1)	0	(1.1)	0
Interest expense	(58.2)	(59.5)	(117.2)	(118.8)
Income before income taxes	643.8	529.1	667.1	833.5
Income tax expense	(161.6)	(141.3)	(184.7)	(228.2)
Net income	482.2	387.8	482.4	605.3
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners	(235.7)	(173.4)	(201.8)	(268.9)
Net income attributable to UGI Corporation	$ 246.5	$ 214.4	$ 280.6	$ 336.4
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)	$ 1.42	$ 1.24	$ 1.62	$ 1.95
Diluted (in dollars per share)	$ 1.40	$ 1.22	$ 1.60	$ 1.92
Average common shares outstanding (thousands):
Basic (in shares)	173,154	172,760	173,055	172,494
Diluted (in shares)	175,628	175,121	175,715	174,789
Dividends declared per common share (in dollars per share)	$ 0.2175	$ 0.1883	$ 0.4350	$ 0.3767

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Inventories

6 Months Ended

Mar. 31, 2015

Inventory Disclosure [Abstract]

Inventories

Note 4 — Inventories

Inventories comprise the following:

	March 31, 2015		September 30, 2014		March 31, 2014
Non-utility LPG and natural gas	$	135.8	$	283.6	$	251.4
Gas Utility natural gas	6.3		82.7		7.5
Materials, supplies and other	59.4		56.7		65.5
Total inventories	$	201.5	$	423.0	$	324.4

At March 31, 2015, UGI Utilities is a party to three principal storage contract administrative agreements (“SCAAs”) having terms of 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 terms 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 for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above.

As of March 31, 2015, UGI Utilities has SCAAs with Energy Services and a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with non-affiliates at March 31, 2015, September 30, 2014 and March 31, 2014, comprising 0.2 billion cubic feet (“bcf”), 3.9 bcf and 0.2 bcf of natural gas, was $0.7, $16.8 and $0.8, respectively.

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Accounting Changes

6 Months Ended

Mar. 31, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Changes

Note 3 — Accounting Changes

Accounting Standards Not Yet Adopted

Consolidation.In February 2015, the Financial Accounting Standards Board (“FASB”) issued new guidance regarding whether a reporting entity should consolidate certain types of legal entities. Among other things, the new guidance modifies the evaluation of whether limited partnerships and similar entities are variable interest entities (“VIEs”) or voting interest entities, and also eliminates the presumption that a general partner should consolidate a limited partnership. The new guidance also affects the consolidation analysis of reporting entities that are involved with VIEs including those that have fee arrangements and related party relationships. The new guidance is effective for the Company beginning in Fiscal 2017. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements, if any, from the adoption of the new guidance.

Debt Issuance Costs. In April 2015, the FASB issued Accounting Standards Update (“ASU”) No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Entities would apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2015.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This standard is effective for the Company for interim and annual periods beginning October 1, 2017 (Fiscal 2018) and allows for either full retrospective adoption or modified retrospective adoption. On April 29, 2015, the FASB issued for public comment a proposal to delay the effective date by one year. The Company is in the process of assessing the impact of the adoption of ASU 2014-09 on its results of operations, cash flows and financial position.

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Mar. 31, 2015

Accounting Policies [Abstract]

Earnings Per Common Share

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

Derivatives Instruments

Derivative Instruments. Derivative instruments are reported in the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.

Certain of our derivative instruments are designated and qualify as cash flow hedges or net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on certain commodity derivative instruments used by Gas Utility and Electric Utility are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers.

Effective October 1, 2014, UGI International determined that on a prospective basis it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Midstream & Marketing has not applied cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Substantially all realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues. For additional information on our derivative instruments, see Note 12.

Use of Estimates

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

Accounting Standards Not Yet Adopted

Accounting Standards Not Yet Adopted

Consolidation.In February 2015, the Financial Accounting Standards Board (“FASB”) issued new guidance regarding whether a reporting entity should consolidate certain types of legal entities. Among other things, the new guidance modifies the evaluation of whether limited partnerships and similar entities are variable interest entities (“VIEs”) or voting interest entities, and also eliminates the presumption that a general partner should consolidate a limited partnership. The new guidance also affects the consolidation analysis of reporting entities that are involved with VIEs including those that have fee arrangements and related party relationships. The new guidance is effective for the Company beginning in Fiscal 2017. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements, if any, from the adoption of the new guidance.

Debt Issuance Costs. In April 2015, the FASB issued Accounting Standards Update (“ASU”) No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs." This ASU amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2015. Early adoption is permitted. Entities would apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance in the fourth quarter of Fiscal 2015.

Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This standard is effective for the Company for interim and annual periods beginning October 1, 2017 (Fiscal 2018) and allows for either full retrospective adoption or modified retrospective adoption. On April 29, 2015, the FASB issued for public comment a proposal to delay the effective date by one year. The Company is in the process of assessing the impact of the adoption of ASU 2014-09 on its results of operations, cash flows and financial position.

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Fair Value Measurements

6 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 11 — Fair Value Measurements

Recurring Fair Value Measurements

The following table presents on a gross basis our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of March 31, 2015, September 30, 2014 and March 31, 2014:

	Asset (Liability)
	Level 1			Level 2			Level 3		Total
March 31, 2015:
Derivative instruments:
Assets:
Commodity contracts	$	13.9		$	8.3		$	—	$	22.2
Foreign currency contracts	$	—		$	35.8		$	—	$	35.8
Interest rate contracts	$	—		$	0.1		$	—	$	0.1
Cross-currency swaps	$	—		$	9.7		$	—	$	9.7
Liabilities:
Commodity contracts	$	(64.0	)	$	(104.3	)	$	—	$	(168.3	)
Interest rate contracts	$	—		$	(12.5	)	$	—	$	(12.5	)
Non-qualified supplemental postretirement grantor trust investments (a)	$	31.8		$	—		$	—	$	31.8
September 30, 2014:
Derivative instruments:
Assets:
Commodity contracts	$	10.6		$	19.8		$	—	$	30.4
Foreign currency contracts	$	—		$	12.8		$	—	$	12.8
Interest rate contracts	$	—		$	0.1		$	—	$	0.1
Cross-currency swaps	$	—		$	2.1		$	—	$	2.1
Liabilities:
Commodity contracts	$	(21.2	)	$	(32.9	)	$	—	$	(54.1	)
Foreign currency contracts	$	—		$	(0.1	)	$	—	$	(0.1	)
Interest rate contracts	$	—		$	(21.0	)	$	—	$	(21.0	)
Non-qualified supplemental postretirement grantor trust investments (a)	$	30.0		$	—		$	—	$	30.0
March 31, 2014 (b):
Derivative instruments:
Assets:
Commodity contracts	$	17.5		$	14.0		$	—	$	31.5
Foreign currency contracts	$	—		$	0.1		$	—	$	0.1
Liabilities:
Commodity contracts	$	(10.0	)	$	(19.7	)	$	—	$	(29.7	)
Foreign currency contracts	$	—		$	(5.6	)	$	—	$	(5.6	)
Interest rate contracts	$	—		$	(27.8	)	$	—	$	(27.8	)
Cross-currency swaps	$	—		$	(2.2	)	$	—	$	(2.2	)
Non-qualified supplemental postretirement grantor trust investments (a)	$	29.8		$	—		$	—	$	29.8

(a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.

(b) Certain immaterial amounts have been revised to correct the classification of derivatives.

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 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. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. 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 March 31, 2015, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,428.7 and $3,664.2, respectively. At March 31, 2014, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,613.6 and $3,864.4, 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 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 arising from concentrations of trade accounts receivable is limited because we have a large customer base which extends across many different U.S. markets and a number of foreign countries. For information regarding concentrations of credit risk associated with our derivative instruments, see Note 12. 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.

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Energy Services Accounts Receivable Securitization Facility

6 Months Ended

Mar. 31, 2015

Transfers and Servicing of Financial Assets [Abstract]

Energy Services Accounts Receivable Securitization Facility

Note 7 — Energy Services Accounts Receivable Securitization Facility

Energy Services has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2015. The Receivables Facility provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November to May and up to $75 of eligible receivables during the period June to October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.

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. 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 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 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 six months ended March 31, 2015 and 2014, Energy Services transferred trade receivables to ESFC totaling $692.0 and $820.7, respectively. During the six months ended March 31, 2015 and 2014, ESFC sold an aggregate $216.5 and $251.0, respectively, of undivided interests in its trade receivables to the bank. At March 31, 2015, the outstanding balance of ESFC receivables was $96.9 and there were no amounts sold to the bank. At March 31, 2014, the outstanding balance of ESFC receivables was $124.1 of which $10.5 was sold to the bank. Losses on sales of receivables to the bank during the six months ended March 31, 2015 and 2014, which are included in interest expense on the Condensed Consolidated Statements of Income, were not material.

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Goodwill and Intangible Assets

6 Months Ended

Mar. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets

Note 5 — Goodwill and Intangible Assets

Goodwill and intangible assets comprise the following:

	March 31, 2015			September 30, 2014			March 31, 2014
Goodwill (not subject to amortization)	$	2,731.2		$	2,833.4		$	2,886.0
Intangible assets:
Customer relationships, noncompete agreements and other	$	670.2		$	712.0		$	727.5
Accumulated amortization	(254.1		)	(263.8		)	(251.6		)
Intangible assets, net (definite-lived)	416.1			448.2			475.9
Trademarks and tradenames (indefinite-lived)	121.4			128.2			132.3
Total intangible assets, net	$	537.5		$	576.4		$	608.2

The decrease in goodwill and intangible assets at March 31, 2015, includes the effects of currency translation. Amortization expense of intangible assets was $12.0 and $25.0 for the three and six months ended March 31, 2015, respectively. Amortization expense of intangible assets was $8.9 and $22.2 for the three and six months ended March 31, 2014, respectively. Amortization expense included in cost of sales in the Condensed Consolidated Statements of Income is not material. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 2015 and for the next four fiscal years is as follows: remainder of Fiscal 2015 — $24.7; Fiscal 2016 — $44.3; Fiscal 2017 — $38.1; Fiscal 2018 — $36.4; Fiscal 2019 — $34.8.

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Utility Regulatory Assets and Liabilities and Regulatory Matters

6 Months Ended

Mar. 31, 2015

Regulated Operations [Abstract]

Utility Regulatory Assets and Liabilities and Regulatory Matters

Note 6 — 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 9 in the Company’s 2014 Annual Report. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Utilities are included in our accompanying Condensed Consolidated Balance Sheets:

	March 31, 2015		September 30, 2014		March 31, 2014
Regulatory assets (a):
Income taxes recoverable	$	111.5	$	110.7	$	106.8
Underfunded pension and postretirement plans	105.5		110.1		91.0
Environmental costs	14.1		14.6		14.5
Deferred fuel and power costs	—		11.8		4.3
Removal costs, net	18.4		16.8		14.4
Other	3.1		4.2		4.9
Total regulatory assets	$	252.6	$	268.2	$	235.9
Regulatory liabilities (a):
Postretirement benefits	$	19.3	$	18.6	$	17.2
Environmental overcollections	—		0.3		1.9
Deferred fuel and power refunds	40.6		0.3		3.2
State tax benefits—distribution system repairs	10.6		10.1		9.0
Other	2.1		3.2		1.8
Total regulatory liabilities	$	72.6	$	32.5	$	33.1

(a) Noncurrent regulatory assets are recorded in other assets and regulatory liabilities are recorded in other current and other noncurrent liabilities in the Condensed Consolidated Balance Sheets.

Deferred fuel and power—costs and refunds. Gas Utility’s 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”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability.

Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at March 31, 2015, September 30, 2014 and March 31, 2014 were $(3.4), $(1.4) and $2.4, respectively.

Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. We have chosen not to elect the NPNS exception under GAAP related to these derivative instruments for all forward electricity purchase contracts entered into prior to March 1, 2015. These electricity supply contracts are recognized on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its DS costs. At March 31, 2015, September 30, 2014, and March 31, 2014, the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(1.2), $0.3 and $0.4, respectively. These amounts are reflected in current and noncurrent derivative assets and current and noncurrent derivative liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds in the table above. Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility will elect the NPNS exception under GAAP and, as a result, the fair values of such contracts will not be recognized on the balance sheet (see Note 12).

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 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 deferred fuel and power refunds. Unrealized gains or losses on FTRs at March 31, 2015, September 30, 2014, and March 31, 2014, were not material.

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Debt

6 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Debt

Note 8 — Debt

On March 27, 2015, UGI Utilities entered into an unsecured revolving credit agreement (the “UGI Utilities 2015 Credit Agreement”) with a group of banks providing for borrowings up to $300 (including a $100 sublimit for letters of credit). Concurrently with entering into the UGI Utilities 2015 Credit Agreement, UGI Utilities terminated its then-existing $300 revolving credit agreement dated as of May 25, 2011. Under the UGI Utilities 2015 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2015 Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.0. The UGI Utilities 2015 Credit Agreement is currently scheduled to expire in March 2016, but may be extended by UGI Utilities to March 2020 if on or before March 25, 2016, the Company satisfies certain requirements relating to approval by the PUC. The Company intends to seek such regulatory approval.

In anticipation of the Company’s pending acquisition of Total’s retail LPG distribution business in France (“Totalgaz”) expected to occur during the third quarter of Fiscal 2015, on April 30, 2015, UGI France, an indirect wholly owned subsidiary of UGI, entered into a new Senior Facilities Agreement with a consortium of banks (the “2015 Senior Facilities Agreement”) having a final maturity date of April 30, 2020. UGI France expects to draw under the Senior Facilities Agreement substantially concurrent with the closing of the pending Totalgaz acquisition. The 2015 Senior Facilities Agreement, when drawn, will consist of a €600 variable-rate term loan and also a €60 revolving credit facility. The term loan proceeds from the 2015 Senior Facilities Agreement will be used to (1) fund a portion of the acquisition of Totalgaz, including related fees and expenses; (2) prepay €342 principal amount, plus accrued interest, outstanding under Antargaz’ 2011 Senior Facilities Agreement due March 2016 (the “2011 Senior Facilities Agreement”); (3) settle Antargaz’ existing pay-fixed, receive-variable interest rate swaps associated with the 2011 Senior Facilities Agreement; and (4) for general corporate purposes. As of March 31, 2015, the fair value of the interest rate swaps was a loss of $10.3. UGI France does not intend to draw on either the term loan or the revolving credit facility until the closing date of the Totalgaz acquisition, which is required to occur no later than June 30, 2015, pursuant to the terms of the 2015 Senior Facilities Agreement.

Borrowings under the 2015 Senior Facilities Agreement €600 term loan and the €60 revolving credit facility will bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate. The margin on such borrowings (which ranges from 1.60% to 2.70% for the term loan, and 1.45% to 2.55% for the revolving credit facility) will be dependent upon the ratio of UGI France’s consolidated total net debt to earnings before interest expense, income taxes, depreciation, and amortization (“EBITDA”), each as defined in the 2015 Senior Facilities Agreement. UGI France expects to enter into pay-fixed, receive-variable interest rate swaps to fix the underlying euribor rate of interest on the term loan.

Principal amounts to be outstanding under the 2015 Senior Facilities Agreement term loan will be due as follows: €60 due April 30, 2018; €60 due April 30, 2019; and €480 million due April 30, 2020.The 2015 Senior Facilities Agreement restricts the ability of UGI France to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires UGI France and its consolidated subsidiaries to maintain a ratio of total net debt to EBITDA, each as defined in the 2015 Senior Facilities Agreement, that shall not exceed (a) 3.75 to 1.00 from the closing date of the pending Totalgaz acquisition to September 30, 2015, and (b) 3.50 to 1.00 from October 1, 2015, to the final maturity date. UGI France will generally be permitted to make restricted payments, such as dividends, if no event of default exists or would exist upon payment of such dividend.

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Summary of Significant Accounting Policies (Details)	6 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Ownership interests in certain subsidiaries under equity method investment, maximum	100.00%
Voting rights in investment businesses not traded publicly accounted for under the cost method, Maximum	20.00%

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Derivative Instruments and Hedging Activities - Offsetting Derivative Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Document Period End Date	Mar. 31, 2015
Derivative asset, gross	$ 67.8	$ 31.6	[1]
Derivative asset, gross liability	(13.8)	(8.6)
Derivative asset, net	54.0	23.0
Cash collateral (received) pledged	0	0
Derivative asset, net amount recognized in balance sheet	54.0	23.0
Derivative liability, gross	(180.8)	(65.3)	[1]
Derivative liability, gross asset	13.8	8.6
Derivative liability, net	(167.0)	(56.7)
Cash collateral (received) pledged	3.7	0
Derivative liability, net amount recognized in balance sheet	$ (163.3)	$ (56.7)

[1] Certain immaterial amounts have been revised to correct the classification of derivatives.

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Accumulated Other Comprehensive Income

6 Months Ended

Mar. 31, 2015

Equity [Abstract]

Accumulated Other Comprehensive Income

Note 13 — Accumulated Other Comprehensive Income

The tables below present changes in AOCI during the three and six months ended March 31, 2015 and 2014:

Three Months Ended March 31, 2015	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - December 31, 2014	$	(20.0	)	$	1.7		$	(21.8	)	$	(40.1	)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			20.2			(64.5		)	(44.3		)
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0.6			(3.0		)	—			(2.4		)
Reclassification adjustments tax expense	(0.2		)	1.1			—			0.9
Reclassification adjustments (after-tax)	0.4			(1.9		)	—			(1.5		)
Other comprehensive income (loss)	0.4			18.3			(64.5		)	(45.8		)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			0.5			—			0.5
Other comprehensive income (loss) attributable to UGI	0.4			18.8			(64.5		)	(45.3		)
AOCI - March 31, 2015	$	(19.6	)	$	20.5		$	(86.3	)	$	(85.4	)
Three Months Ended March 31, 2014	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - December 31, 2013	$	(16.0	)	$	(15.8	)	$	64.0		$	32.2
Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			6.3			(0.6		)	5.7
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0.3			(34.7		)	—			(34.4		)
Reclassification adjustments tax benefit	(0.1		)	3.3			—			3.2
Reclassification adjustments (after-tax)	0.2			(31.4		)	—			(31.2		)
Other comprehensive income (loss)	0.2			(25.1		)	(0.6		)	(25.5		)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			17.6			—			17.6
Other comprehensive income (loss) attributable to UGI	0.2			(7.5		)	(0.6		)	(7.9		)
AOCI - March 31, 2014	$	(15.8	)	$	(23.3	)	$	63.4		$	24.3

Six Months Ended March 31, 2015	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - September 30, 2014	$	(20.6	)	$	(9.3	)	$	8.7		$	(21.2	)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			27.9			(95.0		)	(67.1		)
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	1.6			0.6			—			2.2
Reclassification adjustments tax expense	(0.6		)	(0.4		)	—			(1.0		)
Reclassification adjustments (after-tax)	1.0			0.2			—			1.2
Other comprehensive income (loss)	1.0			28.1			(95.0		)	(65.9		)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			1.7			—			1.7
Other comprehensive income (loss) attributable to UGI	1.0			29.8			(95.0		)	(64.2		)
AOCI - March 31, 2015	$	(19.6	)	$	20.5		$	(86.3	)	$	(85.4	)
Six Months Ended March 31, 2014	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
AOCI - September 30, 2013	$	(16.4	)	$	(26.9	)	$	51.7		$	8.4
Other comprehensive income before reclassification adjustments (after-tax)	—			46.8			11.7			58.5
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0.6			(50.5		)	—			(49.9		)
Reclassification adjustments tax benefit	—			5.3			—			5.3
Reclassification adjustments (after-tax)	0.6			(45.2		)	—			(44.6		)
Other comprehensive income	0.6			1.6			11.7			13.9
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			2.0			—			2.0
Other comprehensive income attributable to UGI	0.6			3.6			11.7			15.9
AOCI - March 31, 2014	$	(15.8	)	$	(23.3	)	$	63.4		$	24.3

For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 12.

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Goodwill and Intangible Assets (Tables)

6 Months Ended

Mar. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Components of Company's Intangible Assets

Goodwill and intangible assets comprise the following:

	March 31, 2015			September 30, 2014			March 31, 2014
Goodwill (not subject to amortization)	$	2,731.2		$	2,833.4		$	2,886.0
Intangible assets:
Customer relationships, noncompete agreements and other	$	670.2		$	712.0		$	727.5
Accumulated amortization	(254.1		)	(263.8		)	(251.6		)
Intangible assets, net (definite-lived)	416.1			448.2			475.9
Trademarks and tradenames (indefinite-lived)	121.4			128.2			132.3
Total intangible assets, net	$	537.5		$	576.4		$	608.2

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Derivative Instruments and Hedging Activities (Details)	6 Months Ended									6 Months Ended			6 Months Ended
	Mar. 31, 2015 USD ($) gal	Mar. 31, 2014 USD ($) gal	Sep. 30, 2014 USD ($)	Mar. 31, 2015 Brokerage Accounts USD ($)	Mar. 31, 2014 Brokerage Accounts USD ($)	Mar. 31, 2015 Interest Rate Swaps EUR (€)	Mar. 31, 2014 Interest Rate Swaps EUR (€)	Mar. 31, 2015 Interest Rate Protection Agreements USD ($)	Mar. 31, 2014 Interest Rate Protection Agreements USD ($)	Mar. 31, 2015 Foreign Currency USD ($)	Mar. 31, 2014 Foreign Currency USD ($)	Sep. 30, 2013 Cross Currency Contracts USD ($)	Mar. 31, 2015 Gas Utility MMBTU	Mar. 31, 2014 Gas Utility MMBTU	Mar. 31, 2015 Electric Utility kWh	Mar. 31, 2014 Electric Utility kWh	Mar. 31, 2015 Midstream & Marketing Electricity (millions of kilowatt-hours) Forward Purchase Contracts kWh	Mar. 31, 2014 Midstream & Marketing Electricity (millions of kilowatt-hours) Forward Purchase Contracts kWh	Mar. 31, 2015 Midstream & Marketing Electricity (millions of kilowatt-hours) Forward Sales Contracts kWh	Mar. 31, 2014 Midstream & Marketing Electricity (millions of kilowatt-hours) Forward Sales Contracts kWh	Mar. 31, 2015 Midstream & Marketing Propane Storage (millions of dekatherms) Forward Sales Contracts gal	Mar. 31, 2014 Midstream & Marketing Propane Storage (millions of dekatherms) Forward Sales Contracts gal	Mar. 31, 2015 Midstream & Marketing Gas Utility Natural Gas Forward Purchase Contracts MMBTU	Mar. 31, 2014 Midstream & Marketing Gas Utility Natural Gas Forward Purchase Contracts MMBTU	Mar. 31, 2015 Midstream & Marketing Natural Gas Storage Forward Sales Contracts MMBTU	Mar. 31, 2014 Midstream & Marketing Natural Gas Storage Forward Sales Contracts MMBTU	Mar. 31, 2015 Midstream & Marketing FTR and NYISO Contracts Electric transmission congestion (excluding Electric Utility) kWh	Mar. 31, 2014 Midstream & Marketing FTR and NYISO Contracts Electric transmission congestion (excluding Electric Utility) kWh	Mar. 31, 2015 Net Investment Hedging EUR (€)	Mar. 31, 2014 Net Investment Hedging EUR (€)
Derivative
Volume of LPG commodity derivatives (in gallons)	362,500,000	121,900,000																			0	0
Derivative, Notional Amount						€ 401,100,000	€ 439,800,000	$ 0	$ 0	$ 223,500,000	$ 199,400,000	$ 52,000,000																	€ 0	€ 0
Maximum length of time hedging exposure to LPG commodity price risk	45 months
Notional amount													9,700,000	9,000,000	384,400,000	207,000,000	356,000,000	603,100,000	315,400,000	346,100,000			61,600,000	65,100,000	600,000	100,000	124,600,000	482,500,000
Maximum length of time hedged in price risk cash flow hedges										35 months			12 months		14 months		24 months		18 months				42 months				2 months
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	2,600,000
Amount of net gains associated with currency rate risk to be reclassified into earnings during the next 12 months	19,500,000
Restricted cash	$ 56,700,000	$ 4,400,000	$ 16,600,000	$ 56,700,000	$ 4,400,000

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Utility Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015		Sep. 30, 2014		Mar. 31, 2014
Regulatory Assets And Liabilities
Regulatory assets	$ 252.6	[1]	$ 268.2	[1]	$ 235.9	[1]
Regulatory liabilities	72.6	[1]	32.5	[1]	33.1	[1]
Postretirement Benefits
Regulatory Assets And Liabilities
Regulatory liabilities	19.3	[1]	18.6	[1]	17.2	[1]
Environmental Overcollections
Regulatory Assets And Liabilities
Regulatory liabilities	0	[1]	0.3	[1]	1.9	[1]
Deferred Fuel and Power Refunds
Regulatory Assets And Liabilities
Regulatory liabilities	40.6	[1]	0.3	[1]	3.2	[1]
State Tax Benefits—Distribution System Repairs
Regulatory Assets And Liabilities
Regulatory liabilities	10.6	[1]	10.1	[1]	9.0	[1]
Other
Regulatory Assets And Liabilities
Regulatory liabilities	2.1	[1]	3.2	[1]	1.8	[1]
Income Taxes Recoverable
Regulatory Assets And Liabilities
Regulatory assets	111.5	[1]	110.7	[1]	106.8	[1]
Underfunded Pension and Postretirement Plans
Regulatory Assets And Liabilities
Regulatory assets	105.5	[1]	110.1	[1]	91.0	[1]
Environmental Costs
Regulatory Assets And Liabilities
Regulatory assets	14.1	[1]	14.6	[1]	14.5	[1]
Deferred Fuel and Power Costs
Regulatory Assets And Liabilities
Regulatory assets	0	[1]	11.8	[1]	4.3	[1]
Removal Costs, Net
Regulatory Assets And Liabilities
Regulatory assets	18.4	[1]	16.8	[1]	14.4	[1]
Other
Regulatory Assets And Liabilities
Regulatory assets	$ 3.1	[1]	$ 4.2	[1]	$ 4.9	[1]

[1] Noncurrent regulatory assets are recorded in other assets and regulatory liabilities are recorded in other current and other noncurrent liabilities in the Condensed Consolidated Balance Sheets.

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Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015	Mar. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income	$ 482.2	$ 387.8	$ 482.4	$ 605.3
Other comprehensive income (loss):
Net gains on derivative instruments (net of tax of $(10.4), $0.4, $(14.3) and $(7.1), respectively)	20.2	6.3	27.9	46.8
Reclassifications of net losses (gains) on derivative instruments (net of tax of $1.1, $3.3, $(0.4) and $5.3, respectively)	(1.9)	(31.4)	0.2	(45.2)
Foreign currency adjustments (net of tax of $35.0, $0.6, $50.6 and $(3.1), respectively)	(64.5)	(0.6)	(95.0)	11.7
Benefit plans (net of tax of $(0.2), $(0.1), $(0.6) and $0.0, respectively)	0.4	0.2	1.0	0.6
Other comprehensive (loss) income	(45.8)	(25.5)	(65.9)	13.9
Comprehensive income	436.4	362.3	416.5	619.2
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	(235.1)	(155.8)	(200.1)	(266.9)
Comprehensive income attributable to UGI Corporation	$ 201.3	$ 206.5	$ 216.4	$ 352.3

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Summary of Significant Accounting Policies

6 Months Ended

Mar. 31, 2015

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 2 — Summary of 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 limited partner interests in the Partnership, and outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests. We eliminate 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, 2014, 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 the Company’s 2014 Annual Report. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

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 March 31,		Six Months Ended March 31,
	2015	2014	2015	2014
Denominator (thousands of shares):
Average common shares outstanding for basic computation	173,154	172,760	173,055	172,494
Incremental shares issuable for stock options and awards	2,474	2,361	2,660	2,295
Average common shares outstanding for diluted computation	175,628	175,121	175,715	174,789

Derivative Instruments. Derivative instruments are reported in the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting.

Certain of our derivative instruments are designated and qualify as cash flow hedges or net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on certain commodity derivative instruments used by Gas Utility and Electric Utility are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers.

Effective October 1, 2014, UGI International determined that on a prospective basis it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Midstream & Marketing has not applied cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Substantially all realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues. For additional information on our derivative instruments, see Note 12.

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

Consolidated Effective Income Tax Rate. UGI’s consolidated effective income tax rate, defined as total income tax (expense) or benefit as a percentage of income (loss) before income taxes, includes amounts associated with noncontrolling interests in the Partnership, which principally comprises AmeriGas Partners and AmeriGas OLP.  AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. As a result, UGI’s consolidated effective income tax rate is affected by the amount of income (loss) before income taxes attributable to noncontrolling interests in the Partnership not subject to income taxes.

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

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Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)

6 Months Ended

Mar. 31, 2015

Regulated Operations [Abstract]

Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility

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

	March 31, 2015		September 30, 2014		March 31, 2014
Regulatory assets (a):
Income taxes recoverable	$	111.5	$	110.7	$	106.8
Underfunded pension and postretirement plans	105.5		110.1		91.0
Environmental costs	14.1		14.6		14.5
Deferred fuel and power costs	—		11.8		4.3
Removal costs, net	18.4		16.8		14.4
Other	3.1		4.2		4.9
Total regulatory assets	$	252.6	$	268.2	$	235.9
Regulatory liabilities (a):
Postretirement benefits	$	19.3	$	18.6	$	17.2
Environmental overcollections	—		0.3		1.9
Deferred fuel and power refunds	40.6		0.3		3.2
State tax benefits—distribution system repairs	10.6		10.1		9.0
Other	2.1		3.2		1.8
Total regulatory liabilities	$	72.6	$	32.5	$	33.1

(a) Noncurrent regulatory assets are recorded in other assets and regulatory liabilities are recorded in other current and other noncurrent liabilities in the Condensed Consolidated Balance Sheets.

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Goodwill and Intangible Assets (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015	Mar. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense of intangible assets	$ 12.0	$ 8.9	$ 25.0	$ 22.2
Remainder of Fiscal 2015	24.7		24.7
Fiscal 2016	44.3		44.3
Fiscal 2017	38.1		38.1
Fiscal 2018	36.4		36.4
Fiscal 2019	$ 34.8		$ 34.8

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Derivative Instruments and Hedging Activities

6 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Note 12 — 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.

Commodity Price Risk

In order to manage market price risk associated with the Partnership’s fixed-price programs, 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. The Partnership from time to time, enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility. At March 31, 2015 and 2014, total volumes associated with LPG commodity derivative instruments totaled 362.5 million gallons and 121.9 million gallons, respectively. At March 31, 2015, the maximum period over which we are economically hedging our exposure to LPG commodity price risk is 45 months.

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 March 31, 2015 and 2014, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 9.7 million dekatherms and 9.0 million dekatherms, respectively. At March 31, 2015, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 12 months. Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism. (see Note 6).

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. For such contracts entered into by Electric Utility prior to March 1, 2015, Electric Utility chose not to elect the NPNS exception under GAAP related to these derivative instruments and the fair values of these contracts are reflected in current and noncurrent derivative instrument assets and liabilities in the accompanying Condensed Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Condensed Consolidated Balance Sheets in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). Effective with Electric Utility forward electricity purchase contracts entered into beginning March 1, 2015, Electric Utility will elect the NPNS exception under GAAP and, as a result, the fair values of such contracts will not be recognized on the balance sheet. At March 31, 2015 and 2014, the volumes of Electric Utility’s forward electricity purchase contracts were 384.4 million kilowatt hours and 207.0 million kilowatt hours, respectively. At March 31, 2015, the maximum period over which these contracts extend is 14 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. Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and 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. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). At March 31, 2015 and 2014, the total volumes associated with FTRs and NYISO capacity contracts totaled 124.6 million kilowatt hours and 482.5 million kilowatt hours, respectively. At March 31, 2015, the maximum period over which we are economically hedging electricity congestion and locational basis differences is 2 months.

In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures contracts, IntercontinentalExchange (“ICE”) natural gas basis swap contracts, and electricity futures contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas or propane. Because it could no longer assert the NPNS exception under GAAP for new contracts entered into for the forward purchase of natural gas and pipeline transportation, beginning in the second quarter of Fiscal 2014 Energy Services began recording these contracts at fair value with changes in fair value reflected in cost of sales.

At March 31, 2015 and 2014, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline contracts totaled 61.6 million dekatherms and 65.1 million dekatherms, respectively. At March 31, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk is 42 months. At March 31, 2015 and 2014, total volumes associated with Midstream & Marketing’s electricity call contracts and electricity put contracts totaled 356.0 million kilowatt hours and 315.4 million kilowatt hours, and 603.1 million kilowatt hours and 346.1 million kilowatt hours, respectively. At March 31, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity commodity price risk (excluding Electric Utility) is 24 months for electricity call contracts and 18 months for electricity put contracts. At March 31, 2015, the volumes associated with Midstream & Marketing’s natural gas storage NYMEX contracts totaled 0.6 million dekatherms and there were no propane storage NYMEX contracts. At March 31, 2014, the volumes associated with Midstream & Marketing’s natural gas storage NYMEX contracts totaled 0.1 million dekatherms and there were no propane storage NYMEX contracts.

At March 31, 2015, the amount of net gains associated with commodity derivative instruments previously designated and qualified as cash flow hedges expected to be reclassified into earnings during the next twelve months is not material.

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 and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on their variable-rate term loans through the respective scheduled maturity dates. As of March 31, 2015 and 2014, the total notional amounts of variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) were €401.1 and €439.8, respectively.

Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At March 31, 2015 and 2014, we had no unsettled IRPAs.

We account for interest rate swaps and IRPAs as cash flow hedges. At March 31, 2015, 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 $2.6.

Foreign Currency Exchange Rate Risk

In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases during the heating-season months of October through March through the use of forward foreign currency exchange contracts. At March 31, 2015 and 2014, we were hedging a total of $223.5 and $199.4 of U.S. dollar-denominated LPG purchases, respectively. At March 31, 2015, the maximum period over which we are hedging our exposure to the variability in cash flows associated with U.S. dollar-denominated purchases of LPG is 35 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 March 31, 2015 and 2014, we had no euro-denominated net investment hedges.

We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At March 31, 2015, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $19.5.

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. dollar-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. dollar-denominated interest rate. We have designated this cross-currency swap as a cash flow hedge. At March 31, 2015, the amount of net gains associated with this cross-currency swap expected to be reclassified into earnings over the next twelve months is not material.

Derivative Instrument Credit Risk

We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts generally require cash deposits in margin accounts. At March 31, 2015 and 2014, restricted cash in brokerage accounts totaled $56.7 and $4.4, respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at March 31, 2015. 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 March 31, 2015, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.

Fair Value of Derivative Instruments

The following table presents the Company’s derivative assets and liabilities on a gross basis as of March 31, 2015 and 2014:

	March 31, 2015			March 31, 2014 (a)
Derivative assets:
Derivatives designated as hedging instruments:
Commodity contracts	$	—		$	10.9
Foreign currency contracts	35.8			0.1
Cross-currency contracts	9.7			—
Interest rate contracts	0.1			—
	45.6			11.0
Derivatives subject to utility rate regulation:
Commodity contracts	—			3.5
Derivatives not designated as hedging instruments:
Commodity contracts	22.2			17.1
Total derivative assets	$	67.8		$	31.6
Derivative liabilities:
Derivatives designated as hedging instruments:
Commodity contracts	$	—		$	(1.1	)
Foreign currency contracts	—			(5.6		)
Cross-currency contracts	—			(2.2		)
Interest rate contracts	(12.5		)	(27.8		)
	(12.5		)	(36.7		)
Derivatives subject to utility rate regulation:
Commodity contracts	(5.2		)	(0.7		)
Derivatives not designated as hedging instruments:
Commodity contracts	(163.1		)	(27.9		)
Total derivative liabilities	$	(180.8	)	$	(65.3	)

(a) Certain immaterial amounts have been revised to correct the classification of derivatives.

Offsetting Derivative Assets and Liabilities

Derivative assets and liabilities are presented net by counterparty on our Condensed Consolidated Balance Sheets if the right of offset exists. Our derivative 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 over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, 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 table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements.

The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of March 31, 2015 and 2014:

	Gross Amounts Recognized			Gross Amounts Offset in Balance Sheet			Net Amounts Recognized			Cash Collateral (Received) Pledged		Net Amounts Recognized in Balance Sheet
March 31, 2015
Derivative assets	$	67.8		$	(13.8	)	$	54.0		$	—	$	54.0
Derivative liabilities	$	(180.8	)	$	13.8		$	(167.0	)	$	3.7	$	(163.3	)
March 31, 2014
Derivative assets	$	31.6		$	(8.6	)	$	23.0		$	—	$	23.0
Derivative liabilities	$	(65.3	)	$	8.6		$	(56.7	)	$	—	$	(56.7	)

Effect of Derivative Instruments

The following tables provide information on the effects of derivative instruments in the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three and six months ended March 31, 2015 and 2014:

	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 Interests into Income
Three Months Ended March 31,	2015			2014			2015			2014
Cash Flow Hedges:
Commodity contracts	$	—		$	7.8		$	0.1		$	39.9		Cost of sales
Foreign currency contracts	23.7			(0.2		)	6.5			(1.4		)	Cost of sales
Cross-currency contracts	5.4			0.1			(0.1		)	0.2			Interest expense
Interest rate contracts	1.6			(1.8		)	(3.5		)	(4.0		)	Interest expense
Total	$	30.7		$	5.9		$	3.0		$	34.7
	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Three Months Ended March 31,	2015			2014
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	(12.3	)	$	(22.2	)	Cost of sales
Commodity contracts	(4.6		)	—			Revenues
Commodity contracts	—			—			Operating expenses / other operating income, net
Total	$	(16.9	)	$	(22.2	)
	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 Interests into Income
Six Months Ended March 31,	2015			2014			2015			2014
Cash Flow Hedges:
Commodity contracts	$	—		$	61.2		$	(2.3	)	$	62.2		Cost of sales
Foreign currency contracts	32.4			(2.7		)	9.2			(3.5		)	Cost of sales
Cross-currency contracts	7.5			(1.1		)	(0.1		)	(0.1		)	Interest expense
Interest rate contracts	2.4			(3.5		)	(7.4		)	(8.1		)	Interest expense
Total	$	42.3		$	53.9		$	(0.6	)	$	50.5
	Gain (Loss) Recognized in Income						Location of Gain (Loss) Recognized in Income
Six Months Ended March 31,	2015			2014
Derivatives Not Designated as Hedging Instruments:
Commodity contracts	$	(304.8	)	$	(9.4	)	Cost of sales
Commodity contracts	(0.8		)	—			Revenues
Commodity contracts	(0.5		)	0.1			Operating expenses / other operating income, net
Total	$	(306.1	)	$	(9.3	)

The amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material for the three and six months ended March 31, 2015 and 2014.

We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts which provide for the purchase and delivery, or sale, of energy products, 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, certain of these contracts qualify for NPNS 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.