UGI (UGI) 10-Q 5 Feb 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Dec. 31, 2015	Jan. 31, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	UGI CORP /PA/
Entity Central Index Key	884,614
Document Type	10-Q
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--09-30
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		171,914,720

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 403	$ 369.7	$ 410.1
Restricted cash	55.5	69.3	54.6
Accounts receivable (less allowances for doubtful accounts of $30.6, $29.7 and $37.9, respectively)	803.1	619.7	960.6
Accrued utility revenues	30.8	12.1	52.7
Inventories	246.8	239.9	391
Deferred income taxes	0	7.8	46.1
Utility regulatory assets	3.9	4.1	16.8
Derivative instruments	29.1	23.3	19.7
Prepaid expenses and other current assets	101.8	113.9	88
Total current assets	1,674	1,459.8	2,039.6
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,896.9 $2,835.0 and $2,664.2, respectively)	5,012.9	4,994.1	4,552.7
Goodwill	2,965.1	2,953.4	2,806.8	[1]
Intangible assets, net	602.4	610.1	563.7
Utility regulatory assets	297.9	300.1	253.8
Derivative instruments	13.7	16.3	16.1
Deferred income taxes	5.6	5.1	0
Other assets	208.8	207.7	197.3
Total assets	10,780.4	10,546.6	10,430	[1]
Current liabilities:
Current maturities of long-term debt	186.9	258	147.1
Short-term borrowings	456.8	189.9	458.5	[1]
Accounts payable	423.3	392.9	556.5
Derivative instruments	123.1	121.8	157
Other current liabilities	721.6	716.3	649.7
Total current liabilities	1,911.7	1,678.9	1,968.8
Long-term debt	3,422.4	3,441.8	3,341.2
Deferred income taxes	1,140.4	1,134	976.3
Deferred investment tax credits	3.5	3.6	3.8
Derivative instruments	33.6	31.2	39.9
Other noncurrent liabilities	676.3	684.7	545.3
Total liabilities	$ 7,187.9	$ 6,974.2	$ 6,875.3
Commitments and contingencies
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized—450,000,000 shares; issued—173,825,741, 173,806,991 and 173,772,391 shares, respectively)	$ 1,215.7	$ 1,214.6	$ 1,215.7
Retained earnings	1,712.3	1,636.9	1,506
Accumulated other comprehensive loss	(142.9)	(114.6)	(40.1)
Treasury stock, at cost	(65.7)	(44.9)	(35.3)
Total UGI Corporation stockholders’ equity	2,719.4	2,692	2,646.3
Noncontrolling interests, principally in AmeriGas Partners	873.1	880.4	908.4
Total equity	3,592.5	3,572.4	3,554.7
Total liabilities and equity	$ 10,780.4	$ 10,546.6	$ 10,430
[1]	Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Accounts receivable, allowances for doubtful accounts	$ 30.6	$ 29.7	$ 37.9
Property, plant and equipment, accumulated depreciation and amortization	$ 2,896.4	$ 2,835	$ 2,664.2
UGI Common Stock, without par value, shares authorized	450,000,000	450,000,000	450,000,000
UGI Common Stock, without par value, shares issued	173,825,741	173,806,991	173,772,391

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Revenues	$ 1,606.6	$ 2,004.6	[1]
Costs and expenses:
Cost of sales (excluding depreciation shown below)	734	1,404.6	[1]
Operating and administrative expenses	464.1	435.7
Utility taxes other than income taxes	3.8	4.1
Depreciation	85.7	75.8
Amortization	14.9	15.2
Other operating income, net	(1.4)	(14.1)
Total costs and expenses	1,301.1	1,921.3
Operating income	305.5	83.3	[1]
Loss from equity investees	(0.1)	(1)	[1]
Interest expense	(57.9)	(59)	[1]
Income before income taxes	247.5	23.3	[1]
Income tax expense	(79.6)	(23.1)
Net income including noncontrolling interests	167.9	0.2
(Deduct net income) add net loss attributable to noncontrolling interests, principally in AmeriGas Partners	(53.3)	33.9	[1]
Net income attributable to UGI Corporation	$ 114.6	$ 34.1
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)	$ 0.66	$ 0.20
Diluted (in dollars per share)	$ 0.65	$ 0.19
Weighted-average common shares outstanding (thousands):
Basic (in shares)	172,862	172,945
Diluted (in shares)	175,218	175,786
Dividends declared per common share (in dollars per share)	$ 0.2275	$ 0.2175
[1]	Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Net income including noncontrolling interests	$ 167.9	$ 0.2
Other comprehensive income (loss):
Net gains on derivative instruments (net of tax of $(4.2) and $(3.9), respectively)	6.8	7.7
Reclassifications of net (gains) losses on derivative instruments (net of tax of $3.2 and $(1.5), respectively)	(5.3)	2.1
Foreign currency adjustments (net of tax of $0 and $15.6, respectively)	(30.2)	(30.5)
Benefit plans (net of tax of $(0.3) and $(0.4), respectively)	0.4	0.6
Other comprehensive loss	(28.3)	(20.1)
Comprehensive income (loss) including noncontrolling interests	139.6	(19.9)
(Deduct comprehensive income) add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	(53.3)	35
Comprehensive income attributable to UGI Corporation	$ 86.3	$ 15.1

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Tax on (loss) gain on derivative instruments	$ (4.2)	$ (3.9)
Tax on reclassification on derivative instruments	3.2	(1.5)
Tax on foreign currency adjustments	0	15.6
Tax on benefit plans	$ (0.3)	$ (0.4)

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income including noncontrolling interests	$ 167.9	$ 0.2
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	100.6	91	[1]
Deferred income tax benefit, net	(20.9)	(59.8)
Provision for uncollectible accounts	6	7
Unrealized (gains) losses on derivative instruments	(1.1)	229.7
Other, net	5.9	(0.9)
Net change in:
Accounts receivable and accrued utility revenues	(213.4)	(341.8)
Inventories	(9.1)	27.6
Utility deferred fuel and power costs, net of changes in unsettled derivatives	(6.8)	4.4
Accounts payable	33.7	119.3
Collateral deposits	2.5	(90.9)
Other current assets	2.6	(14.9)
Other current liabilities	59.6	48.1
Net cash provided by operating activities	127.5	19
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(132)	(132.1)
Acquisitions of businesses, net of cash acquired	(41.7)	(7.2)
Decrease (increase) in restricted cash	13.8	(38)
Other, net	4.6	7
Net cash used by investing activities	(155.3)	(170.3)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(39.2)	(37.5)
Distributions on AmeriGas Partners publicly held Common Units	(63.6)	(60.8)
Repayments of debt	(74.5)	(2.6)
Increase in short-term borrowings	260.4	213
Receivables Facility net borrowings	6.5	35.5
Issuances of UGI Common Stock	2	5.5
Repurchases of UGI Common Stock	(23.6)	0
Other	0.4	(3.3)
Net cash provided by financing activities	68.4	149.8
EFFECT OF EXCHANGE RATE CHANGES ON CASH	(7.3)	(7.9)
Cash and cash equivalents increase (decrease)	33.3	(9.4)
Cash and cash equivalents:
End of period	403	410.1
Beginning of period	$ 369.7	$ 419.5
[1]	Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Changes in Equity (unaudited) - USD ($) $ in Millions	Total	Parent	Common Stock, Without Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Noncontrolling Interests
Balance, beginning of period at Sep. 30, 2014			$ 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) on treasury stock transactions), net of tax withheld			(3.9)
Excess tax benefits realized on equity-based compensation			1.8
Equity-based compensation expense			2.2
Net income including noncontrolling interests	$ 0.2			34.1			(33.9)
Cash dividends on Common Stock				(37.5)
Net gains on derivative instruments, net of tax	7.7				7.7
Reclassification of net (gains) losses on derivative instruments, net of tax	2.1				3.3
Benefit plans, net of tax	0.6				0.6
Foreign currency, net of tax	(30.5)				(30.5)
Common stock issued in connection with employee and director plans, net of tax withheld						9.8
Repurchases of Common Stock						0
Reacquired common stock - employee and director plans						(0.4)
Reclassification of net gains on derivative instruments							(1.2)
Dividends and distributions							(60.8)
Other							0.2
Balance, end of period at Dec. 31, 2014	3,554.7	$ 2,646.3	1,215.7	1,506	(40.1)	(35.3)	908.4
Balance, beginning of period at Sep. 30, 2015	3,572.4		1,214.6	1,636.9	(114.6)	(44.9)	880.4
Increase (Decrease) in Stockholders' Equity
Common Stock issued in connection with employee and director plans (including (losses) on treasury stock transactions), net of tax withheld			(0.9)
Excess tax benefits realized on equity-based compensation			0.4
Equity-based compensation expense			1.6
Net income including noncontrolling interests	167.9			114.6			53.3
Cash dividends on Common Stock				(39.2)
Net gains on derivative instruments, net of tax	6.8				6.8
Reclassification of net (gains) losses on derivative instruments, net of tax	(5.3)				(5.3)
Benefit plans, net of tax	0.4				0.4
Foreign currency, net of tax	(30.2)				(30.2)
Common stock issued in connection with employee and director plans, net of tax withheld						3
Repurchases of Common Stock						(23.6)
Reacquired common stock - employee and director plans						(0.2)
Reclassification of net gains on derivative instruments							0
Dividends and distributions							(63.6)
Other							3
Balance, end of period at Dec. 31, 2015	$ 3,592.5	$ 2,719.4	$ 1,215.7	$ 1,712.3	$ (142.9)	$ (65.7)	$ 873.1

Nature of Operations

Nature of Operations	3 Months Ended
	Dec. 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,” “we” or “us.” 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 December 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 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises 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, 2015 (the “Company’s 2015 Annual Report”). Incentive distributions received by the General Partner during the three months ended December 31, 2015 and 2014 were $8.6 and $6.5 , respectively. Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“UGI France”); (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 (“HVAC”). 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.”

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2 — Summary of Significant Accounting Policies 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, 2015 , 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 2015 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 2015 2014 Denominator (thousands of shares): Weighted-average common shares outstanding for basic computation 172,862 172,945 Incremental shares issuable for stock options and awards 2,356 2,841 Weighted-average common shares outstanding for diluted computation 175,218 175,786 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 occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the 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 on a prospective basis that 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, as appropriate, on the Condensed Consolidated Statements of Income. Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, if any, are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from net investment hedges are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges are included in cash flow from operating activities while cash flows from the currency portion of such hedges are included in the cash flow from financing activities. For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, 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. Correction of Prior Period Error in Other Comprehensive Income During the three months ended June 30, 2015, the Company recorded an adjustment to decrease other comprehensive income related to prior periods by reducing the amount of net deferred tax assets that had been previously recognized for (1) foreign currency adjustments related to foreign subsidiaries whose undistributed earnings are considered indefinitely reinvested, and (2) foreign currency adjustments related to intercompany loans between a U.S. domiciled entity and its foreign branch that is considered disregarded for tax purposes and for which income taxes will not be payable. Accounting Standards Codification (“ASC”) No. 740, “ Income Taxes,” provides an exception to recording deferred tax attributes associated with these components of comprehensive income. Previously, the Company had incorrectly recorded deferred taxes on these currency adjustments. During the three months ended June 30, 2015, the Company evaluated the effects of the errors, both qualitatively and quantitatively, and concluded that they did not have a material impact on any prior period financial statement and recorded the cumulative effect of the error as of April 1, 2015. If the Company had corrected the error in all of the periods prior to April 1, 2015, other comprehensive loss for the three months ended December 31, 2014 , would have increased by $14.4 .

Accounting Changes

Accounting Changes	3 Months Ended
	Dec. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Changes	Adoption of New Accounting Standard Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. We applied this guidance prospectively and, as a result, prior period amounts have not been adjusted. Accounting Standards Not Yet Adopted Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board (“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 (Fiscal 2017). Early adoption is permitted. Entities will apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance effective September 30, 2016. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. Consolidation. In February 2015, the FASB issued ASU No. 2015-02, “Amendments to the Consolidation Analysis.” This ASU provides 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. 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 ASC No. 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 entity 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, 2018 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our financial statements.

Inventories

Inventories	3 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventories	Note 4 — Inventories Inventories comprise the following: December 31, September 30, December 31, Non-utility LPG and natural gas $ 148.6 $ 140.7 $ 260.4 Gas Utility natural gas 35.9 37.5 72.4 Materials, supplies and other 62.3 61.7 58.2 Total inventories $ 246.8 $ 239.9 $ 391.0 At December 31, 2015 , UGI Utilities is a party to two 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 December 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 the non-affiliate at December 31, 2015 , September 30, 2015 and December 31, 2014 , comprising 3.8 billion cubic feet (“bcf”), 4.0 bcf and 3.4 bcf of natural gas, was $9.4 , $9.8 and $14.4 , respectively.

Goodwill and Intangible Assets

Goodwill and Intangible Assets	3 Months Ended
	Dec. 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: December 31, September 30, December 31, Goodwill (not subject to amortization) $ 2,965.1 $ 2,953.4 $ 2,806.8 Intangible assets: Customer relationships, noncompete agreements and other $ 764.6 $ 761.1 $ 709.3 Accumulated amortization (292.2 ) (282.4 ) (271.9 ) Intangible assets, net (definite-lived) 472.4 478.7 437.4 Trademarks and tradenames (indefinite-lived) 130.0 131.4 126.3 Total intangible assets, net $ 602.4 $ 610.1 $ 563.7 The changes in goodwill and intangible assets are primarily due to acquisitions and the effects of currency translation. Amortization expense of intangible assets was $12.8 and $13.0 for the three months ended December 31, 2015 and December 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 2016 and for the next four fiscal years is as follows: remainder of Fiscal 2016 — $39.0 ; Fiscal 2017 — $46.1 ; Fiscal 2018 — $44.6 ; Fiscal 2019 — $42.9 ; Fiscal 2020 — $41.6 .

Utility Regulatory Assets and L

Utility Regulatory Assets and Liabilities and Regulatory Matters	3 Months Ended
	Dec. 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 2015 Annual Report. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets: December 31, September 30, December 31, Regulatory assets: Income taxes recoverable $ 117.4 $ 115.9 $ 111.1 Underfunded pension and postretirement plans 138.3 140.8 107.8 Environmental costs 17.6 20.0 14.7 Deferred fuel and power costs — — 16.7 Removal costs, net 22.3 21.2 17.6 Other 6.2 6.3 2.7 Total regulatory assets $ 301.8 $ 304.2 $ 270.6 Regulatory liabilities (a): Postretirement benefits $ 20.3 $ 20.0 $ 19.0 Deferred fuel and power refunds 28.1 36.6 — State tax benefits—distribution system repairs 13.7 13.3 10.3 Other 1.1 1.1 3.6 Total regulatory liabilities $ 63.2 $ 71.0 $ 32.9 (a) 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 December 31, 2015 , September 30, 2015 and December 31, 2014 were $(4.5) , $(3.3) and $(6.8) , respectively. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Prior to March 1, 2015, we did not elect the NPNS exception under GAAP for these contracts. Therefore, we recognized the fair value of these contracts on the balance sheet with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its DS costs. At December 31, 2015 , September 30, 2015 , and December 31, 2014 , the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(0.5) , $(0.5) and $(2.4) , 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 contracts entered into beginning March 1, 2015, Electric Utility has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not 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 December 31, 2015 , September 30, 2015 , and December 31, 2014 , were not material. UGI Gas Base Rate Filing. On January 19, 2016, UGI Utilities filed a request with the PUC to increase UGI Gas base operating revenues for residential, commercial and industrial customers by $58.6 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. UGI Utilities is requesting that the new gas rates become effective March 19, 2016. However, the PUC typically suspends the effective date for general base rate proceedings to allow for investigation and public hearings. This review process is expected to last approximately nine months, however, the Company cannot predict the timing or the ultimate outcome of the rate case review process.

Energy Services Accounts Receiv

Energy Services Accounts Receivable Securitization Facility	3 Months Ended
	Dec. 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 an accounts receivable securitization facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2016. The Receivables Facility provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November through April and up to $75 of eligible receivables during the period May 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. 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. The Company records interest expense on amounts owed to the bank. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable. During the three months ended December 31, 2015 and 2014 , Energy Services transferred trade receivables to ESFC totaling $199.3 and $286.4 , respectively. During the three months ended December 31, 2015 and 2014 , ESFC sold an aggregate $61.5 and $105.0 , respectively, of undivided interests in its trade receivables to the bank. At December 31, 2015 , the outstanding balance of ESFC receivables was $55.4 of which $26.0 was sold to the bank. At December 31, 2014 , the outstanding balance of ESFC receivables was $96.5 of which $43.0 was sold to the bank. Losses on sales of receivables to the bank during the three months ended December 31, 2015 and 2014 , which are included in interest expense on the Condensed Consolidated Statements of Income, were not material.

Debt

Debt	3 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	Note 8 — Debt In October 2015, Flaga entered into a €100.8 Credit Facility Agreement (“Flaga Credit Facility Agreement”) with a bank. The Flaga Credit Facility Agreement includes a €25 multi-currency revolving credit facility, a €5 overdraft facility, a €25 guarantee facility and a €45.8 variable-rate term loan facility. Borrowings under the Flaga Credit Facility Agreement’s €45.8 term loan facility were used to refinance its €19.1 term loan due October 2016 and its €26.7 term loan due August 2016. Concurrent with entering into the Flaga Credit Facility Agreement, Flaga terminated its then-existing €46 multi-currency working capital facility. The Flaga Credit Facility Agreement revolving credit facility borrowings bear interest at market rates (generally one, three or six-month euribor rates) plus margins. The margins on revolving facility borrowings, which range from 1.45% to 3.65% , are based upon the actual currency borrowed and certain consolidated equity, return on assets and debt to EBITDA ratios, as defined in the Flaga Credit Facility Agreement. Facility fees on the unused amount of the revolving credit facility are 30% of the lowest applicable margin. The Flaga Credit Facility Agreement terminates in October 2020. The €45.8 term loan matures in October 2020. The €45.8 term bears interest at three-month euribor rates, plus a margin. The margin on such borrowings ranges from 0.40% to 1.80% and is based upon certain consolidated equity, return on assets and debt to EBITDA ratios, as defined. Flaga has entered into pay-fixed, receive-variable interest rate swaps that generally fix the underlying euribor rate on the term loan borrowings at 2.18% through September 2016 and 0.23% from October 2016 through October 2020. Because the cash flows associated with the refinancing of the then-existing term loans were with the same bank, such cash flows have been reflected “net” on the Condensed Consolidated Statement of Cash Flows.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Dec. 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 December 31, 2015 and 2014 , our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11.7 and $11.2 , 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. 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 receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At December 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 United States District Court for the Western District of Missouri. In July 2015, the Court dismissed all claims brought by direct customers and all claims other than those for injunctive relief brought by indirect customers. The direct customers filed an appeal with the United States Court of Appeals for the Eighth Circuit, which is still pending. The indirect customers filed an amended complaint claiming injunctive relief and state law claims under Wisconsin, Maine and Vermont law. In January 2016, the District Court dismissed the remaining injunctive relief claims for the indirect purchasers. As a result, the only claims remaining with respect to indirect purchasers involve alleged violations of Wisconsin, Maine and Vermont state antitrust laws. 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 financial position, results of operations or cash flows.

Defined Benefit Pension and Oth

Defined Benefit Pension and Other Postretirement Plans	3 Months Ended
	Dec. 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, UGI France 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 December 31, 2015 2014 2015 2014 Service cost $ 2.5 $ 2.4 $ 0.2 $ 0.2 Interest cost 6.6 6.3 0.2 0.2 Expected return on assets (8.0 ) (7.9 ) (0.2 ) (0.2 ) Amortization of: Prior service cost (benefit) 0.1 0.1 (0.1 ) (0.1 ) Actuarial loss 2.7 2.5 — — Net benefit cost 3.9 3.4 0.1 0.1 Change in associated regulatory liabilities — — 0.9 0.9 Net expense $ 3.9 $ 3.4 $ 1.0 $ 1.0 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 three months ended December 31, 2015 and 2014 , the Company made cash contributions to the U.S. Pension Plan of $2.5 and $2.8 , respectively. The Company expects to make additional discretionary cash contributions of approximately $7.4 to the U.S. Pension Plan during the remainder of Fiscal 2016 . 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 three months ended December 31, 2015 and 2014 . We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. Net periodic costs associated with these plans for the three months ended December 31, 2015 and 2014 were not material.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Dec. 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 December 31, 2015 , September 30, 2015 and December 31, 2014 : Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2015: Derivative instruments: Assets: Commodity contracts $ 19.7 $ 10.8 $ — $ 30.5 Foreign currency contracts $ — $ 25.4 $ — $ 25.4 Interest rate contracts $ — $ 0.6 $ — $ 0.6 Cross-currency swaps $ — $ 1.9 $ — $ 1.9 Liabilities: Commodity contracts $ (70.5 ) $ (97.5 ) $ — $ (168.0 ) Interest rate contracts $ — $ (9.8 ) $ — $ (9.8 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 31.7 $ — $ — $ 31.7 September 30, 2015: Derivative instruments: Assets: Commodity contracts $ 17.4 $ 11.6 $ — $ 29.0 Foreign currency contracts $ — $ 29.1 $ — $ 29.1 Cross-currency swaps $ — $ 0.4 $ — $ 0.4 Liabilities: Commodity contracts $ (70.0 ) $ (99.0 ) $ — $ (169.0 ) Foreign currency contracts $ — $ (0.1 ) $ — $ (0.1 ) Interest rate contracts $ — $ (10.8 ) $ — $ (10.8 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 30.3 $ — $ — $ 30.3 December 31, 2014: Derivative instruments: Assets: Commodity contracts $ 14.1 $ 26.1 $ — $ 40.2 Foreign currency contracts $ — $ 18.7 $ — $ 18.7 Interest rate contracts $ — $ 0.1 $ — $ 0.1 Cross-currency swaps $ — $ 4.3 $ — $ 4.3 Liabilities: Commodity contracts $ (69.4 ) $ (228.5 ) $ — $ (297.9 ) Interest rate contracts $ — $ (17.0 ) $ — $ (17.0 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 31.4 $ — $ — $ 31.4 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans. 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 that 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, foreign currency contracts and cross-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 December 31, 2015 , the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,609.3 and $3,590.4 , respectively. At December 31, 2014 , the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,488.3 and $3,640.7 , 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 that 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.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	3 Months Ended
	Dec. 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 December 31, 2015 and 2014 , total volumes associated with LPG commodity derivative instruments totaled 481.9 million gallons and 429.6 million gallons, respectively. At December 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 December 31, 2015 and 2014 , the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 12.4 million dekatherms and 11.2 million dekatherms, respectively. At December 31, 2015 , the maximum period over which Gas Utility is economically hedging natural gas market price risk is 9 months . Gains and losses on natural gas futures contracts and any gains on natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets 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 has elected the NPNS exception under GAAP and, as a result, the fair values of such contracts are not recognized on the balance sheet. At December 31, 2015 and 2014 , the volumes of Electric Utility’s forward electricity purchase contracts were 333.3 million kilowatt hours and 486.2 million kilowatt hours, respectively. At December 31, 2015 , the maximum period over which these contracts extend is 11 months . In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. 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 December 31, 2015 and 2014 , the total volumes associated with FTRs and NYISO capacity contracts totaled 223.7 million kilowatt hours and 331.8 million kilowatt hours, respectively. At December 31, 2015 , the maximum period over which we are economically hedging electricity congestion and locational basis differences is 5 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, Intercontinental Exchange (“ICE”) natural gas basis swap contracts, and electricity futures and forward 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 December 31, 2015 and 2014 , total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline contracts totaled 104.9 million dekatherms and 127.8 million dekatherms, respectively. At December 31, 2015 and 2014 , total volumes associated with Midstream & Marketing’s natural gas basis swap contracts totaled 86.1 million dekatherms and 37.1 million dekatherms, respectively. At December 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 39 months . At December 31, 2015 and 2014 , total volumes associated with Midstream & Marketing’s electricity long forward and futures contracts and electricity short forward and futures contracts totaled 547.8 million kilowatt hours and 252.9 million kilowatt hours, and 350.0 million kilowatt hours and 184.1 million kilowatt hours, respectively. At December 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 39 months for electricity call contracts and 37 months for electricity put contracts. At December 31, 2015 , the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 1.6 million dekatherms and 1.8 million gallons, respectively. At December 31, 2014 , the volumes associated with Midstream & Marketing’s natural gas storage and propane storage NYMEX contracts totaled 0.6 million dekatherms and 2.6 million gallons, respectively. At December 31, 2015 , there were no amounts remaining in AOCI related to commodity derivative hedges. Interest Rate Risk UGI France’s and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. UGI France 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 December 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 €645.8 and €401.1 , respectively. Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). At December 31, 2015 , the total notional amount of unsettled IRPAs was $290.0 . At December 31, 2014 , we had no unsettled IRPAs. Our December 31, 2015 , unsettled IRPA contracts hedge forecasted interest payments expected to occur over ten - and thirty -year periods beginning in Fiscal 2016. We account for interest rate swaps and IRPAs as cash flow hedges. At December 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 approximately $2.2 . Foreign Currency Exchange Rate Risk In order to reduce volatility, UGI France 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 December 31, 2015 and 2014 , we were hedging a total of $280.5 and $225.8 of U.S. dollar-denominated LPG purchases, respectively. At December 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 39 months . From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At December 31, 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 December 31, 2015 , the amount of net gains associated with currency rate risk expected to be reclassified into earnings during the next twelve months based upon current fair values is $16.0 . Cross-Currency Swaps From time to time, Flaga enters into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with foreign currency and interest rate risk. These cross-currency hedges include 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. These cross-currency swaps also include interest rate swaps of a fixed foreign-denominated interest rate to a fixed U.S. dollar-denominated interest rate. We designate these cross-currency swaps as cash flow hedges. At December 31, 2015 and 2014 , cross-currency swaps were hedging foreign currency risk associated with interest and principal payments on $59.1 and $52.0 of Flaga U.S. dollar-denominated debt, respectively. At December 31, 2015 , the amount of net gains associated with this cross-currency swap expected to be reclassified into earnings during 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 forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2015 and 2014 , restricted cash in brokerage accounts totaled $55.5 and $54.6 , 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 December 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 December 31, 2015 , if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material. 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. Fair Value of Derivative Instruments The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of December 31, 2015 and 2014 : December 31, December 31, Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 25.4 $ 18.7 Cross-currency contracts 1.9 4.3 Interest rate contracts 0.6 0.1 27.9 23.1 Derivatives subject to PGC and DS mechanisms: Commodity contracts 0.2 0.2 Derivatives not designated as hedging instruments: Commodity contracts 30.3 40.0 Total derivative assets - gross 58.4 63.3 Gross amounts offset in the balance sheet (15.6 ) (27.5 ) Total derivative assets - net $ 42.8 $ 35.8 Derivative liabilities: Derivatives designated as hedging instruments: Interest rate contracts $ (9.8 ) $ (17.0 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (6.3 ) (9.4 ) Derivatives not designated as hedging instruments: Commodity contracts (161.7 ) (288.5 ) Total derivative liabilities - gross (177.8 ) (314.9 ) Gross amounts offset in the balance sheet 15.6 27.5 Cash collateral pledged 5.5 90.5 Total derivative liabilities - net $ (156.7 ) $ (196.9 ) 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 months ended December 31, 2015 and 2014 : Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Three Months Ended December 31, 2015 2014 2015 2014 Cash Flow Hedges: Commodity contracts $ — $ — $ — $ (2.4 ) Cost of sales Foreign currency contracts 5.4 8.7 9.1 2.7 Cost of sales Cross-currency contracts — 2.1 — — Interest expense/other operating income, net Interest rate contracts 5.6 0.8 (0.6 ) (3.9 ) Interest expense Total $ 11.0 $ 11.6 $ 8.5 $ (3.6 ) Gain (Loss) Location of Gain (Loss) Three Months Ended December 31, 2015 2014 Derivatives Not Designated as Hedging Instruments: Commodity contracts $ (46.2 ) $ (292.5 ) Cost of sales Commodity contracts 1.6 3.8 Revenues Commodity contracts (0.1 ) (0.5 ) Operating expenses/other Total $ (44.7 ) $ (289.2 ) For the three months ended December 31, 2015, the amount of derivative gains or losses representing ineffectiveness, and the amount of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, was a loss of $3.4 which amount is recorded in other operating income, net, on the Condensed Consolidated Statements of Income and is related to interest rate contracts at UGI France. For the three months ended December 31, 2014, the amount of derivative gains or losses representing ineffectiveness, and the amount of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, was not material. 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 that 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.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	3 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Accumulated Other Comprehensive Income	Note 13 — Accumulated Other Comprehensive Income The tables below present changes in AOCI during the three months ended December 31, 2015 and 2014 : Three Months Ended December 31, 2015 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2015 $ (20.4 ) $ 11.2 $ (105.4 ) $ (114.6 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) — 6.8 (30.2 ) (23.4 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.7 (8.5 ) — (7.8 ) Reclassification adjustments tax expense (0.3 ) 3.2 — 2.9 Reclassification adjustments (after-tax) 0.4 (5.3 ) — (4.9 ) Other comprehensive income (loss) attributable to UGI 0.4 1.5 (30.2 ) (28.3 ) AOCI - December 31, 2015 $ (20.0 ) $ 12.7 $ (135.6 ) $ (142.9 ) Three Months Ended December 31, 2014 Postretirement Benefit Plans Derivative Instruments Foreign Currency (a) Total AOCI - September 30, 2014 $ (20.6 ) $ (9.3 ) $ 8.7 $ (21.2 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) — 7.7 (30.5 ) (22.8 ) Amounts reclassified from AOCI and noncontrolling interests: Reclassification adjustments (pre-tax) 1.0 3.6 — 4.6 Reclassification adjustments tax benefit (0.4 ) (1.5 ) — (1.9 ) Reclassification adjustments (after-tax) 0.6 2.1 — 2.7 Other comprehensive income (loss) 0.6 9.8 (30.5 ) (20.1 ) Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners — 1.2 — 1.2 Other comprehensive income (loss) attributable to UGI 0.6 11.0 (30.5 ) (18.9 ) AOCI - December 31, 2014 $ (20.0 ) $ 1.7 $ (21.8 ) $ (40.1 ) (a) See Note 2 relating to correction of prior period error in other comprehensive income. For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 12 .

Segment Information

Segment Information	3 Months Ended
	Dec. 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. As more fully described below, effective October 1, 2015, the composition of our UGI Utilities (formerly Gas Utility) and Energy Services reportable segments changed to include certain operating segments previously included in Corporate & Other. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising UGI France; (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) UGI Utilities; (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.” As a result of changes in the composition of information reported to our chief operating decision maker (“CODM”) associated with our regulated utility operations, effective October 1, 2015, we began including our Electric Utility operating segment with our Gas Utility reportable segment now referred to as “UGI Utilities.” Also, as a result of changes in segment management and reporting for HVAC, effective October 1, 2015, we began including HVAC operating segment within our Energy Services reportable segment. Previously, these two business units, neither of which meet the quantitative threshold for presentation as a reportable segment under GAAP, were included within “Corporate & Other” in our segment information. In accordance with GAAP, prior-period amounts for these reportable segments have been restated to reflect these changes. 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 2015 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 CODM does not consider such items when evaluating the financial performance of our reportable segments. Midstream & Marketing UGI International Total Elim- AmeriGas UGI Energy Electric UGI France Flaga & Corporate Three Months Ended Revenues $ 1,606.6 $ (45.4 ) (c) $ 644.1 $ 198.0 $ 214.8 $ 14.8 $ 408.7 $ 169.5 $ 2.1 Cost of sales $ 734.0 $ (44.5 ) (c) $ 243.2 $ 75.4 $ 151.2 $ 6.0 $ 192.6 $ 110.2 $ (0.1 ) Segment profit: Operating income (loss) $ 305.5 $ 0.1 $ 129.6 $ 48.3 $ 41.3 $ 1.6 $ 68.7 $ 16.4 $ (0.5 ) Loss from equity investees (0.1 ) — — — — — (0.1 ) — — Interest expense (57.9 ) — (41.0 ) (9.5 ) (0.8 ) — (5.6 ) (0.9 ) (0.1 ) Income (loss) before income taxes $ 247.5 $ 0.1 $ 88.6 $ 38.8 $ 40.5 $ 1.6 $ 63.0 $ 15.5 $ (0.6 ) Partnership Adjusted EBITDA (a) $ 177.7 Noncontrolling interests’ net income $ 53.3 $ — $ 57.3 $ — $ — $ — $ 0.1 $ — $ (4.1 ) Depreciation and amortization $ 100.6 $ — $ 49.2 $ 16.7 $ 4.1 $ 3.3 $ 21.6 $ 5.6 $ 0.1 Capital expenditures $ 132.9 $ — $ 28.0 $ 61.5 $ 21.9 $ 0.5 $ 16.3 $ 4.7 $ — As of December 31, 2015 Total assets $ 10,780.4 $ (106.2 ) $ 4,242.6 $ 2,606.3 $ 721.0 $ 279.0 $ 2,378.9 $ 534.8 $ 124.0 Short-term borrowings $ 456.8 $ — $ 182.0 $ 217.7 $ 56.0 $ — $ 1.1 $ — $ — Goodwill $ 2,965.1 $ — $ 1,971.3 $ 182.1 $ 11.5 $ — $ 700.9 $ 99.3 $ — Midstream & Marketing UGI International Total Elim- AmeriGas UGI Energy Electric UGI France Flaga & Corporate Three Months Ended Revenues $ 2,004.6 $ (67.7 ) (c) $ 888.8 $ 287.3 $ 314.1 $ 16.5 $ 337.9 $ 224.6 $ 3.1 Cost of sales $ 1,404.6 $ (67.0 ) (c) $ 462.4 $ 143.1 $ 244.6 $ 8.0 $ 209.3 $ 172.6 $ 231.6 Segment profit: Operating income (loss) $ 83.3 $ — $ 139.7 $ 75.6 $ 46.3 $ (0.7 ) $ 38.4 $ 15.1 $ (231.1 ) Loss from equity investees (1.0 ) — — — — — (1.0 ) — — Interest expense (59.0 ) — (41.0 ) (10.6 ) (0.6 ) — (5.6 ) (1.0 ) (0.2 ) Income (loss) before income taxes $ 23.3 $ — $ 98.7 $ 65.0 $ 45.7 $ (0.7 ) $ 31.8 $ 14.1 $ (231.3 ) Partnership EBITDA (a) $ 188.5 Noncontrolling interests’ net income (loss) $ (33.9 ) $ — $ 66.8 $ — $ — $ — $ 0.1 $ — $ (100.8 ) Depreciation and amortization $ 91.0 $ — $ 49.4 $ 15.4 $ 3.8 $ 2.7 $ 13.3 $ 6.1 $ 0.3 Capital expenditures $ 123.5 $ — $ 30.4 $ 55.0 $ 12.9 $ 6.6 $ 12.1 $ 6.4 $ 0.1 As of December 31, 2014 Total assets $ 10,430.0 $ (92.7 ) $ 4,491.0 $ 2,488.6 $ 728.8 $ 286.4 $ 1,671.5 $ 579.0 $ 277.4 Short-term borrowings $ 458.5 $ — $ 253.0 $ 153.5 $ 43.0 $ — $ — $ 9.0 $ — Goodwill $ 2,806.8 $ — $ 1,949.6 $ 182.1 $ 11.8 $ — $ 575.9 $ 87.4 $ — (a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income: Three Months Ended 2015 2014 Partnership Adjusted EBITDA $ 177.7 $ 188.5 Depreciation and amortization (49.2 ) (49.4 ) Noncontrolling interests (i) 1.1 0.6 Operating income $ 129.6 $ 139.7 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. (b) Corporate & Other results principally comprise (1) net expenses of UGI’s captive general liability insurance company, and (2) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $1.1 and $(229.7) during the three months ended December 31, 2015 and 2014 , respectively. Corporate & Other assets principally comprise cash and short-term investments. (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.

Acquisition of Totalgaz

Acquisition of Totalgaz	3 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisition of Totalgaz	Note 15 — Acquisition of Totalgaz On May 29, 2015 (the “Acquisition Date”), UGI, through its wholly owned indirect subsidiary, UGI France SAS (a Société par actions simplifiée) (“France SAS”), acquired all of the outstanding shares of Totalgaz SAS, a retail distributor of LPG in France. In November 2015, France SAS received €1.1 ( $1.2 ) of cash as a result of the completion of the final working capital amount. The Totalgaz Acquisition nearly doubles our retail LPG distribution business in France and is consistent with our growth strategies, one of which is to grow our core business through acquisitions. The Company has accounted for the Totalgaz Acquisition using the acquisition method. At December 31, 2015 , the allocation of the purchase price is substantially complete except for the valuation of certain liabilities associated with cylinder deposits and amounts related to deferred income tax assets and liabilities. These amounts are preliminary pending the obtaining of additional information. The Company expects to obtain additional information during the measurement period under GAAP of up to one year from the Acquisition Date as necessary to determine the final allocation of the purchase price. Accordingly, the fair value estimates presented below relating to these items are subject to change. The components of the Finagaz purchase price allocation are as follows: Assets acquired: Cash $ 86.8 Accounts receivable (a) 170.3 Prepaid expenses and other current assets 11.0 Property, plant and equipment 375.6 Intangible assets (b) 91.3 Other assets 21.4 Total assets acquired $ 756.4 Liabilities assumed: Accounts payable 109.2 Other current liabilities 103.5 Deferred income taxes 115.8 Other noncurrent liabilities 117.5 Total liabilities assumed $ 446.0 Goodwill 186.2 Net consideration transferred (including working capital adjustments) $ 496.6 (a) Approximates the gross contractual amounts of receivables acquired. (b) Represents $79.3 of customer relationships and $12.0 of tradenames. The excess of the purchase price for the Totalgaz Acquisition over the preliminary fair values of the assets acquired and liabilities assumed has been reflected as goodwill, assigned to the UGI France reportable segment, and results principally from anticipated synergies and value creation resulting from the Company’s combined LPG businesses in France. The goodwill is not deductible for income tax purposes. The Company recognized $3.8 of direct transaction-related costs associated with the Totalgaz Acquisition during the three months ended December 31, 2014 , which costs are reflected primarily in operating and administrative expenses on the Condensed Consolidated Statements of Income. The following table presents unaudited pro forma revenues, net income attributable to UGI Corporation and earnings per share data for the three months ended December 31, 2014 as if the Totalgaz Acquisition had occurred on October 1, 2014. The unaudited pro forma consolidated information reflects the historical results of Totalgaz SAS and its subsidiaries after giving effect to adjustments directly attributable to the transaction, including depreciation, amortization, interest expense, intercompany eliminations and related income tax effects. The unaudited pro forma net income also reflects the effects of the issuance of the €600 term loan under the 2015 Senior Facilities Agreement and the associated repayment of the term loan outstanding under the 2011 Senior Facilities Agreement as if such transactions had occurred on October 1, 2014. Three Months Ended December 31, 2014 As Reported Pro Forma Adjusted Revenues $ 2,004.6 $ 2,184.5 Net income attributable to UGI Corporation $ 34.1 $ 46.6 Earnings per common share attributable to UGI Corporation shareholders: Basic $ 0.20 $ 0.27 Diluted $ 0.19 $ 0.27 The unaudited pro forma consolidated information is not necessarily indicative of the results that would have occurred had the Totalgaz Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results. In connection with the Totalgaz Acquisition, the Company agreed with the French Competition Authority (the “FCA”) to divest certain assets and investments of Totalgaz SAS and certain assets of Antargaz located in France no later than 15 months subsequent to the Acquisition Date. Following the closing of the Totalgaz Acquisition, two competitors in the French LPG distribution market challenged the decision of the FCA. The competitors’ request for interim measures suspending the effectiveness of the agreed remedies was denied by the supreme administrative court (conseil d’etat). Proceedings on the merits are continuing. While UGI cannot predict the final outcome of these proceedings at this time, we believe the FCA and the Company have strong defenses to the claims and intend to vigorously defend against them. For additional information regarding the Totalgaz Acquisition, see Note 4 to the Company’s 2015 Annual Report.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Dec. 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. Shares used in computing basic and diluted earnings per share are as follows: Three Months Ended 2015 2014 Denominator (thousands of shares): Weighted-average common shares outstanding for basic computation 172,862 172,945 Incremental shares issuable for stock options and awards 2,356 2,841 Weighted-average common shares outstanding for diluted computation 175,218 175,786
Derivative 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 occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the 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 on a prospective basis that 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, as appropriate, on the Condensed Consolidated Statements of Income. Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, if any, are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from net investment hedges are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges are included in cash flow from operating activities while cash flows from the currency portion of such hedges are included in the cash flow from financing activities. For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, 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	Adoption of New Accounting Standard Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. We applied this guidance prospectively and, as a result, prior period amounts have not been adjusted. Accounting Standards Not Yet Adopted Debt Issuance Costs. In April 2015, the Financial Accounting Standards Board (“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 (Fiscal 2017). Early adoption is permitted. Entities will apply the new guidance retrospectively to all periods presented. The Company expects to adopt the new guidance effective September 30, 2016. The adoption of the new guidance is not expected to have a material impact on the Company’s financial statements. Consolidation. In February 2015, the FASB issued ASU No. 2015-02, “Amendments to the Consolidation Analysis.” This ASU provides 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. 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 ASC No. 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 entity 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, 2018 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our financial statements.

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Dec. 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 2015 2014 Denominator (thousands of shares): Weighted-average common shares outstanding for basic computation 172,862 172,945 Incremental shares issuable for stock options and awards 2,356 2,841 Weighted-average common shares outstanding for diluted computation 175,218 175,786

Inventories (Tables)

Inventories (Tables)	3 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Components of Inventories	Inventories comprise the following: December 31, September 30, December 31, Non-utility LPG and natural gas $ 148.6 $ 140.7 $ 260.4 Gas Utility natural gas 35.9 37.5 72.4 Materials, supplies and other 62.3 61.7 58.2 Total inventories $ 246.8 $ 239.9 $ 391.0

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	3 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Components of Company's Goodwill and Intangible Assets	Goodwill and intangible assets comprise the following: December 31, September 30, December 31, Goodwill (not subject to amortization) $ 2,965.1 $ 2,953.4 $ 2,806.8 Intangible assets: Customer relationships, noncompete agreements and other $ 764.6 $ 761.1 $ 709.3 Accumulated amortization (292.2 ) (282.4 ) (271.9 ) Intangible assets, net (definite-lived) 472.4 478.7 437.4 Trademarks and tradenames (indefinite-lived) 130.0 131.4 126.3 Total intangible assets, net $ 602.4 $ 610.1 $ 563.7

Utility Regulatory Assets and28

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)	3 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility	The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets: December 31, September 30, December 31, Regulatory assets: Income taxes recoverable $ 117.4 $ 115.9 $ 111.1 Underfunded pension and postretirement plans 138.3 140.8 107.8 Environmental costs 17.6 20.0 14.7 Deferred fuel and power costs — — 16.7 Removal costs, net 22.3 21.2 17.6 Other 6.2 6.3 2.7 Total regulatory assets $ 301.8 $ 304.2 $ 270.6 Regulatory liabilities (a): Postretirement benefits $ 20.3 $ 20.0 $ 19.0 Deferred fuel and power refunds 28.1 36.6 — State tax benefits—distribution system repairs 13.7 13.3 10.3 Other 1.1 1.1 3.6 Total regulatory liabilities $ 63.2 $ 71.0 $ 32.9 (a) Regulatory liabilities are recorded in other current and other noncurrent liabilities in the Condensed Consolidated Balance Sheets.

Defined Benefit Pension and O29

Defined Benefit Pension and Other Postretirement Plans (Tables)	3 Months Ended
	Dec. 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 December 31, 2015 2014 2015 2014 Service cost $ 2.5 $ 2.4 $ 0.2 $ 0.2 Interest cost 6.6 6.3 0.2 0.2 Expected return on assets (8.0 ) (7.9 ) (0.2 ) (0.2 ) Amortization of: Prior service cost (benefit) 0.1 0.1 (0.1 ) (0.1 ) Actuarial loss 2.7 2.5 — — Net benefit cost 3.9 3.4 0.1 0.1 Change in associated regulatory liabilities — — 0.9 0.9 Net expense $ 3.9 $ 3.4 $ 1.0 $ 1.0

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	3 Months Ended
	Dec. 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 December 31, 2015 , September 30, 2015 and December 31, 2014 : Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2015: Derivative instruments: Assets: Commodity contracts $ 19.7 $ 10.8 $ — $ 30.5 Foreign currency contracts $ — $ 25.4 $ — $ 25.4 Interest rate contracts $ — $ 0.6 $ — $ 0.6 Cross-currency swaps $ — $ 1.9 $ — $ 1.9 Liabilities: Commodity contracts $ (70.5 ) $ (97.5 ) $ — $ (168.0 ) Interest rate contracts $ — $ (9.8 ) $ — $ (9.8 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 31.7 $ — $ — $ 31.7 September 30, 2015: Derivative instruments: Assets: Commodity contracts $ 17.4 $ 11.6 $ — $ 29.0 Foreign currency contracts $ — $ 29.1 $ — $ 29.1 Cross-currency swaps $ — $ 0.4 $ — $ 0.4 Liabilities: Commodity contracts $ (70.0 ) $ (99.0 ) $ — $ (169.0 ) Foreign currency contracts $ — $ (0.1 ) $ — $ (0.1 ) Interest rate contracts $ — $ (10.8 ) $ — $ (10.8 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 30.3 $ — $ — $ 30.3 December 31, 2014: Derivative instruments: Assets: Commodity contracts $ 14.1 $ 26.1 $ — $ 40.2 Foreign currency contracts $ — $ 18.7 $ — $ 18.7 Interest rate contracts $ — $ 0.1 $ — $ 0.1 Cross-currency swaps $ — $ 4.3 $ — $ 4.3 Liabilities: Commodity contracts $ (69.4 ) $ (228.5 ) $ — $ (297.9 ) Interest rate contracts $ — $ (17.0 ) $ — $ (17.0 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 31.4 $ — $ — $ 31.4 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.

Derivative Instruments and He31

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Dec. 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, as well as the effects of offsetting, as of December 31, 2015 and 2014 : December 31, December 31, Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 25.4 $ 18.7 Cross-currency contracts 1.9 4.3 Interest rate contracts 0.6 0.1 27.9 23.1 Derivatives subject to PGC and DS mechanisms: Commodity contracts 0.2 0.2 Derivatives not designated as hedging instruments: Commodity contracts 30.3 40.0 Total derivative assets - gross 58.4 63.3 Gross amounts offset in the balance sheet (15.6 ) (27.5 ) Total derivative assets - net $ 42.8 $ 35.8 Derivative liabilities: Derivatives designated as hedging instruments: Interest rate contracts $ (9.8 ) $ (17.0 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (6.3 ) (9.4 ) Derivatives not designated as hedging instruments: Commodity contracts (161.7 ) (288.5 ) Total derivative liabilities - gross (177.8 ) (314.9 ) Gross amounts offset in the balance sheet 15.6 27.5 Cash collateral pledged 5.5 90.5 Total derivative liabilities - net $ (156.7 ) $ (196.9 )
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 months ended December 31, 2015 and 2014 : Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Three Months Ended December 31, 2015 2014 2015 2014 Cash Flow Hedges: Commodity contracts $ — $ — $ — $ (2.4 ) Cost of sales Foreign currency contracts 5.4 8.7 9.1 2.7 Cost of sales Cross-currency contracts — 2.1 — — Interest expense/other operating income, net Interest rate contracts 5.6 0.8 (0.6 ) (3.9 ) Interest expense Total $ 11.0 $ 11.6 $ 8.5 $ (3.6 ) Gain (Loss) Location of Gain (Loss) Three Months Ended December 31, 2015 2014 Derivatives Not Designated as Hedging Instruments: Commodity contracts $ (46.2 ) $ (292.5 ) Cost of sales Commodity contracts 1.6 3.8 Revenues Commodity contracts (0.1 ) (0.5 ) Operating expenses/other Total $ (44.7 ) $ (289.2 )

Accumulated Other Comprehensi32

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income	The tables below present changes in AOCI during the three months ended December 31, 2015 and 2014 : Three Months Ended December 31, 2015 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2015 $ (20.4 ) $ 11.2 $ (105.4 ) $ (114.6 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) — 6.8 (30.2 ) (23.4 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.7 (8.5 ) — (7.8 ) Reclassification adjustments tax expense (0.3 ) 3.2 — 2.9 Reclassification adjustments (after-tax) 0.4 (5.3 ) — (4.9 ) Other comprehensive income (loss) attributable to UGI 0.4 1.5 (30.2 ) (28.3 ) AOCI - December 31, 2015 $ (20.0 ) $ 12.7 $ (135.6 ) $ (142.9 ) Three Months Ended December 31, 2014 Postretirement Benefit Plans Derivative Instruments Foreign Currency (a) Total AOCI - September 30, 2014 $ (20.6 ) $ (9.3 ) $ 8.7 $ (21.2 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) — 7.7 (30.5 ) (22.8 ) Amounts reclassified from AOCI and noncontrolling interests: Reclassification adjustments (pre-tax) 1.0 3.6 — 4.6 Reclassification adjustments tax benefit (0.4 ) (1.5 ) — (1.9 ) Reclassification adjustments (after-tax) 0.6 2.1 — 2.7 Other comprehensive income (loss) 0.6 9.8 (30.5 ) (20.1 ) Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners — 1.2 — 1.2 Other comprehensive income (loss) attributable to UGI 0.6 11.0 (30.5 ) (18.9 ) AOCI - December 31, 2014 $ (20.0 ) $ 1.7 $ (21.8 ) $ (40.1 ) (a) See Note 2 relating to correction of prior period error in other comprehensive income.

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Schedule of Segment Reporting Information	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 2015 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 CODM does not consider such items when evaluating the financial performance of our reportable segments. Midstream & Marketing UGI International Total Elim- AmeriGas UGI Energy Electric UGI France Flaga & Corporate Three Months Ended Revenues $ 1,606.6 $ (45.4 ) (c) $ 644.1 $ 198.0 $ 214.8 $ 14.8 $ 408.7 $ 169.5 $ 2.1 Cost of sales $ 734.0 $ (44.5 ) (c) $ 243.2 $ 75.4 $ 151.2 $ 6.0 $ 192.6 $ 110.2 $ (0.1 ) Segment profit: Operating income (loss) $ 305.5 $ 0.1 $ 129.6 $ 48.3 $ 41.3 $ 1.6 $ 68.7 $ 16.4 $ (0.5 ) Loss from equity investees (0.1 ) — — — — — (0.1 ) — — Interest expense (57.9 ) — (41.0 ) (9.5 ) (0.8 ) — (5.6 ) (0.9 ) (0.1 ) Income (loss) before income taxes $ 247.5 $ 0.1 $ 88.6 $ 38.8 $ 40.5 $ 1.6 $ 63.0 $ 15.5 $ (0.6 ) Partnership Adjusted EBITDA (a) $ 177.7 Noncontrolling interests’ net income $ 53.3 $ — $ 57.3 $ — $ — $ — $ 0.1 $ — $ (4.1 ) Depreciation and amortization $ 100.6 $ — $ 49.2 $ 16.7 $ 4.1 $ 3.3 $ 21.6 $ 5.6 $ 0.1 Capital expenditures $ 132.9 $ — $ 28.0 $ 61.5 $ 21.9 $ 0.5 $ 16.3 $ 4.7 $ — As of December 31, 2015 Total assets $ 10,780.4 $ (106.2 ) $ 4,242.6 $ 2,606.3 $ 721.0 $ 279.0 $ 2,378.9 $ 534.8 $ 124.0 Short-term borrowings $ 456.8 $ — $ 182.0 $ 217.7 $ 56.0 $ — $ 1.1 $ — $ — Goodwill $ 2,965.1 $ — $ 1,971.3 $ 182.1 $ 11.5 $ — $ 700.9 $ 99.3 $ — Midstream & Marketing UGI International Total Elim- AmeriGas UGI Energy Electric UGI France Flaga & Corporate Three Months Ended Revenues $ 2,004.6 $ (67.7 ) (c) $ 888.8 $ 287.3 $ 314.1 $ 16.5 $ 337.9 $ 224.6 $ 3.1 Cost of sales $ 1,404.6 $ (67.0 ) (c) $ 462.4 $ 143.1 $ 244.6 $ 8.0 $ 209.3 $ 172.6 $ 231.6 Segment profit: Operating income (loss) $ 83.3 $ — $ 139.7 $ 75.6 $ 46.3 $ (0.7 ) $ 38.4 $ 15.1 $ (231.1 ) Loss from equity investees (1.0 ) — — — — — (1.0 ) — — Interest expense (59.0 ) — (41.0 ) (10.6 ) (0.6 ) — (5.6 ) (1.0 ) (0.2 ) Income (loss) before income taxes $ 23.3 $ — $ 98.7 $ 65.0 $ 45.7 $ (0.7 ) $ 31.8 $ 14.1 $ (231.3 ) Partnership EBITDA (a) $ 188.5 Noncontrolling interests’ net income (loss) $ (33.9 ) $ — $ 66.8 $ — $ — $ — $ 0.1 $ — $ (100.8 ) Depreciation and amortization $ 91.0 $ — $ 49.4 $ 15.4 $ 3.8 $ 2.7 $ 13.3 $ 6.1 $ 0.3 Capital expenditures $ 123.5 $ — $ 30.4 $ 55.0 $ 12.9 $ 6.6 $ 12.1 $ 6.4 $ 0.1 As of December 31, 2014 Total assets $ 10,430.0 $ (92.7 ) $ 4,491.0 $ 2,488.6 $ 728.8 $ 286.4 $ 1,671.5 $ 579.0 $ 277.4 Short-term borrowings $ 458.5 $ — $ 253.0 $ 153.5 $ 43.0 $ — $ — $ 9.0 $ — Goodwill $ 2,806.8 $ — $ 1,949.6 $ 182.1 $ 11.8 $ — $ 575.9 $ 87.4 $ — (a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income: Three Months Ended 2015 2014 Partnership Adjusted EBITDA $ 177.7 $ 188.5 Depreciation and amortization (49.2 ) (49.4 ) Noncontrolling interests (i) 1.1 0.6 Operating income $ 129.6 $ 139.7 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. (b) Corporate & Other results principally comprise (1) net expenses of UGI’s captive general liability insurance company, and (2) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $1.1 and $(229.7) during the three months ended December 31, 2015 and 2014 , respectively. Corporate & Other assets principally comprise cash and short-term investments. (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.

Acquisition of Totalgaz (Tables

Acquisition of Totalgaz (Tables)	3 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Schedule of Preliminary Purchase Price Allocation	The components of the Finagaz purchase price allocation are as follows: Assets acquired: Cash $ 86.8 Accounts receivable (a) 170.3 Prepaid expenses and other current assets 11.0 Property, plant and equipment 375.6 Intangible assets (b) 91.3 Other assets 21.4 Total assets acquired $ 756.4 Liabilities assumed: Accounts payable 109.2 Other current liabilities 103.5 Deferred income taxes 115.8 Other noncurrent liabilities 117.5 Total liabilities assumed $ 446.0 Goodwill 186.2 Net consideration transferred (including working capital adjustments) $ 496.6 (a) Approximates the gross contractual amounts of receivables acquired. (b) Represents $79.3 of customer relationships and $12.0 of tradenames.
Schedule of Pro Forma Information	The following table presents unaudited pro forma revenues, net income attributable to UGI Corporation and earnings per share data for the three months ended December 31, 2014 as if the Totalgaz Acquisition had occurred on October 1, 2014. The unaudited pro forma consolidated information reflects the historical results of Totalgaz SAS and its subsidiaries after giving effect to adjustments directly attributable to the transaction, including depreciation, amortization, interest expense, intercompany eliminations and related income tax effects. The unaudited pro forma net income also reflects the effects of the issuance of the €600 term loan under the 2015 Senior Facilities Agreement and the associated repayment of the term loan outstanding under the 2011 Senior Facilities Agreement as if such transactions had occurred on October 1, 2014. Three Months Ended December 31, 2014 As Reported Pro Forma Adjusted Revenues $ 2,004.6 $ 2,184.5 Net income attributable to UGI Corporation $ 34.1 $ 46.6 Earnings per common share attributable to UGI Corporation shareholders: Basic $ 0.20 $ 0.27 Diluted $ 0.19 $ 0.27

Nature of Operations (Details)

Nature of Operations (Details) $ in Millions	3 Months Ended
	Dec. 31, 2015USD ($)county	Dec. 31, 2014USD ($)
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%
General public as limited partner interests in AmeriGas Partners	73.70%
General Partner incentive distribution | $	$ 8.6	$ 6.5
Number of counties of operation | county	1

Summary of Significant Accoun36

Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Denominator (thousands of shares):
Weighted-average common shares outstanding for basic computation	172,862	172,945
Incremental shares issuable for stock options and awards	2,356	2,841
Weighted-average common shares outstanding for diluted computation	175,218	175,786

Summary of Significant Accoun37

Summary of Significant Accounting Policies (Details) $ in Millions	3 Months Ended
	Dec. 31, 2014USD ($)
Accounting Policies [Abstract]
Decrease in other comprehensive (loss) income	$ 14.4

Inventories (Details)

Inventories (Details) - UGI Utilities $ in Millions	3 Months Ended
	Dec. 31, 2015USD ($)storage_agreementBcf	Sep. 30, 2015USD ($)Bcf	Dec. 31, 2014USD ($)Bcf
Inventory
SCAA contract term (in years)	3 years
Storage Contract Administrative Agreements
Inventory
Number of storage agreements | storage_agreement	2
Volume of gas storage inventories released under SCAAs with non-affiliates (in cubic feet) | Bcf	3.8	4	3.4
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $	$ 9.4	$ 9.8	$ 14.4

Inventories - Components of Inv

Inventories - Components of Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Inventory
Inventory, net	$ 246.8	$ 239.9	$ 391
Non-utility LPG and Natural Gas
Inventory
Inventory, net	148.6	140.7	260.4
Gas Utility Natural Gas
Inventory
Inventory, net	35.9	37.5	72.4
Materials, Supplies and Other
Inventory
Inventory, net	$ 62.3	$ 61.7	$ 58.2

Goodwill and Intangible Asset40

Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense of intangible assets	$ 12.8	$ 13
Remainder of Fiscal 2016	39
Fiscal 2,017	46.1
Fiscal 2,018	44.6
Fiscal 2,019	42.9
Fiscal 2,020	$ 41.6

Goodwill and Intangible Asset41

Goodwill and Intangible Assets - Components of Company's Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill (not subject to amortization)	$ 2,965.1	$ 2,953.4	$ 2,806.8	[1]
Intangible assets:
Customer relationships, noncompete agreements and other	764.6	761.1	709.3
Accumulated amortization	(292.2)	(282.4)	(271.9)
Intangible assets, net (definite-lived)	472.4	478.7	437.4
Trademarks and tradenames (indefinite-lived)	130	131.4	126.3
Total intangible assets, net	$ 602.4	$ 610.1	$ 563.7
[1]	Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.

Utility Regulatory Assets and42

Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) - USD ($) $ in Millions	Jan. 19, 2016	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Gas Utility
Regulatory Assets
Fair value of unrealized gains (losses)		$ (4.5)	$ (3.3)	$ (6.8)
Electric Utility Electric Supply Contracts
Regulatory Assets
Fair value of unrealized gains (losses)		$ (0.5)	$ (0.5)	$ (2.4)
UGI Utilities | Pennsylvania Public Utility Commission | Subsequent Event
Regulatory Assets
Requested operating revenue increase	$ 58.6
Estimated time period for regulatory approval (in months)	9 months

Utility Regulatory Assets and43

Utility Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility (Details) - USD ($) $ in Millions		Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Regulatory Assets And Liabilities
Regulatory assets		$ 301.8	$ 304.2	$ 270.6
Regulatory liabilities	[1]	63.2	71	32.9
Postretirement Benefits
Regulatory Assets And Liabilities
Regulatory liabilities	[1]	20.3	20	19
Deferred Fuel and Power Refunds
Regulatory Assets And Liabilities
Regulatory liabilities	[1]	28.1	36.6	0
State Tax Benefits—Distribution System Repairs
Regulatory Assets And Liabilities
Regulatory liabilities	[1]	13.7	13.3	10.3
Other
Regulatory Assets And Liabilities
Regulatory liabilities	[1]	1.1	1.1	3.6
Income Taxes Recoverable
Regulatory Assets And Liabilities
Regulatory assets		117.4	115.9	111.1
Underfunded Pension and Postretirement Plans
Regulatory Assets And Liabilities
Regulatory assets		138.3	140.8	107.8
Environmental Costs
Regulatory Assets And Liabilities
Regulatory assets		17.6	20	14.7
Deferred Fuel and Power Costs
Regulatory Assets And Liabilities
Regulatory assets		0	0	16.7
Removal Costs, Net
Regulatory Assets And Liabilities
Regulatory assets		22.3	21.2	17.6
Other
Regulatory Assets And Liabilities
Regulatory assets		$ 6.2	$ 6.3	$ 2.7
[1]	Regulatory liabilities are recorded in other current and other noncurrent liabilities in the Condensed Consolidated Balance Sheets.

Energy Services Accounts Rece44

Energy Services Accounts Receivable Securitization Facility (Details) - USD ($)	3 Months Ended		6 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Oct. 31, 2016	Apr. 30, 2016
Energy Services
Accounts, Notes, Loans and Financing Receivable
Sale of trade receivables	$ 199,300,000	$ 286,400,000
Energy Services Funding Corporation
Accounts, Notes, Loans and Financing Receivable
Sale of undivided interests in its trade receivables to the commercial paper conduit	61,500,000	105,000,000
Outstanding balance of trade receivables	55,400,000	96,500,000
Outstanding balance of trade receivables sold	$ 26,000,000	$ 43,000,000
Forecast | Maximum
Accounts, Notes, Loans and Financing Receivable
Receivables facility			$ 75,000,000	$ 150,000,000

Debt (Details)

Debt (Details) $ in Millions	1 Months Ended
	Oct. 31, 2015EUR (€)	Dec. 31, 2015EUR (€)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Line of Credit Facility
Long-term debt | $			$ 3,609.3	$ 3,488.3
Flaga | Line of Credit | Flaga Multi-Currency Working Capital Facility
Line of Credit Facility
Maximum borrowing capacity		€ 46,000,000
Flaga | Line of Credit | Flaga Credit Facility Agreement
Line of Credit Facility
Maximum borrowing capacity	€ 100,800,000
Flaga | Line of Credit | Revolving Credit Facility | Flaga Credit Facility Agreement
Line of Credit Facility
Maximum borrowing capacity	€ 25,000,000
Facility fee on unused balance	30.00%
Flaga | Line of Credit | Revolving Credit Facility | Flaga Credit Facility Agreement | EURIBOR | Minimum
Line of Credit Facility
Basis spread on variable rate	1.45%
Flaga | Line of Credit | Revolving Credit Facility | Flaga Credit Facility Agreement | EURIBOR | Maximum
Line of Credit Facility
Basis spread on variable rate	3.65%
Flaga | Overdraft Facility | Flaga Credit Facility Agreement
Line of Credit Facility
Maximum borrowing capacity	€ 5,000,000
Flaga | Guarantee Facility | Flaga Credit Facility Agreement
Line of Credit Facility
Maximum borrowing capacity	25,000,000
Flaga | Term Loan | Flaga Credit Facility Agreement
Line of Credit Facility
Maximum borrowing capacity	€ 45,800,000
Flaga | Term Loan | Flaga Credit Facility Agreement | Three-Month EURIBOR | Minimum
Line of Credit Facility
Basis spread on variable rate	0.40%
Flaga | Term Loan | Flaga Credit Facility Agreement | Three-Month EURIBOR | Maximum
Line of Credit Facility
Basis spread on variable rate	1.80%
Flaga | Term Loan | Flaga Term Loan Due October 2016
Line of Credit Facility
Long-term debt		19,100,000
Flaga | Term Loan | Flaga Term Loan Due August 2016
Line of Credit Facility
Long-term debt		€ 26,700,000
Interest Rate Swap | Through September 2016 | Flaga | Term Loan | Flaga Credit Facility Agreement | Three-Month EURIBOR
Line of Credit Facility
Underlying EURIBOR fixed rate	2.18%
Interest Rate Swap | October 2016 Through October 2020 | Flaga | Term Loan | Flaga Credit Facility Agreement | Three-Month EURIBOR
Line of Credit Facility
Underlying EURIBOR fixed rate	0.23%

Commitments and Contingencies (

Commitments and Contingencies (Details)	3 Months Ended	6 Months Ended
	Dec. 31, 2015USD ($)lb	Oct. 31, 2014lawsuit	Dec. 31, 2014USD ($)
Commitments and Contingencies
Class action lawsuits (more than 35) | lawsuit		35
Amount of propane in cylinders before reduction | lb	17
Amount of propane in cylinders after reduction | lb	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	$ 1,800,000
Environmental Matters | PNG MGP
Commitments and Contingencies
Environmental expenditures cap during calendar year	$ 1,100,000
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	$ 11,700,000		$ 11,200,000

Defined Benefit Pension and O47

Defined Benefit Pension and Other Postretirement Plans (Details) - USD ($)	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contribution made to Pension and Post-retirement Plans	$ 2,500,000	$ 2,800,000
Expected contribution to pension plan during remainder of fiscal year	7,400,000
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contribution made to Pension and Post-retirement Plans	$ 0	$ 0

Defined Benefit Pension and O48

Defined Benefit Pension and Other Postretirement Plans - Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 2.5	$ 2.4
Interest cost	6.6	6.3
Expected return on assets	(8)	(7.9)
Amortization of:
Prior service cost (benefit)	0.1	0.1
Actuarial loss	2.7	2.5
Net benefit cost	3.9	3.4
Change in associated regulatory liabilities	0	0
Net expense	3.9	3.4
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	0.2	0.2
Interest cost	0.2	0.2
Expected return on assets	(0.2)	(0.2)
Amortization of:
Prior service cost (benefit)	(0.1)	(0.1)
Actuarial loss	0	0
Net benefit cost	0.1	0.1
Change in associated regulatory liabilities	0.9	0.9
Net expense	$ 1	$ 1

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Carrying value of long-term debt	$ 3,609.3	$ 3,488.3
Estimated fair value of long-term debt	$ 3,590.4	$ 3,640.7

Fair Value Measurements - Finan

Fair Value Measurements - Financial Assets and Liabilities that are Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions		Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		$ 58.4		$ 63.3
Derivative financial instruments, liabilities		(177.8)		(314.9)
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	[1]	31.7	$ 30.3	31.4
Fair Value, Measurements, Recurring | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		30.5	29	40.2
Derivative financial instruments, liabilities		(168)	(169)	(297.9)
Fair Value, Measurements, Recurring | Foreign Currency Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		25.4	29.1	18.7
Derivative financial instruments, liabilities			(0.1)
Fair Value, Measurements, Recurring | Interest Rate Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0.6		0.1
Derivative financial instruments, liabilities		(9.8)	(10.8)	(17)
Fair Value, Measurements, Recurring | Cross-Currency Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		1.9	0.4	4.3
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	[1]	31.7	30.3	31.4
Fair Value, Measurements, Recurring | Level 1 | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		19.7	17.4	14.1
Derivative financial instruments, liabilities		(70.5)	(70)	(69.4)
Fair Value, Measurements, Recurring | Level 1 | Foreign Currency Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0	0	0
Derivative financial instruments, liabilities			0
Fair Value, Measurements, Recurring | 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
Fair Value, Measurements, Recurring | Level 1 | Cross-Currency Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0	0	0
Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	[1]	0	0	0
Fair Value, Measurements, Recurring | Level 2 | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		10.8	11.6	26.1
Derivative financial instruments, liabilities		(97.5)	(99)	(228.5)
Fair Value, Measurements, Recurring | Level 2 | Foreign Currency Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		25.4	29.1	18.7
Derivative financial instruments, liabilities			(0.1)
Fair Value, Measurements, Recurring | Level 2 | Interest Rate Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0.6		0.1
Derivative financial instruments, liabilities		(9.8)	(10.8)	(17)
Fair Value, Measurements, Recurring | Level 2 | Cross-Currency Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		1.9	0.4	4.3
Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	[1]	0	0	0
Fair Value, Measurements, Recurring | Level 3 | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0	0	0
Derivative financial instruments, liabilities		0	0	0
Fair Value, Measurements, Recurring | Level 3 | Foreign Currency Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0	0	0
Derivative financial instruments, liabilities			0
Fair Value, Measurements, Recurring | 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
Fair Value, Measurements, Recurring | Level 3 | Cross-Currency Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		$ 0	$ 0	$ 0
[1]	Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.

Derivative Instruments and He51

Derivative Instruments and Hedging Activities (Details) kWh in Millions, gal in Millions, MMBTU in Millions	3 Months Ended
	Dec. 31, 2015USD ($)kWhMMBTUgal	Dec. 31, 2014EUR (€)kWhMMBTUgal	Dec. 31, 2015EUR (€)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2014USD ($)
Derivative
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months				$ 2,200,000
Amount of net gains associated with currency rate risk to be reclassified into earnings during the next 12 months				16,000,000
Restricted cash				55,500,000	$ 69,300,000	$ 54,600,000
Gain (loss) on ineffectiveness and excluded derivatives recognized in income	$ 3,400,000
Commodity Contracts
Derivative
Amounts remaining in AOCI related to commodity derivative hedges				0
Interest Rate Swap
Derivative
Notional amount (in currency) | €		€ 401,100,000	€ 645,800,000
Interest Rate Protection Agreements
Derivative
Notional amount (in currency)				290,000,000		0
Lower remaining maturity range (in years)	10 years
Higher remaining maturity range (in years)	30 years
Foreign Currency Contracts
Derivative
Maximum length of time hedged in price risk cash flow hedges (in months)	39 months
Notional amount (in currency)		€ 0	€ 0	280,500,000		225,800,000
Cross Currency Contracts
Derivative
Notional amount (in currency)				$ 59,100,000		$ 52,000,000
Propane | Commodity Contracts
Derivative
Volume of LPG commodity derivatives (in gallons) | gal	481.9	429.6
Maximum length of time hedging exposure to LPG commodity price risk (in months)	45 months
Propane | Natural Gas Storage and Propane Storage NYMEX Contracts
Derivative
Volume of LPG commodity derivatives (in gallons) | gal	1.8	2.6
Natural Gas | Gas Basis Swap Contracts
Derivative
Notional amount (energy measure) | MMBTU	86.1	37.1
Natural Gas | Natural Gas Futures, Forward And Pipeline Contracts
Derivative
Notional amount (energy measure) | MMBTU	104.9	127.8
Maximum length of time hedged in price risk cash flow hedges (in months)	39 months
Natural Gas | Natural Gas Storage and Propane Storage NYMEX Contracts
Derivative
Notional amount (energy measure) | MMBTU	1.6	0.6
Natural Gas | Gas Utility | Commodity Contracts
Derivative
Notional amount (energy measure) | MMBTU	12.4	11.2
Maximum length of time hedged in price risk cash flow hedges (in months)	9 months
Electricity | Commodity Contracts | Long
Derivative
Notional amount (energy measure) | kWh	547.8	350
Maximum length of time hedged in price risk cash flow hedges (in months)	39 months
Electricity | Commodity Contracts | Short
Derivative
Notional amount (energy measure) | kWh	252.9	184.1
Maximum length of time hedged in price risk cash flow hedges (in months)	37 months
Electricity | Electric Utility | Commodity Contracts
Derivative
Notional amount (energy measure) | kWh	333.3	486.2
Maximum length of time hedged in price risk cash flow hedges (in months)	11 months
Electricity | Electric Utility | Financial Transmission Rights
Derivative
Notional amount (energy measure) | kWh	223.7
Maximum length of time hedged in price risk cash flow hedges (in months)	5 months
Electricity | Electric Utility | NYISO Capacity Swap Contracts
Derivative
Notional amount (energy measure) | kWh		331.8
Maximum length of time hedged in price risk cash flow hedges (in months)	5 months

Derivative Instruments and He52

Derivative Instruments and Hedging Activities - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative assets:
Derivative asset, gross	$ 58.4	$ 63.3
Gross amounts offset in the balance sheet	(15.6)	(27.5)
Total derivative assets - net	42.8	35.8
Derivative liabilities:
Derivative liability, gross	(177.8)	(314.9)
Gross amounts offset in the balance sheet	15.6	27.5
Cash collateral pledged	5.5	90.5
Total derivative liabilities - net	(156.7)	(196.9)
Designated as Hedging Instrument
Derivative assets:
Derivative asset, gross	27.9	23.1
Designated as Hedging Instrument | Foreign Currency Contracts
Derivative assets:
Derivative asset, gross	25.4	18.7
Designated as Hedging Instrument | Cross Currency Contracts
Derivative assets:
Derivative asset, gross	1.9	4.3
Designated as Hedging Instrument | Interest Rate Contracts
Derivative assets:
Derivative asset, gross	0.6	0.1
Derivative liabilities:
Derivative liability, gross	(9.8)	(17)
Derivatives Subject To PGC and DS Mechanisms | Commodity Contracts
Derivative assets:
Derivative asset, gross	0.2	0.2
Derivative liabilities:
Derivative liability, gross	(6.3)	(9.4)
Derivatives Not Designated as Hedging Instruments | Commodity Contracts
Derivative assets:
Derivative asset, gross	30.3	40
Derivative liabilities:
Derivative liability, gross	$ (161.7)	$ (288.5)

Derivative Instruments and He53

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	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivatives Not Designated as Hedging Instruments
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	$ (44.7)	$ (289.2)
Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI	11	11.6
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	8.5	(3.6)
Commodity Contracts | Derivatives Not Designated as Hedging Instruments | Cost of Sales
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	(46.2)	(292.5)
Commodity Contracts | Derivatives Not Designated as Hedging Instruments | Revenues
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	1.6	3.8
Commodity Contracts | Derivatives Not Designated as Hedging Instruments | Operating Expenses / Other Operating Income, Net
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	(0.1)	(0.5)
Commodity Contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI	0	0
Commodity Contracts | Cash Flow Hedges | Cost of Sales
Derivative Instruments, Gain (Loss)
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	0	(2.4)
Foreign Currency Contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI	5.4	8.7
Foreign Currency Contracts | Cash Flow Hedges | Cost of Sales
Derivative Instruments, Gain (Loss)
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	9.1	2.7
Cross Currency Contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI	0	2.1
Cross Currency Contracts | Cash Flow Hedges | Interest Expense / Other Operating Income, Net
Derivative Instruments, Gain (Loss)
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	0	0
Interest Rate Contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI	5.6	0.8
Interest Rate Contracts | Cash Flow Hedges | Interest Expense
Derivative Instruments, Gain (Loss)
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	$ (0.6)	$ (3.9)

Accumulated Other Comprehensi54

Accumulated Other Comprehensive Income - Schedule of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions		3 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
AOCI Attributable to Parent, Net of Tax
AOCI - balance at beginning of period		$ (114.6)	$ (21.2)
Other comprehensive income (loss) before reclassification adjustments (after-tax)		(23.4)	(22.8)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)		(7.8)	4.6
Reclassification adjustments tax benefit		2.9	(1.9)
Reclassification adjustments (after-tax)		(4.9)	2.7
Other comprehensive (loss) income		(28.3)	(20.1)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners			1.2
Other comprehensive income (loss) attributable to UGI		(28.3)	(18.9)
AOCI - balance at end of period		(142.9)	(40.1)
Postretirement Benefit Plans
AOCI Attributable to Parent, Net of Tax
AOCI - balance at beginning of period		(20.4)	(20.6)
Other comprehensive income (loss) before reclassification adjustments (after-tax)		0	0
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)		0.7	1
Reclassification adjustments tax benefit		(0.3)	(0.4)
Reclassification adjustments (after-tax)		0.4	0.6
Other comprehensive (loss) income			0.6
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners			0
Other comprehensive income (loss) attributable to UGI		0.4	0.6
AOCI - balance at end of period		(20)	(20)
Derivative Instruments
AOCI Attributable to Parent, Net of Tax
AOCI - balance at beginning of period		11.2	(9.3)
Other comprehensive income (loss) before reclassification adjustments (after-tax)		6.8	7.7
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)		(8.5)	3.6
Reclassification adjustments tax benefit		3.2	(1.5)
Reclassification adjustments (after-tax)		(5.3)	2.1
Other comprehensive (loss) income			9.8
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners			1.2
Other comprehensive income (loss) attributable to UGI		1.5	11
AOCI - balance at end of period		12.7	1.7
Foreign Currency
AOCI Attributable to Parent, Net of Tax
AOCI - balance at beginning of period		(105.4)	8.7	[1]
Other comprehensive income (loss) before reclassification adjustments (after-tax)		(30.2)	(30.5)	[1]
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)		0	0	[1]
Reclassification adjustments tax benefit		0	0	[1]
Reclassification adjustments (after-tax)		0	0	[1]
Other comprehensive (loss) income	[1]		(30.5)
Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	[1]		0
Other comprehensive income (loss) attributable to UGI		(30.2)	(30.5)	[1]
AOCI - balance at end of period		$ (135.6)	$ (21.8)	[1]
[1]	See Note 2 relating to correction of prior period error in other comprehensive income.

Segment Information (Details)

Segment Information (Details)	3 Months Ended
	Dec. 31, 2015segment
Segment Reporting [Abstract]
Number of reportable segments (in reportable segments)	6

Segment Information - Schedule

Segment Information - Schedule of Segment Reporting Information (Details) - USD ($) $ in Millions		3 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Sep. 30, 2015
Segment Reporting Information
Revenues		$ 1,606.6	$ 2,004.6	[1]
Cost of sales		734	1,404.6	[1]
Segment profit:
Operating income (loss)		305.5	83.3	[1]
Loss from equity investees		(0.1)	(1)	[1]
Interest expense		(57.9)	(59)	[1]
Income before income taxes		247.5	23.3	[1]
Noncontrolling interests’ net income (loss)		53.3	(33.9)	[1]
Depreciation and amortization		100.6	91	[1]
Capital expenditures		132.9	123.5	[1]
Total assets		10,780.4	10,430	[1]	$ 10,546.6
Short-term borrowings		456.8	458.5	[1]	189.9
Goodwill		2,965.1	2,806.8	[1]	$ 2,953.4
AmeriGas Propane
Segment profit:
Operating income (loss)		129.6	139.7
Partnership Adjusted EBITDA		177.7	188.5
Depreciation and amortization		49.2	49.4
Intersegment Eliminations
Segment Reporting Information
Revenues	[2]	(45.4)	(67.7)	[1]
Cost of sales	[2]	(44.5)	(67)	[1]
Segment profit:
Operating income (loss)		0.1	0	[1]
Loss from equity investees		0	0	[1]
Interest expense		0	0	[1]
Income before income taxes		0.1	0	[1]
Noncontrolling interests’ net income (loss)		0	0	[1]
Depreciation and amortization		0	0	[1]
Capital expenditures		0	0	[1]
Total assets		(106.2)	(92.7)	[1]
Short-term borrowings		0	0	[1]
Goodwill		0	0	[1]
Operating Segments | AmeriGas Propane
Segment Reporting Information
Revenues		644.1	888.8	[1]
Cost of sales		243.2	462.4	[1]
Segment profit:
Operating income (loss)		129.6	139.7	[1]
Loss from equity investees		0	0	[1]
Interest expense		(41)	(41)	[1]
Income before income taxes		88.6	98.7	[1]
Partnership Adjusted EBITDA	[3]	177.7	188.5	[1]
Noncontrolling interests’ net income (loss)		57.3	66.8	[1]
Depreciation and amortization		49.2	49.4	[1]
Capital expenditures		28	30.4	[1]
Total assets		4,242.6	4,491	[1]
Short-term borrowings		182	253	[1]
Goodwill		1,971.3	1,949.6	[1]
Operating Segments | UGI Utilities
Segment Reporting Information
Revenues		198	287.3	[1]
Cost of sales		75.4	143.1	[1]
Segment profit:
Operating income (loss)		48.3	75.6	[1]
Loss from equity investees		0	0	[1]
Interest expense		(9.5)	(10.6)	[1]
Income before income taxes		38.8	65	[1]
Noncontrolling interests’ net income (loss)		0	0	[1]
Depreciation and amortization		16.7	15.4	[1]
Capital expenditures		61.5	55	[1]
Total assets		2,606.3	2,488.6	[1]
Short-term borrowings		217.7	153.5	[1]
Goodwill		182.1	182.1	[1]
Operating Segments | Midstream & Marketing, Energy Services
Segment Reporting Information
Revenues		214.8	314.1	[1]
Cost of sales		151.2	244.6	[1]
Segment profit:
Operating income (loss)		41.3	46.3	[1]
Loss from equity investees		0	0	[1]
Interest expense		(0.8)	(0.6)	[1]
Income before income taxes		40.5	45.7	[1]
Noncontrolling interests’ net income (loss)		0	0	[1]
Depreciation and amortization		4.1	3.8	[1]
Capital expenditures		21.9	12.9	[1]
Total assets		721	728.8	[1]
Short-term borrowings		56	43	[1]
Goodwill		11.5	11.8	[1]
Operating Segments | Midstream & Marketing, Electric Generation
Segment Reporting Information
Revenues		14.8	16.5	[1]
Cost of sales		6	8	[1]
Segment profit:
Operating income (loss)		1.6	(0.7)	[1]
Loss from equity investees		0	0	[1]
Interest expense		0	0	[1]
Income before income taxes		1.6	(0.7)	[1]
Noncontrolling interests’ net income (loss)		0	0	[1]
Depreciation and amortization		3.3	2.7	[1]
Capital expenditures		0.5	6.6	[1]
Total assets		279	286.4	[1]
Short-term borrowings		0	0	[1]
Goodwill		0	0	[1]
Operating Segments | UGI International, UGI France
Segment Reporting Information
Revenues		408.7	337.9	[1]
Cost of sales		192.6	209.3	[1]
Segment profit:
Operating income (loss)		68.7	38.4	[1]
Loss from equity investees		(0.1)	(1)	[1]
Interest expense		(5.6)	(5.6)	[1]
Income before income taxes		63	31.8	[1]
Noncontrolling interests’ net income (loss)		0.1	0.1	[1]
Depreciation and amortization		21.6	13.3	[1]
Capital expenditures		16.3	12.1	[1]
Total assets		2,378.9	1,671.5	[1]
Short-term borrowings		1.1	0	[1]
Goodwill		700.9	575.9	[1]
Operating Segments | UGI International, Flaga & Other
Segment Reporting Information
Revenues		169.5	224.6	[1]
Cost of sales		110.2	172.6	[1]
Segment profit:
Operating income (loss)		16.4	15.1	[1]
Loss from equity investees		0	0	[1]
Interest expense		(0.9)	(1)	[1]
Income before income taxes		15.5	14.1	[1]
Noncontrolling interests’ net income (loss)		0	0	[1]
Depreciation and amortization		5.6	6.1	[1]
Capital expenditures		4.7	6.4	[1]
Total assets		534.8	579	[1]
Short-term borrowings		0	9	[1]
Goodwill		99.3	87.4	[1]
Corporate & Other
Segment Reporting Information
Revenues	[4]	2.1	3.1	[1]
Cost of sales	[4]	(0.1)	231.6	[1]
Segment profit:
Operating income (loss)	[4]	(0.5)	(231.1)	[1]
Loss from equity investees	[4]	0	0	[1]
Interest expense	[4]	(0.1)	(0.2)	[1]
Income before income taxes	[4]	(0.6)	(231.3)	[1]
Noncontrolling interests’ net income (loss)	[4]	(4.1)	(100.8)	[1]
Depreciation and amortization	[4]	0.1	0.3	[1]
Capital expenditures	[4]	0	0.1	[1]
Total assets	[4]	124	277.4	[1]
Short-term borrowings	[4]	0	0	[1]
Goodwill	[4]	0	0	[1]
Gains (losses) on unsettled commodity derivative instruments, net		$ 1.1	$ (229.7)
[1]	Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.
[2]	Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.
[3]	The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income: Three Months Ended December 31, 2015 2014Partnership Adjusted EBITDA $177.7 $188.5Depreciation and amortization (49.2) (49.4)Noncontrolling interests (i) 1.1 0.6Operating income $129.6 $139.7(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
[4]	Corporate & Other results principally comprise (1) net expenses of UGI’s captive general liability insurance company, and (2) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $1.1 and $(229.7) during the three months ended December 31, 2015 and 2014, respectively. Corporate & Other assets principally comprise cash and short-term investments.

Segment Information - Reconcili

Segment Information - Reconciliation of Partnership Adjusted EBITDA (Details) - USD ($) $ in Millions		3 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information
Depreciation and amortization		$ (100.6)	$ (91)	[1]
Operating income		$ 305.5	$ 83.3	[1]
General Partnership interest in AmeriGas OLP (percentage)		1.01%	1.01%
Amerigas Propane
Segment Reporting Information
Partnership Adjusted EBITDA		$ 177.7	$ 188.5
Depreciation and amortization		(49.2)	(49.4)
Noncontrolling interests	[2]	1.1	0.6
Operating income		$ 129.6	$ 139.7
[1]	Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.
[2]	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

Acquisition of Totalgaz (Detail

Acquisition of Totalgaz (Details) $ in Millions	May. 29, 2015EUR (€)	Nov. 30, 2015EUR (€)	Nov. 30, 2015USD ($)	Dec. 31, 2015USD ($)competitors	Dec. 31, 2014USD ($)
Business Acquisition
Long-term debt				$ 3,609.3	$ 3,488.3
Number of competitors challenging agreement | competitors				2
Totalgaz SAS
Business Acquisition
Recognized direct transaction costs					$ 3.8
France SAS | Totalgaz SAS
Business Acquisition
Adjustment to working capital		€ 1,100,000	$ 1.2
Divestiture period following acquisition	15 months
France SAS | 2015 Senior Facilities Agreement | Term Loan | Totalgaz SAS
Business Acquisition
Long-term debt | €	€ 600,000,000

Acquisition of Totalgaz - Sched

Acquisition of Totalgaz - Schedule of Preliminary Purchase Price Allocation (Details) - USD ($) $ in Millions		Dec. 31, 2015	Sep. 30, 2015	May. 29, 2015	Dec. 31, 2014	[1]
Liabilities assumed:
Goodwill (not subject to amortization)		$ 2,965.1	$ 2,953.4		$ 2,806.8
Totalgaz SAS
Assets acquired:
Cash				$ 86.8
Accounts receivable	[2]			170.3
Prepaid expenses and other current assets				11
Property, plant and equipment				375.6
Intangible assets	[3]			91.3
Other assets				21.4
Total assets acquired				756.4
Liabilities assumed:
Accounts payable				109.2
Other current liabilities				103.5
Deferred income taxes				115.8
Other noncurrent liabilities				117.5
Total liabilities assumed				446
Goodwill (not subject to amortization)				186.2
Net consideration transferred (including working capital adjustments)				496.6
Indefinite-lived intangible assets acquired	[3]			12
Totalgaz SAS | Customer Relationships
Liabilities assumed:
Finite-lived intangibles assets acquired	[3]			$ 79.3
[1]	Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.
[2]	Approximates the gross contractual amounts of receivables acquired.
[3]	Represents $79.3 of customer relationships and $12.0 of tradenames.

Acquisition of Totalgaz - Sch60

Acquisition of Totalgaz - Schedule of Pro Forma Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
As Reported
Revenues	$ 1,606.6	$ 2,004.6	[1]
Net income attributable to UGI Corporation	$ 114.6	$ 34.1
Earnings Per Share [Abstract]
Basic (in dollars per share)	$ 0.66	$ 0.20
Diluted (in dollars per share)	$ 0.65	$ 0.19
Totalgaz SAS
Pro Forma Adjusted
Revenues		$ 2,184.5
Net income attributable to UGI Corporation		$ 46.6
Earnings per common share attributable to UGI Corporation shareholders:
Basic (in dollars per share)		$ 0.27
Diluted (in dollars per share)		$ 0.27
[1]	Certain amounts have been restated to reflect the current-year changes in our segment presentation as described above.