UGI (UGI) 10-Q 8 May 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Mar. 31, 2018	Apr. 30, 2018
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	Mar. 31, 2018
Amendment Flag	false
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--09-30
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		173,118,013

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Mar. 31, 2018	Sep. 30, 2017	Mar. 31, 2017
Current assets:
Cash and cash equivalents	$ 474.8	$ 558.4	$ 637.8
Restricted cash	10.6	10.3	0.3
Accounts receivable (less allowances for doubtful accounts of $44.6, $26.9 and $34.7, respectively)	1,272.7	626.8	920.4
Accrued utility revenues	62.3	13.3	36.7
Inventories	228.3	278.6	203
Utility regulatory assets	2.9	8.3	2.3
Derivative instruments	36.6	63.1	49.2
Prepaid expenses and other current assets	133.9	138.7	90.6
Total current assets	2,222.1	1,697.5	1,940.3
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $3,141.2, $3,312.9 and $3,221.9, respectively)	5,716.6	5,537	5,298.6
Goodwill	3,218.1	3,107.2	2,948.4
Intangible assets, net	627.1	611.7	551
Utility regulatory assets	358.7	360.6	392.4
Derivative instruments	12	9.2	11.4
Other assets	290.7	259	243.4
Total assets	12,445.3	11,582.2	11,385.5
Current liabilities:
Current maturities of long-term debt	86	177.5	170.5
Short-term borrowings	302.8	366.9	50.1
Accounts payable	600.3	439.6	467.6
Derivative instruments	28.9	25	5
Other current liabilities	799.5	681.1	674.6
Total current liabilities	1,817.5	1,690.1	1,367.8
Long-term debt	4,192.8	3,994.6	4,025.5
Deferred income taxes	905.9	1,357	1,267.6
Deferred investment tax credits	2.8	3	3.1
Derivative instruments	25	21.8	5.9
Other noncurrent liabilities	1,080.3	774.8	778.2
Total liabilities	8,024.3	7,841.3	7,448.1
Commitments and contingencies (Note 10)
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 174,015,641, 173,987,691 and 173,949,791 shares, respectively)	1,193.4	1,188.6	1,190.4
Retained earnings	2,656.6	2,106.7	2,214.2
Accumulated other comprehensive loss	(34.1)	(93.4)	(204.5)
Treasury stock, at cost	(41.6)	(38.6)	(34.9)
Total UGI Corporation stockholders’ equity	3,774.3	3,163.3	3,165.2
Noncontrolling interests, principally in AmeriGas Partners	646.7	577.6	772.2
Total equity	4,421	3,740.9	3,937.4
Total liabilities and equity	$ 12,445.3	$ 11,582.2	$ 11,385.5

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2018	Sep. 30, 2017	Mar. 31, 2017
Statement of Financial Position [Abstract]
Accounts receivable, allowances for doubtful accounts	$ 44.6	$ 26.9	$ 34.7
Property, plant and equipment, accumulated depreciation and amortization	$ 3,141.2	$ 3,312.9	$ 3,221.9
UGI Common Stock, without par value, shares authorized (in shares)	450,000,000	450,000,000	450,000,000
UGI Common Stock, without par value, shares issued (in shares)	174,015,641	173,987,691	173,949,791

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Income Statement [Abstract]
Revenues	$ 2,812	$ 2,173.8	$ 4,937.2	$ 3,853.3
Costs and expenses:
Cost of sales (excluding depreciation shown below)	1,560.2	1,071.2	2,697.6	1,718.6
Operating and administrative expenses	556.2	491.1	1,046.3	959.6
Depreciation	98.5	84.8	194	168.5
Amortization	13.7	14.5	28.5	28.9
Other operating income, net	(6.1)	(1)	(10.5)	(1.7)
Total costs and expenses	2,222.5	1,660.6	3,955.9	2,873.9
Operating income	589.5	513.2	981.3	979.4
Income from equity investees	0.7	2.3	1.7	2.1
Loss on extinguishments of debt	0	(22.1)	0	(55.3)
(Losses) gains on foreign currency contracts, net	(11)	(1.2)	(15.8)	0.1
Interest expense	(58.1)	(55.8)	(116.3)	(111.2)
Income (loss) before income taxes	521.1	436.4	850.9	815.1
Income tax expense	(113.4)	(124.6)	(9)	(212.4)
Net income including noncontrolling interests	407.7	311.8	841.9	602.7
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners	(131.7)	(91.9)	(200)	(152.1)
Net income attributable to UGI Corporation	$ 276	$ 219.9	$ 641.9	$ 450.6
Earnings per common share attributable to UGI Corporation stockholders
Basic (in dollars per share)	$ 1.59	$ 1.27	$ 3.70	$ 2.60
Diluted (in dollars per share)	$ 1.57	$ 1.24	$ 3.63	$ 2.55
Weighted average common shares outstanding (thousands)
Basic (in shares)	173,570	173,624	173,617	173,567
Diluted (in shares)	176,350	177,136	176,646	176,976
Dividends declared per common share (in dollars per share)	$ 0.25	$ 0.2375	$ 0.5	$ 0.4750

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income including noncontrolling interests	$ 407.7	$ 311.8	$ 841.9	$ 602.7
Other comprehensive income (loss):
Net (losses) gains on derivative instruments (net of tax of $0.7, $0.3, $0.9 and $(5.7), respectively)	(1.6)	(0.5)	(2)	11.8
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(1.5), $2.5, $(1.4) and $4.6, respectively)	2.8	(5.4)	2.4	(9.9)
Foreign currency adjustments	35.9	17.8	58.2	(53.1)
Benefit plans (net of tax of $(0.1), $(0.3), $(0.3) and $(0.9), respectively)	0.3	0.4	0.7	1.4
Other comprehensive income (loss)	37.4	12.3	59.3	(49.8)
Comprehensive income including noncontrolling interests	445.1	324.1	901.2	552.9
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	(131.7)	(91.9)	(200)	(152.1)
Comprehensive income attributable to UGI Corporation	$ 313.4	$ 232.2	$ 701.2	$ 400.8

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Tax on (loss) gain on derivative instruments	$ 0.7	$ 0.3	$ 0.9	$ (5.7)
Tax on reclassification on derivative instruments	(1.5)	2.5	(1.4)	4.6
Tax on benefit plans	$ (0.1)	$ (0.3)	$ (0.3)	$ (0.9)

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income including noncontrolling interests	$ 841.9	$ 602.7
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization	222.5	197.4
Deferred income tax (benefit) expense	(191.5)	49.4
Provision for uncollectible accounts	24.8	15.3
Change in unrealized losses (gains) on derivative instruments	41.5	(81.6)
Loss on extinguishments of debt	0	55.3
Other, net	10	24
Net change in:
Accounts receivable and accrued utility revenues	(676)	(424.3)
Inventories	57	3.9
Utility deferred fuel and power costs, net of changes in unsettled derivatives	31.5	(7.6)
Accounts payable	136.2	129.4
Other current assets	(18.3)	(1.3)
Other current liabilities	99.8	22.4
Net cash provided by operating activities	579.4	585
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(266.1)	(341.8)
Acquisitions of businesses and assets, net of cash acquired	(174.3)	(7.3)
(Increase) decrease in restricted cash	(0.3)	15.3
Other, net	9	(4.3)
Net cash used by investing activities	(431.7)	(338.1)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(86.6)	(82.3)
Distributions on AmeriGas Partners publicly held Common Units	(131.5)	(130.1)
Issuances of debt, net of issuance costs	124.3	1,307.1
Repayments of debt, including redemption premiums	(64.3)	(928.6)
Decrease in short-term borrowings	(38.7)	(216.1)
Receivables Facility net repayments	(29)	(25.5)
Issuances of UGI Common Stock	3.1	5.9
Repurchases of UGI Common Stock	(14.1)	(25.5)
Other	(3.4)	(0.8)
Net cash used by financing activities	(240.2)	(95.9)
EFFECT OF EXCHANGE RATE CHANGES ON CASH	8.9	(16)
Cash and cash equivalents (decrease) increase	(83.6)	135
CASH AND CASH EQUIVALENTS
End of period	474.8	637.8
Beginning of period	$ 558.4	$ 502.8

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Changes in Equity (unaudited) - USD ($) $ in Millions	Total	Total UGI Corporation stockholders’ equity	Common stock, without par value	Retained earnings	Accumulated other comprehensive income (loss)	Treasury stock	Noncontrolling interests
Increase (Decrease) in Stockholders' Equity
Cumulative effect of change in accounting for employee share-based payments				$ 5
Balance, beginning of period at Sep. 30, 2016			$ 1,201.6	1,840.9	$ (154.7)	$ (36.9)	$ 750.9
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			(20.7)
Equity-based compensation expense			8.1
Losses on treasury stock transactions in connection with employee and director plans	$ 0
Net income	602.7			450.6			152.1
Cash dividends on Common Stock				(82.3)
Net (losses) gains on derivative instruments	11.8				11.8
Reclassification of net losses (gains) on derivative instruments	(9.9)				(9.9)
Benefit plans	1.4				1.4
Foreign currency adjustments	(53.1)				(53.1)
Common stock issued in connection with employee and director plans, net of tax withheld						33.7
Repurchases of Common Stock						(25.5)
Reacquired common stock — employee and director plans						(6.4)
Sale of treasury stock			1.4			0.2
Dividends and distributions							(130.1)
Other							(0.7)
Balance, end of period at Mar. 31, 2017	3,937.4	$ 3,165.2	1,190.4	2,214.2	(204.5)	(34.9)	772.2
Increase (Decrease) in Stockholders' Equity
Net income	311.8
Net (losses) gains on derivative instruments	(0.5)
Reclassification of net losses (gains) on derivative instruments	(5.4)
Benefit plans	0.4
Foreign currency adjustments	17.8
Balance, end of period at Mar. 31, 2017	3,937.4	3,165.2	1,190.4	2,214.2	(204.5)	(34.9)	772.2
Increase (Decrease) in Stockholders' Equity
Cumulative effect of change in accounting for employee share-based payments				0
Balance, beginning of period at Sep. 30, 2017	3,740.9		1,188.6	2,106.7	(93.4)	(38.6)	577.6
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			(3.8)
Equity-based compensation expense			8.6
Losses on treasury stock transactions in connection with employee and director plans	(5.4)
Net income	841.9			641.9			200
Cash dividends on Common Stock				(86.6)
Net (losses) gains on derivative instruments	(2)				(2)
Reclassification of net losses (gains) on derivative instruments	2.4				2.4
Benefit plans	0.7				0.7
Foreign currency adjustments	58.2				58.2
Common stock issued in connection with employee and director plans, net of tax withheld						13
Repurchases of Common Stock						(14.1)
Reacquired common stock — employee and director plans						(1.9)
Sale of treasury stock			0			0
Dividends and distributions							(131.8)
Other							0.9
Balance, end of period at Mar. 31, 2018	4,421	3,774.3	1,193.4	2,656.6	(34.1)	(41.6)	646.7
Increase (Decrease) in Stockholders' Equity
Net income	407.7
Net (losses) gains on derivative instruments	(1.6)
Reclassification of net losses (gains) on derivative instruments	2.8
Benefit plans	0.3
Foreign currency adjustments	35.9
Balance, end of period at Mar. 31, 2018	$ 4,421	$ 3,774.3	$ 1,193.4	$ 2,656.6	$ (34.1)	$ (41.6)	$ 646.7

Nature of Operations

Nature of Operations	6 Months Ended
	Mar. 31, 2018
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; and (3) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production, electricity generation and energy services business. In Europe, we market and distribute propane and other liquefied petroleum gases (“LPG”) and market energy products and services. 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”). AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the “General Partner”), serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as the “Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At March 31, 2018 , the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.0% 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 14 of the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2017 (the “Company’s 2017 Annual Report”). Incentive distributions received by the General Partner during the six months ended March 31, 2018 and 2017 were $22.7 and $20.9 , respectively. Our wholly owned subsidiary, UGI Enterprises, LLC, (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution business throughout Europe, (2) a natural gas marketing business in France, Belgium and the United Kingdom, and (3) a natural gas and electricity marketing business in the Netherlands. These businesses are conducted principally through our subsidiaries, UGI France SAS, Flaga GmbH (“Flaga”), AvantiGas Limited, DVEP Investeringen B.V. (“DVEP”), and UniverGas Italia S.r.l. (“UniverGas”). We refer to our foreign operations collectively as “UGI International.” UGI Energy Services, LLC (“Energy Services, LLC”), a wholly owned subsidiary of Enterprises, conducts directly and through subsidiaries energy marketing, midstream transmission, liquefied natural gas (“LNG”), storage, natural gas gathering, natural gas production, electricity generation and energy services businesses primarily in the Mid-Atlantic region of the U.S. Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. A first-tier subsidiary of Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in portions of eastern and central Pennsylvania (“HVAC”). Energy Services, LLC and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). We refer to the businesses of Energy Services, LLC and its subsidiaries and HVAC as “Midstream & Marketing.” UGI Utilities, Inc. (“UGI Utilities”) conducts a natural gas distribution utility business (“Gas Utility”) directly and through its wholly owned 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 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 (“MD PSC”). Electric Utility is subject to regulation by the PUC. UGI Utilities is used herein as an abbreviated reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries.

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Mar. 31, 2018
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, 2017 , 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 2017 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 Six Months Ended 2018 2017 2018 2017 Denominator (thousands of shares): Weighted-average common shares outstanding — basic 173,570 173,624 173,617 173,567 Incremental shares issuable for stock options and awards (a) 2,780 3,512 3,029 3,409 Weighted-average common shares outstanding — diluted 176,350 177,136 176,646 176,976 (a) For the three and six months ended March 31, 2018 , there were 2,486 shares associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive. For the three and six months ended March 31, 2017 , there were no such antidilutive shares. Derivative Instruments. Derivative instruments are reported on the condensed consolidated balance sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception. 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. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”), 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. Unrealized gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities (for which NPNS has not been elected) are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. From time to time, we also enter into net investment hedges. 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. Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “ (Losses) gains on foreign currency contracts, net ” on the Condensed Consolidated Statements of Income. Cash flows from derivative instruments, other than certain cross-currency swaps and net investment hedges, if any, are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges, if any, are included in cash flows from operating activities while cash flows from the currency portion of such hedges, if any, are included in cash flows from financing activities. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows. 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 13 . Impairment of Cost Basis Investments . We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary. In March 2017, we recorded a pre-tax loss of $7.0 associated with an other-than-temporary impairment of our investment in a private equity partnership that invests in renewable energy companies. This loss is reflected in “ Other operating income, net ” on the Condensed Consolidated Statements of Income for the three and six months ended March 31, 2017. Income Taxes. UGI’s consolidated effective income tax rate, defined as total income taxes 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. See Note 5 for discussions regarding the December 22, 2017, enactment of the Tax Cuts and Jobs Act (the “TCJA”) in the U.S. and changes in French tax laws. Use of Estimates. The preparation of financial statements 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. Reclassifications. Certain prior period amounts have been reclassified to conform to the current-period presentation.

Accounting Changes

Accounting Changes	6 Months Ended
	Mar. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Changes	Note 3 — Accounting Changes Accounting Standards Not Yet Adopted Other Comprehensive Income. In February 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU provides that the stranded tax effects in AOCI resulting from the TCJA may be reclassified to retained earnings, at the election of the entity, in the period of adoption. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required only prospectively. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. For entities subject to rate regulation, however, the ASU recognized that in the event a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of a regulatory asset or liability. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) with a retrospective adoption for income statement presentation and a prospective adoption for capitalization. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in the ASU are required to be adopted on a retrospective basis. The ASU is effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. We currently expect to adopt this ASU effective October 1, 2018. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” (“ASU 2014-09”) The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 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. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue by UGI Utilities. The Company anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018.

Inventories

Inventories	6 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
Inventories	Note 4 — Inventories Inventories comprise the following: March 31, September 30, March 31, Non-utility LPG and natural gas $ 163.0 $ 188.4 $ 143.1 Gas Utility natural gas 3.5 39.5 2.4 Materials, supplies and other 61.8 50.7 57.5 Total inventories $ 228.3 $ 278.6 $ 203.0 At March 31, 2018 , UGI Utilities was a party to five principal storage contract administrative agreements (“SCAAs”) which have terms of up to three years. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above. As of March 31, 2018 , UGI Utilities had SCAAs with Energy Services, LLC, the effects of which are eliminated in consolidation, and with a non-affiliate. There were no gas storage inventories released under SCAAs with the non-affiliate at March 31, 2018 and 2017. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at September 30, 2017 , comprising 2.3 billion cubic feet (“bcf”) of natural gas was $6.7 .

Income Taxes

Income Taxes	6 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Income Tax Reform	Note 5 — Income Tax Reform U.S. Tax Reform On December 22, 2017, the TCJA was enacted into law. Among the significant changes resulting from the law, the TCJA reduces the U.S. federal income tax rate from 35% to 21% effective January 1, 2018, creates a territorial tax system with a one-time mandatory “toll tax” on previously un-repatriated foreign earnings, and allows for immediate capital expensing of certain qualified property. It also applies restrictions on the deductibility of interest expense, eliminates bonus depreciation for regulated utilities and applies a broader application of compensation limitations. In accordance with GAAP as determined by ASC 740, “Income Taxes,” we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three and six months ended March 31, 2018 , contain provisional estimates of the impact of the TCJA. These amounts are considered provisional because they use estimates for which tax returns have not yet been filed and because estimated amounts may be impacted by future regulatory and accounting guidance if and when issued. In accordance with SEC Staff Accounting Bulletin (“SAB”) No. 118, we will adjust these provisional amounts as further information becomes available and as we refine our calculations. As permitted by the guidance issued by the SEC, these adjustments may occur during a reasonable “measurement period” not to exceed twelve months from the date of enactment. As a result, during the three and six months ended March 31, 2018 , we reduced our net deferred income tax liabilities by $5.0 and $388.8 , respectively, due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of the enactment in December 2017, and as a result of adjusting our original provisional amounts during the quarter ended March 31, 2018. Because part of the reduction to our net deferred income taxes relates to UGI Utilities’ regulated utility plant assets as further described below, most of UGI Utilities’ reduction in deferred income taxes is not being recognized immediately in income tax expense. Discrete deferred income tax adjustments recorded during each of the three month periods ended December 31, 2017 and March 31, 2018, and the six months ended March 31, 2018, which reduced (increased) income tax expense consisted primarily of the following items: Provisional amounts - Three months ended December 31, 2017 Changes to provisional amounts - Three months ended March 31, 2018 Provisional amounts - Six months ended March 31, 2018 Reduction in net deferred tax liabilities in the U.S. from the reduction of the U.S. tax rate $ 180.3 $ — $ 180.3 Establishment of valuation allowances related to deferred tax assets impacted by TCJA (12.6 ) 5.0 (7.6 ) Toll-tax on un-repatriated earnings (1.7 ) 0.3 (1.4 ) Total discrete deferred income tax adjustments $ 166.0 $ 5.3 $ 171.3 Impact on earnings per share: Basic earnings per share $ 0.96 $ 0.03 $ 0.99 Diluted earnings per share $ 0.94 $ 0.03 $ 0.97 In order for UGI Utilities’ regulated utility plant assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred income taxes be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. At December 31, 2017, UGI Utilities has recorded a regulatory liability of $216.1 associated with excess deferred federal income taxes related to its regulated utility plant assets. This regulatory liability has been increased, and a federal deferred income tax asset has been recorded, in the amount of $87.8 to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. This regulatory liability is being amortized to income tax expense over the remaining lives of the assets that gave rise to the excess deferred income taxes. For further information on this regulatory liability, see Note 7 . For the three and six months ended March 31, 2018 , we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rate. We are subject to a blended federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contains the effective date of the rate change from 35% to 21% . As a result, the U.S. federal income tax rate included in our estimated annual effective tax rate is based on this 24.5% blended rate for Fiscal 2018. For the three and six months ended March 31, 2018 , the effects of the tax law changes on current-period results (excluding the one-time impacts described above) decreased income tax expense, and increased net income attributable to UGI, by approximately $34.0 and $54.5 , respectively. As a result of the TCJA tax law changes, in January 2018, the PUC opened a proceeding to consider whether existing rates charged by Pennsylvania utilities are no longer “just and reasonable,” as required by Pennsylvania law. On February 12, 2018, the PUC issued a Secretarial Letter requesting detailed information from large public utilities, including UGI Utilities, and inviting interested parties to submit comments on the impacts of the TCJA. On March 15, 2018, the PUC entered a temporary rates Order that converted commission-approved rates of most large Pennsylvania public utilities, including Gas Utility, into “temporary rates” for a period of six months, with a possible extension for an additional six months. It ordered each affected public utility to file a tariff supplement designating its existing rates and riders as temporary, effective March 15, 2018. In its comments on March 9, 2018, UGI Utilities expressed the view that, as a matter of law, reducing base rates by the tax impact of the TCJA would be unlawful if the result did not permit the utility to earn a reasonable rate of return and proposed to give approximately half of the benefits from the TCJA to customers through a reduction in rates and increased funding for low income and gas operations programs. The PUC is in the process of reviewing the data and comments submitted in response to the Secretarial Letter. Due to the complexity of the tax law changes and the numerous public utilities involved, the PUC has stated that it is unable to determine when it will complete its review and resolve the issues presented. Changes in French Corporate Income Tax Rates In December 2017, the French Parliament approved the Finance Bill for 2018 and the second amended Finance Bill for 2017 (collectively, the “December 2017 French Finance Bills”). One impact of the December 2017 French Finance Bills is an increase in the Fiscal 2018 corporate income tax rate in France to 39.4% from 34.4% previously. The December 2017 French Finance Bills also include measures to reduce the corporate income tax rate to 25.8% effective for fiscal years starting after January 1, 2022 (Fiscal 2023). As a result of the future corporate income tax rate reduction effective in Fiscal 2023, during the three months ended December 31, 2017, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax benefit of $17.3 . During the three months ended March 31, 2018, this estimated deferred tax benefit was adjusted downward by $3.7 to $13.6 (equal to $0.08 per basic and diluted share) for the six months ended March 31, 2018. The estimated annual effective income tax rate used in determining income taxes for the six months ended March 31, 2018, reflects the impact of the single year Fiscal 2018 income tax rate increase as a result of the December 2017 French Finance Bills. The impact of the single year rate change increased income tax expense for the three and six months ended March 31, 2018, by approximately $1.1 and $5.0 , respectively. In December 2016, the French Parliament approved the Finance Bill for 2017 and amended the Finance Bill for 2016 (collectively, the “December 2016 French Finance Bills”). The December 2016 French Finance Bills, among other things, will reduce UGI France’s corporate income tax rate from the then-current 34.4% to 28.9% , effective for fiscal years starting after January 1, 2020 (Fiscal 2021). As a result of this future income tax rate reduction, during the three months ended December 31, 2016, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax benefit of $27.4 (equal to $0.15 per basic and diluted share).

Goodwill and Intangible Assets

Goodwill and Intangible Assets	6 Months Ended
	Mar. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	Note 6 — Goodwill and Intangible Assets Goodwill and intangible assets comprise the following: March 31, September 30, March 31, Goodwill (not subject to amortization) $ 3,218.1 $ 3,107.2 $ 2,948.4 Intangible assets: Customer relationships, noncompete agreements and other $ 867.0 $ 817.8 $ 764.3 Accumulated amortization (376.2 ) (340.2 ) (342.4 ) Intangible assets, net (definite-lived) 490.8 477.6 421.9 Trademarks and tradenames (indefinite-lived) 136.3 134.1 129.1 Total intangible assets, net $ 627.1 $ 611.7 $ 551.0 The changes in goodwill and intangible assets are primarily due to acquisitions and the effects of currency translation. Amortization expense of intangible assets was $13.7 and $12.4 for the three months ended March 31, 2018 and 2017 , respectively. Amortization expense of intangible assets was $28.5 and $24.9 for the six months ended March 31, 2018 and 2017 , respectively. Amortization expense included in “Cost of sales” on the Condensed Consolidated Statements of Income was not material. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 2018 and for the next four fiscal years is as follows: remainder of Fiscal 2018 — $28.3 ; Fiscal 2019 — $54.7 ; Fiscal 2020 — $53.3 ; Fiscal 2021 — $51.4 ; Fiscal 2022 — $49.7 . During the quarter ended March 31, 2018, the Partnership performed a formal business review of the current and planned use of its indefinite-lived tradenames and trademarks, primarily associated with its January 2012 acquisition of Heritage Propane. This review included obtaining an understanding of the costs and benefits of continuing to utilize these tradenames and trademarks in the operations of the Partnership’s business. At March 31, 2018, these indefinite-lived tradenames and trademarks had a carrying amount of $82.9 . In April 2018, a plan to discontinue the use of these tradenames and trademarks was presented to the Partnership’s senior management. After considering the merits of the plan, the Partnership’s senior management approved, and the General Partner’s Board of Directors endorsed, a plan to discontinue the use of these tradenames and trademarks which is expected to occur over a period of approximately four years. As a result, during the three months ending June 30, 2018, the Partnership will adjust the carrying amounts of these tradenames and trademarks to their fair values and will reclassify the remaining fair value of these tradenames and trademarks from indefinite-lived intangible assets to definite-lived intangible assets having a remaining estimated period of benefit of approximately four years. The Partnership estimates that it will record a pre-tax non-cash impairment charge of approximately $70 which will decrease net income attributable to UGI by approximately $13 .

Utility Regulatory Assets and L

Utility Regulatory Assets and Liabilities and Regulatory Matters	6 Months Ended
	Mar. 31, 2018
Regulated Operations [Abstract]
Utility Regulatory Assets and Liabilities and Regulatory Matters	Note 7 — Utility Regulatory Assets and Liabilities and Regulatory Matters For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 in the Company’s 2017 Annual Report. Other than removal costs, UGI Utilities currently does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with UGI Utilities are included in our accompanying condensed consolidated balance sheets: March 31, September 30, March 31, Regulatory assets: Income taxes recoverable $ 128.3 $ 121.4 $ 120.3 Underfunded pension and postretirement plans 135.3 141.3 175.6 Environmental costs 59.8 61.6 62.2 Deferred fuel and power costs 0.7 7.7 1.3 Removal costs, net 30.5 31.0 28.8 Other 7.0 5.9 6.5 Total regulatory assets $ 361.6 $ 368.9 $ 394.7 Regulatory liabilities (a): Postretirement benefits $ 17.1 $ 17.5 $ 17.0 Deferred fuel and power refunds 35.3 10.6 13.8 State tax benefits — distribution system repairs 19.9 18.4 16.1 Excess federal deferred income taxes (b) 301.2 — — Other 7.2 2.7 3.6 Total regulatory liabilities $ 380.7 $ 49.2 $ 50.5 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Condensed Consolidated Balance Sheets. (b) Balance at March 31, 2018 , comprises excess deferred federal income taxes resulting from the enactment of the TCJA (see below and Note 5 ). Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that 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 on such contracts at March 31, 2018 , September 30, 2017 and March 31, 2017 were $0.3 , $0.1 and $2.0 , respectively. In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at March 31, 2018 , September 30, 2017 and March 31, 2017 , were not material. Excess federal deferred income taxes. This regulatory liability is the result of remeasuring UGI Utilities’ federal deferred income tax liabilities on utility plant due to the enactment of the TCJA on December 22, 2017 (see Note 5 ). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that these excess federal deferred income taxes be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess federal deferred income taxes, ranging from 1 year to approximately 65 years . This regulatory liability has been increased to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes and will be amortized and credited to tax expense. Other Regulatory Matters Base Rate Filings. On January 26, 2018, Electric Utility filed a rate request with the PUC to increase its annual base distribution revenues by $9.2 . The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. Electric Utility requested that the new electric rates become effective March 27, 2018. The PUC entered an Order dated March 1, 2018, suspending the effective date for the rate increase to allow for investigation and public hearings. Unless a settlement is reached sooner, this review process is expected to last up to nine months from the date of filing; however, the Company cannot predict the timing or the ultimate outcome of the rate case review process. On August 31, 2017, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for an $11.3 annual base distribution rate increase for PNG. The increase became effective on October 20, 2017. On October 14, 2016, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27.0 annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016. Distribution System Improvement Charge. State legislation permits gas and electric utilities in Pennsylvania to recover a distribution system improvement charge (“DSIC”) on eligible capital investments as an alternative ratemaking mechanism providing for a more-timely cost recovery of qualifying capital expenditures between base rate cases. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero , in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In May 2017, the PUC issued a final Order to approve an increase of the maximum allowable DSIC to 7.5% of billed distribution revenues effective July 1, 2017, for PNG and CPG, pending reconsideration at each company’s Long-term Infrastructure Improvement Plan filing in 2018. PNG’s DSIC has been reset to zero as a result of its most recent rate case. The DSIC rate for PNG will resume upon exceeding the threshold amount of DSIC-eligible plant in service agreed upon in the settlement of its recent base rate case. In November 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism, capped at 5% of distribution charges billed to customers, effective January 1, 2017. UGI Gas will be permitted to recover revenue under the mechanism for the amount of DSIC-eligible plant placed into service in excess of the threshold amount of DSIC-eligible plant agreed upon in the settlement of its recent base rate case. Utilities Merger Request. On March 8, 2018 and March 13, 2018, the Company filed merger authorization requests with the PUC and MD PSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. There are no expected changes to annual base distribution rates for the combined utilities or to existing regulatory assets and liabilities as a result of the proposed merger. The Company cannot predict the timing or the ultimate outcome of the PUC or MD PSC review of the merger request. CPG, PNG, and UGI Utilities also filed, in May 2018, related applications to transfer certain FERC authorizations from PNG and CPG to UGI Utilities to ensure continuity of certain interstate gas transportation services now conducted by CPG and PNG upon the effective date of the proposed merger.

Energy Services Accounts Receiv

Energy Services Accounts Receivable Securitization Facility	6 Months Ended
	Mar. 31, 2018
Transfers and Servicing [Abstract]
Energy Services Accounts Receivable Securitization Facility	Note 8 — Energy Services Accounts Receivable Securitization Facility Energy Services, LLC has an accounts receivable securitization facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2018. The Receivables Facility, as amended, provides Energy Services, LLC with the ability to borrow up to $150 of eligible receivables during the period November to April and up to $75 of eligible receivables during the period May to October. Energy Services, LLC 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, LLC 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. Amounts sold to the bank are reflected as “Short-term borrowings” on the Condensed Consolidated Balance Sheets. ESFC was created and has been structured to isolate its assets from creditors of Energy Services, LLC and its affiliates, including UGI. Trade receivables sold to the bank remain on Energy Services, LLC’s balance sheet and Energy Services, LLC reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services, LLC continues to service, administer and collect trade receivables on behalf of the bank, as applicable. Losses on sales of receivables to the bank during the three and six months ended March 31, 2018 and 2017 , which are included in “Interest expense” on the Condensed Consolidated Statements of Income, were not material. Information regarding the trade receivables transferred to ESFC and the amounts sold to the bank for the six months ended March 31, 2018 and 2017 , as well as the balance of ESFC trade receivables at March 31, 2018 , September 30, 2017 and March 31, 2017 , is as follows: Six Months Ended March 31, 2018 2017 Trade receivables transferred to ESFC during the period $ 806.9 $ 633.7 ESFC trade receivables sold to the bank during the period $ 128.0 $ 151.0 March 31, 2018 September 30, 2017 March 31, 2017 ESFC trade receivables — end of period (a) $ 99.6 $ 44.8 $ 85.3 (a) At March 31, 2018 and September 30, 2017 , the amounts of ESFC trade receivables sold to the bank were $10.0 and $39.0 , respectively. At March 31, 2017 , there were no ESFC trade receivables sold to the bank. Amounts sold to the bank are reflected as “ Short-term borrowings ” on the Condensed Consolidated Balance Sheets.

Debt

Debt	6 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Debt	Note 9 — Debt AmeriGas Propane. In December 2017, AmeriGas Partners entered into the Second Amended and Restated Credit Agreement (“AmeriGas Credit Agreement”) with a group of banks. The AmeriGas Credit Agreement amends and restates a previous credit agreement. The AmeriGas Credit Agreement provides for borrowings up to $600 (including a $150 sublimit for letters of credit) and expires in December 2022. The AmeriGas Credit Agreement permits AmeriGas to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Credit Agreement, plus a margin. Under the AmeriGas Credit Agreement, the applicable margin on base rate borrowings ranges from 0.50% to 1.75% ; the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.75% ; and the facility fee ranges from 0.30% to 0.50% . The aforementioned margins and facility fees are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (each as defined in the AmeriGas Credit Agreement). During the three and six months ended March 31, 2017 , the Partnership recognized pre-tax losses of $22.1 and $55.3 , respectively, in connection with the early repayments of a portion of AmeriGas Partners’ 7.00% Senior Notes. These losses are reflected in “ Loss on extinguishments of debt ” on the Condensed Consolidated Statements of Income for the three and six months ended March 31, 2017 . UGI International. In December 2017, UGI International, LLC, a wholly owned subsidiary of UGI, entered into a secured multicurrency revolving facility agreement (the "UGI International Credit Agreement") with a group of banks providing for borrowings up to €300 . The UGI International Credit Agreement is scheduled to expire in April 2020. Under the UGI International Credit Agreement, UGI International, LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated euribor rate plus a margin ranging from 1.45% to 2.35% . Loans made in U.S. dollars will bear interest at LIBOR plus a margin ranging from 1.70% to 2.60% . The aforementioned margins are dependent upon certain indebtedness at UGI International, LLC. The UGI International Credit Agreement requires UGI International, LLC not to exceed a ratio of total net indebtedness to EBITDA, as defined, of 3.50 to 1.00. Also in December 2017, Flaga repaid $9.2 of the outstanding principal amount of its then-existing $59.1 U.S. dollar denominated variable-rate term loan due September 2018. Concurrently, Flaga entered into an amendment to the aforementioned term loan, which amends and restates the previous agreement to provide for a principal balance of $49.9 and extends the maturity of the term loan to April 2020 (“Flaga Term Loan”). The outstanding principal bears interest at the one-month LIBOR rate plus a margin of 1.125% . Flaga has effectively fixed the LIBOR component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments payable under the Flaga Term Loan, by entering into a cross-currency swap arrangement with a bank. Because a portion of the cash flows related to the Flaga Term Loan were with the same bank, such cash flows have been reflected “net” in the financing activities section of the Condensed Consolidated Statement of Cash Flows. UGI Utilities. In October 2017, UGI Utilities entered into a $125 unsecured variable-rate term loan agreement (the “Utilities Term Loan”) with a group of banks. Proceeds from the Utilities Term Loan were used to repay revolving credit agreement borrowings and for general corporate purposes. The outstanding principal amount of the Utilities Term Loan is payable in equal quarterly installments of $1.6 , which commenced March 2018, with the balance of the principal being due and payable in full on October 30, 2022. Under the Utilities Term Loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The Utilities Term Loan requires that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 10 — Commitments and Contingencies UGI Standby Commitment to Purchase AmeriGas Partners Class B Common Units On November 7, 2017, UGI entered into a Standby Equity Commitment Agreement (the “Commitment Agreement”) with AmeriGas Partners and AmeriGas Propane, Inc. Under the terms of the Commitment Agreement, UGI has committed to make up to $225 of capital contributions to the Partnership through July 1, 2019 (the “Commitment Period”). UGI’s capital contributions may be made from time to time during the Commitment Period upon request of the Partnership. There have been no capital contributions made to the Partnership under the Commitment Agreement. In consideration for any capital contributions made pursuant to the Commitment Agreement, the Partnership will issue to UGI or a wholly owned subsidiary new Class B Common Units representing limited partner interests in the Partnership (“Class B Units”). The Class B Units will be issued at a price per unit equal to the 20 -day volume-weighted average price of AmeriGas Partners Common Units prior to the date of the Partnership’s related capital call. The Class B Units will be entitled to cumulative quarterly distributions at a rate equal to the annualized Common Unit yield at the time of the applicable capital call, plus 130 basis points. The Partnership may choose to make the distributions in cash or in the form of additional Class B Units. While outstanding, the Class B Units will not be subject to any incentive distributions from the Partnership. At any time after five years from the initial issuance of the Class B Units, holders may elect to convert all or any portion of the Class B Units they own into Common Units on a one -for-one basis, and at any time after six years from the initial issuance of the Class B Units, the Partnership may elect to convert all or any portion of the Class B Units into Common Units if (i) the closing trading price of the Common Units is greater than 110% of the applicable purchase price for the Class B Units and (ii) the Common Units are listed or admitted for trading on a National Securities Exchange. Upon certain events involving a change of control and immediately prior to a liquidation or winding up of the Partnership, the Class B Units will automatically convert into Common Units on a one -for-one basis. Environmental Matters UGI Utilities From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. 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 also has two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered into a consent order and agreement (“COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania. In accordance with the COAs, UGI Utilities, CPG and PNG are each required to either obtain a certain number of points per calendar year based on defined eligible environmental investigatory and/or remedial activities at the MGPs or make expenditures for such activities in an amount equal to an annual environmental cost cap. The CPG COA includes an obligation to plug specified natural gas wells. The COA environmental costs caps are $2.5 , $1.8 , and $1.1 , for UGI Utilities, CPG and PNG, respectively. The COAs for UGI Utilities, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively. At March 31, 2018 , September 30, 2017 and March 31, 2017 , our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Utilities, CPG and PNG totaled $51.9 , $54.3 and $55.7 , respectively. UGI Utilities, CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 7 ). We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to UGI Utilities’ results of operations because UGI Utilities, CPG and PNG receive ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. 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 a former subsidiary. 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 a former subsidiary 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. At March 31, 2018 , September 30, 2017 and March 31, 2017 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside of Pennsylvania was material. AmeriGas Propane AmeriGas OLP Saranac Lake. By letter dated March 6, 2008, the New York State Department of Environmental Conservation (“DEC”) notified AmeriGas OLP that the DEC had placed property purportedly owned by AmeriGas OLP in Saranac Lake, New York on the New York State Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by the DEC disclosed contamination related to a former MGP. At that time, AmeriGas OLP reviewed the study and researched the history of the site, including the extent of AmeriGas OLP’s ownership. In its written response to the DEC in early 2009, AmeriGas OLP disputed DEC’s contention it was a potentially responsible party (“PRP”) as it did not operate the MGP and appeared to only own a portion of the site. The DEC did not respond to the 2009 communication. In March 2017, the DEC communicated to AmeriGas OLP that the DEC had previously issued three Records of Decision (“RODs”) related to the site and requested additional information regarding AmeriGas OLP’s purported ownership. The selected remedies identified in the RODs total approximately $27.7 . Based on public reports, the DEC has commenced implementation of the remediation plan. AmeriGas OLP responded to the DEC’s March 2017 request for ownership information, renewing its challenge to designation as a PRP and identifying potential defenses. In October 2017, the DEC identified a third party PRP with respect to the site. Based on our evaluation of the available information, during the third quarter of Fiscal 2017, the Partnership accrued an environmental remediation liability of $7.5 related to the site. Our share of the actual remediation costs could be significantly more or less than the accrued amount. 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 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 their 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 (“District Court”). In July 2015, the District Court dismissed all claims brought by direct customers. In June 2017, the United States Court of Appeals for the Eighth Circuit (“Eighth Circuit”) ruled en banc to reverse the dismissal by the District Court, which had previously been affirmed by a panel of the Eighth Circuit. In September 2017, we filed a Petition for a Writ of Certiorari to the U.S. Supreme Court appealing the decision of the Eighth Circuit. The petition was denied in January 2018 and, as a result, the case was transferred back to the District Court for further proceedings. In July 2015, the District Court also dismissed all claims brought by the indirect customers other than those for injunctive relief. The indirect customers filed an amended complaint with the District Court claiming injunctive relief and state law claims under Wisconsin, Maine and Vermont law. In September 2016, the District Court dismissed the amended complaint in its entirety. The indirect customers appealed this decision to the Eighth Circuit. On July 21, 2016, several new indirect customer plaintiffs filed an antitrust class action lawsuit against the Partnership in the Western District of Missouri. The new indirect customer class action lawsuit was dismissed in September 2016 and certain indirect customer plaintiffs appealed the decision, consolidating their appeal with the indirect customer appeal still pending in the Eighth Circuit. The parties submitted briefs in October 2017 to the Eighth Circuit and held oral argument in February 2018. The parties are now awaiting the court’s ruling. 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 statements.

Defined Benefit Pension and Oth

Defined Benefit Pension and Other Postretirement Plans	6 Months Ended
	Mar. 31, 2018
Retirement Benefits [Abstract]
Defined Benefit Pension and Other Postretirement Plans	Note 11 — 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 postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, employees of UGI France SAS and its subsidiaries are covered by certain defined benefit pension and postretirement plans. Net periodic pension expense and other postretirement benefit costs include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended March 31, 2018 2017 2018 2017 Service cost $ 2.8 $ 3.0 $ 0.2 $ 0.3 Interest cost 6.5 6.1 0.2 0.2 Expected return on assets (8.6 ) (8.3 ) (0.2 ) (0.1 ) Amortization of: Prior service cost (benefit) 0.1 — — (0.2 ) Actuarial loss 3.3 4.2 — — Net benefit cost 4.1 5.0 0.2 0.2 Change in associated regulatory liabilities — — (0.1 ) (0.1 ) Net benefit cost after change in regulatory liabilities $ 4.1 $ 5.0 $ 0.1 $ 0.1 Pension Benefits Other Postretirement Benefits Six Months Ended March 31, 2018 2017 2018 2017 Service cost $ 5.6 $ 6.0 $ 0.4 $ 0.5 Interest cost 13.0 12.3 0.4 0.4 Expected return on assets (17.2 ) (16.6 ) (0.4 ) (0.3 ) Amortization of: Prior service cost (benefit) 0.2 0.1 (0.1 ) (0.3 ) Actuarial loss 6.6 8.3 — 0.1 Net benefit cost 8.2 10.1 0.3 0.4 Change in associated regulatory liabilities — — (0.2 ) (0.2 ) Net benefit cost after change in regulatory liabilities $ 8.2 $ 10.1 $ 0.1 $ 0.2 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, UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. During the six months ended March 31, 2018 and 2017 , the Company made cash contributions to the U.S. Pension Plan of $6.7 and $5.7 , respectively. The Company expects to make additional discretionary cash contributions of approximately $6.7 to the U.S. Pension Plan during the remainder of Fiscal 2018 . 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. The difference between such cash deposits or expense recorded and amounts included in UGI Gas’ and Electric Utility’s rates, if any, is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the six months ended March 31, 2018 and 2017 . We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. Net periodic costs associated with these plans for the three and six months ended March 31, 2018 and 2017 , were not material.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 12 — Fair Value Measurements Recurring Fair Value Measurements The following table presents on a gross basis our financial assets and liabilities, including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of March 31, 2018 , September 30, 2017 and March 31, 2017 : Asset (Liability) Level 1 Level 2 Level 3 Total March 31, 2018: Derivative instruments: Assets: Commodity contracts $ 39.6 $ 27.0 $ — $ 66.6 Foreign currency contracts $ — $ 13.9 $ — $ 13.9 Liabilities: Commodity contracts $ (24.3 ) $ (13.5 ) $ — $ (37.8 ) Foreign currency contracts $ — $ (43.5 ) $ — $ (43.5 ) Interest rate contracts $ — $ (1.9 ) $ — $ (1.9 ) Cross-currency contracts $ — $ (2.2 ) $ — $ (2.2 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 37.9 $ — $ — $ 37.9 September 30, 2017: Derivative instruments: Assets: Commodity contracts $ 27.2 $ 76.9 $ — $ 104.1 Foreign currency contracts $ — $ 12.2 $ — $ 12.2 Liabilities: Commodity contracts $ (27.7 ) $ (11.4 ) $ — $ (39.1 ) Foreign currency contracts $ — $ (38.2 ) $ — $ (38.2 ) Interest rate contracts $ — $ (2.3 ) $ — $ (2.3 ) Cross-currency contracts $ — $ (2.9 ) $ — $ (2.9 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 35.6 $ — $ — $ 35.6 March 31, 2017: Derivative instruments: Assets: Commodity contracts $ 56.0 $ 18.0 $ — $ 74.0 Foreign currency contracts $ — $ 15.6 $ — $ 15.6 Cross-currency contracts $ — $ 3.0 $ — $ 3.0 Liabilities: Commodity contracts $ (28.0 ) $ (11.0 ) $ — $ (39.0 ) Foreign currency contracts $ — $ (1.5 ) $ — $ (1.5 ) Interest rate contracts $ — $ (2.2 ) $ — $ (2.2 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 35.2 $ — $ — $ 35.2 (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. 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). The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at March 31, 2018 , September 30, 2017 and March 31, 2017 were as follows: March 31, 2018 September 30, 2017 March 31, 2017 Carrying amount $ 4,316.4 $ 4,211.9 $ 4,238.9 Estimated fair value $ 4,287.3 $ 4,346.8 $ 4,255.0 Financial instruments other than derivative instruments, such as short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit 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 13 . 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. See Note 2 for additional information on this cost method investment.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	6 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 13 — 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. Although our commodity derivative instruments extend over a number of years, a significant portion of our commodity derivative instruments economically hedge commodity price risk during the next twelve months. Commodity Price Risk Regulated Utility Operations Natural Gas 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 PGC. 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. Gains and losses on Gas Utility’s natural gas futures contracts and 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 7 ). Electricity 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. At March 31, 2018 , September 30, 2017 and March 31, 2017 , all Electric Utility forward electricity purchase contracts were subject to the NPNS exception. 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. Gains and losses on Electric Utility FTRs 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 DS mechanism (see Note 7 ). Non-utility Operations LPG 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, AmeriGas Partners, certain other domestic businesses 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. Also, Midstream & Marketing, from time to time, uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of propane. Natural Gas In order to manage market price risk relating to fixed-price sales contracts for natural gas, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and forward contracts and Intercontinental Exchange (“ICE”) natural gas basis swap contracts. 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. UGI International also uses natural gas futures and forward contracts to economically hedge market price risk associated with fixed-price sales contracts with its customers. Electricity In order to manage market price risk relating to fixed-price sales contracts for electricity, Midstream & Marketing enters into electricity futures and forward contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. From time to time, 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. UGI International also uses electricity futures and forward contracts to economically hedge market price risk associated with fixed-price sales and purchase contracts for electricity. Interest Rate Risk UGI France SAS’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. UGI France SAS and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rates and LIBOR rates of interest on their variable-rate term loans. 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”). We account for interest rate swaps and IRPAs as cash flow hedges. At March 31, 2018 , 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 $3.5 . Foreign Currency Exchange Rate Risk Forward Foreign Currency Exchange Contracts In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March. We account for these foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At March 31, 2018 , the amount of net losses associated with currency rate risk expected to be reclassified into earnings during the next twelve months based upon current fair values is $3.7 . Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign currency exchange contracts. The fair value of these forward foreign currency contracts are recorded as assets or liabilities on the condensed consolidated balance sheets. Changes in the fair value of these foreign currency exchange contracts are recorded in “Losses on foreign currency contracts, net” on the Condensed Consolidated Statements of Income. From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our UGI International euro-denominated net investments. We account for these foreign currency exchange contracts as net investment hedges. At March 31, 2018 and 2017 , there were no unsettled net investment hedges outstanding. 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 the foreign currency and interest rate risk of U.S. dollar-denominated debt. 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 floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designate these cross-currency swaps as cash flow hedges. At March 31, 2018 , the amount of net losses associated with such cross-currency swaps expected to be reclassified into earnings during the next twelve months is not material. Quantitative Disclosures Related to Derivative Instruments The following table summarizes, by derivative type, the gross notional amounts related to open derivative contracts as of March 31, 2018 , September 30, 2017 and March 31, 2017 , and the final settlement date of the Company's open derivative transactions as of March 31, 2018 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through March 31, 2018 September 30, 2017 March 31, 2017 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms March 2019 12.7 14.8 9.0 FTRs contracts Kilowatt hours May 2018 25.5 101.2 14.6 Non-utility Operations LPG swaps & options Gallons March 2020 229.2 325.5 241.6 Natural gas futures, forward and pipeline contracts (a) Dekatherms March 2022 128.9 75.9 56.5 Natural gas basis swap contracts Dekatherms March 2022 74.1 104.2 107.2 NYMEX natural gas storage Dekatherms March 2019 0.9 1.9 1.4 NYMEX propane storage Gallons N/A — 0.3 — Electricity long forward and futures contracts (a) Kilowatt hours January 2022 4,184.1 4,440.3 668.7 Electricity short forward and futures contracts Kilowatt hours May 2021 490.9 447.0 526.1 Interest Rate Risk: Interest rate swaps Euro October 2020 € 645.8 € 645.8 € 645.8 Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2021 $ 496.2 $ 424.8 $ 321.8 Cross-currency contracts USD April 2020 $ 49.9 $ 59.1 $ 59.1 (a) Amounts at March 31, 2018 and September 30, 2017 , include derivative contracts held by DVEP which was acquired on August 31, 2017. 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 March 31, 2018 , September 30, 2017 and March 31, 2017 , restricted cash in brokerage accounts totaled $10.6 , $10.3 and $0.3 , respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss we would incur if these counterparties failed to perform according to the terms of their contracts, based upon the gross fair values of the derivative instruments, was not material at March 31, 2018 . Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At March 31, 2018 , 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 the condensed consolidated balance sheets if the right of offset exists. We offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty. 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 the 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 by type, as well as the effects of offsetting, as of March 31, 2018 , September 30, 2017 and March 31, 2017 : March 31, September 30, March 31, Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 0.3 $ 3.2 $ 14.2 Cross-currency contracts — — 3.0 0.3 3.2 17.2 Derivatives subject to PGC and DS mechanisms: Commodity contracts 0.9 1.7 2.1 Derivatives not designated as hedging instruments: Commodity contracts 65.7 102.4 71.9 Foreign currency contracts 13.6 9.0 1.4 79.3 111.4 73.3 Total derivative assets — gross 80.5 116.3 92.6 Gross amounts offset in the balance sheet (31.5 ) (35.7 ) (31.8 ) Cash collateral received (0.4 ) (8.3 ) (0.2 ) Total derivative assets — net $ 48.6 $ 72.3 $ 60.6 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ (4.0 ) $ (5.5 ) $ — Cross-currency contracts (2.2 ) (2.9 ) — Interest rate contracts (1.9 ) (2.3 ) (2.2 ) (8.1 ) (10.7 ) (2.2 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (0.6 ) (1.5 ) (0.2 ) Derivatives not designated as hedging instruments: Commodity contracts (37.2 ) (37.6 ) (38.8 ) Foreign currency contracts (39.5 ) (32.7 ) (1.5 ) (76.7 ) (70.3 ) (40.3 ) Total derivative liabilities — gross (85.4 ) (82.5 ) (42.7 ) Gross amounts offset in the balance sheet 31.5 35.7 31.8 Total derivative liabilities — net $ (53.9 ) $ (46.8 ) $ (10.9 ) Effect of Derivative Instruments The following tables provide information on the effects of derivative instruments on the condensed consolidated statements of income and changes in AOCI for the six months ended March 31, 2018 and 2017 : Three Months Ended March 31,: Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Cash Flow Hedges: 2018 2017 2018 2017 Foreign currency contracts $ (3.1 ) $ (1.7 ) $ (3.9 ) $ 8.9 Cost of sales Cross-currency contracts 0.3 0.3 0.3 — Interest expense/other operating income, net Interest rate contracts 0.5 0.6 (0.7 ) (1.0 ) Interest expense Total $ (2.3 ) $ (0.8 ) $ (4.3 ) $ 7.9 Gain (Loss) Location of Gain (Loss) Derivatives Not Designated as Hedging Instruments: 2018 2017 Commodity contracts $ (41.8 ) $ 22.0 Cost of sales Commodity contracts (0.2 ) 0.8 Revenues Commodity contracts 0.1 0.1 Operating and administrative expenses Foreign currency contracts (11.0 ) (1.2 ) (Losses) gains on foreign currency contracts, net Total $ (52.9 ) $ 21.7 Six Months Ended March 31,: Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Cash Flow Hedges: 2018 2017 2018 2017 Foreign currency contracts $ (4.5 ) $ 15.5 $ (3.1 ) $ 16.8 Cost of sales Cross-currency contracts 0.4 0.2 0.5 (0.3 ) Interest expense/other operating income, net Interest rate contracts 1.2 1.8 (1.2 ) (2.0 ) Interest expense Total $ (2.9 ) $ 17.5 $ (3.8 ) $ 14.5 Gain (Loss) Location of Gain (Loss) Derivatives Not Designated as Hedging Instruments: 2018 2017 Commodity contracts $ (17.4 ) $ 130.5 Cost of sales Commodity contracts (1.5 ) 0.9 Revenues Commodity contracts 0.2 — Operating and administrative expenses Foreign currency contracts (15.8 ) 0.1 (Losses) gains on foreign currency contracts, net Total $ (34.5 ) $ 131.5 For the three and six months ended March 31, 2018 and 2017 , the amounts of derivative gains or losses representing ineffectiveness and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing were not material. 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 certain of these contracts have the requisite elements of a derivative instrument, these contracts qualify for NPNS exception accounting 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	6 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Accumulated Other Comprehensive Income	Note 14 — Accumulated Other Comprehensive Income The tables below present changes in AOCI during the three and six months ended March 31, 2018 and 2017 : Three Months Ended March 31, 2018 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — December 31, 2017 $ (18.8 ) $ (22.2 ) $ (30.5 ) $ (71.5 ) Other comprehensive (loss) income before reclassification adjustments (after-tax) — (1.6 ) 35.9 34.3 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.4 4.3 — 4.7 Reclassification adjustments tax benefit (0.1 ) (1.5 ) — (1.6 ) Reclassification adjustments (after-tax) 0.3 2.8 — 3.1 Other comprehensive income attributable to UGI 0.3 1.2 35.9 37.4 AOCI — March 31, 2018 $ (18.5 ) $ (21.0 ) $ 5.4 $ (34.1 ) Three Months Ended March 31, 2017 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — December 31, 2016 $ (28.1 ) $ (5.6 ) $ (183.1 ) $ (216.8 ) Other comprehensive (loss) income before reclassification adjustments (after-tax) — (0.5 ) 17.8 17.3 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.7 (7.9 ) — (7.2 ) Reclassification adjustments tax (benefit) expense (0.3 ) 2.5 — 2.2 Reclassification adjustments (after-tax) 0.4 (5.4 ) — (5.0 ) Other comprehensive income (loss) attributable to UGI 0.4 (5.9 ) 17.8 12.3 AOCI — March 31, 2017 $ (27.7 ) $ (11.5 ) $ (165.3 ) $ (204.5 ) Six Months Ended March 31, 2018 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — September 30, 2017 $ (19.2 ) $ (21.4 ) $ (52.8 ) $ (93.4 ) Other comprehensive (loss) income before reclassification adjustments (after-tax) — (2.0 ) 58.2 56.2 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 1.0 3.8 — 4.8 Reclassification adjustments tax benefit (0.3 ) (1.4 ) — (1.7 ) Reclassification adjustments (after-tax) 0.7 2.4 — 3.1 Other comprehensive income attributable to UGI 0.7 0.4 58.2 59.3 AOCI — March 31, 2018 $ (18.5 ) $ (21.0 ) $ 5.4 $ (34.1 ) Six Months Ended March 31, 2017 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — September 30, 2016 $ (29.1 ) $ (13.4 ) $ (112.2 ) $ (154.7 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) — 11.8 (53.1 ) (41.3 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 2.3 (14.5 ) — (12.2 ) Reclassification adjustments tax (benefit) expense (0.9 ) 4.6 — 3.7 Reclassification adjustments (after-tax) 1.4 (9.9 ) — (8.5 ) Other comprehensive income (loss) attributable to UGI 1.4 1.9 (53.1 ) (49.8 ) AOCI — March 31, 2017 $ (27.7 ) $ (11.5 ) $ (165.3 ) $ (204.5 ) For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 13 .

Segment Information

Segment Information	6 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Segment Information	Note 15 — Segment Information Our operations comprise four reportable segments generally based upon products or services sold, geographic location and regulatory environment: (1) AmeriGas Propane; (2) UGI International; (3) Midstream & Marketing; and (4) UGI Utilities. Corporate & Other principally comprise (1) net expenses of UGI’s captive general liability insurance company and UGI’s corporate headquarters facility, and UGI’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other includes net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) because such items are excluded from profit measures evaluated by our chief operating decision maker (“CODM”) in assessing our reportable segments’ performance or allocating resources. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company, and UGI corporate headquarters’ assets. 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 2017 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 the effects of gains and losses on commodity derivative instruments not associated with current-period transactions and other gains and losses that competitors do not necessarily have (“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. Our CODM evaluates the performance of our other reportable segments principally based upon their income before income taxes excluding gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions, as previously mentioned. Three Months Ended March 31, 2018 Total Eliminations AmeriGas Propane UGI International Midstream & Marketing UGI Corporate & Other (b) Revenues $ 2,812.0 $ — $ 1,040.3 $ 909.6 $ 436.2 $ 424.6 $ 1.3 Intersegment revenues $ — $ (188.9 ) (c) $ — $ — $ 129.0 $ 58.7 $ 1.2 Cost of sales $ 1,560.2 $ (187.9 ) (c) $ 483.7 $ 541.1 $ 418.6 $ 257.3 $ 47.4 Segment profit: Operating income (loss) $ 589.5 $ 0.3 $ 266.6 $ 131.8 $ 107.5 $ 135.1 $ (51.8 ) Income (loss) from equity investees 0.7 — — (0.1 ) 0.8 (d) — — Losses on foreign currency contracts, net (11.0 ) — — (9.0 ) — — (2.0 ) Interest expense (58.1 ) — (41.0 ) (5.2 ) (0.7 ) (11.1 ) (0.1 ) Income (loss) before income taxes $ 521.1 $ 0.3 $ 225.6 $ 117.5 $ 107.6 $ 124.0 $ (53.9 ) Partnership Adjusted EBITDA (a) $ 309.5 Noncontrolling interests’ net income (loss) $ 131.7 $ — $ 155.7 $ (1.2 ) $ — $ — $ (22.8 ) Depreciation and amortization $ 112.2 $ (0.1 ) $ 45.2 $ 34.9 $ 10.8 $ 21.1 $ 0.3 Capital expenditures (including the effects of accruals) $ 110.1 $ — $ 23.6 $ 26.1 $ 4.3 $ 55.1 $ 1.0 Three Months Ended March 31, 2017 Total Eliminations AmeriGas Propane UGI International Midstream & Marketing UGI Corporate & Other (b) Revenues $ 2,173.8 $ — $ 863.6 $ 620.7 $ 347.5 $ 341.2 $ 0.8 Intersegment revenues $ — $ (95.8 ) (c) $ — $ — $ 76.2 $ 18.8 $ 0.8 Cost of sales $ 1,071.2 $ (94.9 ) (c) $ 355.8 $ 313.1 $ 309.8 $ 164.5 $ 22.9 Segment profit: Operating income (loss) $ 513.2 $ — $ 227.3 $ 121.0 $ 82.1 $ 116.4 $ (33.6 ) Income (loss) from equity investees 2.3 — — (0.1 ) 2.4 (d) — — (Losses) gains on foreign currency contracts, net (1.2 ) — — 0.1 — — (1.3 ) Loss on extinguishments of debt (22.1 ) — (22.1 ) — — — — Interest expense (55.8 ) — (40.0 ) (4.8 ) (0.7 ) (10.3 ) — Income (loss) before income taxes $ 436.4 $ — $ 165.2 $ 116.2 $ 83.8 $ 106.1 $ (34.9 ) Partnership Adjusted EBITDA (a) $ 271.2 Noncontrolling interests’ net income (loss) $ 91.9 $ — $ 112.7 $ 0.1 $ — $ — $ (20.9 ) Depreciation and amortization $ 99.3 $ (0.1 ) $ 45.0 $ 27.6 $ 8.8 $ 17.7 $ 0.3 Capital expenditures (including the effects of accruals) $ 126.2 $ — $ 27.2 $ 21.5 $ 20.8 $ 56.5 $ 0.2 Six Months Ended March 31, 2018 Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 4,937.2 $ — $ 1,827.6 $ 1,693.8 $ 686.0 $ 730.0 $ (0.2 ) Intersegment revenues $ — $ (286.0 ) (c) $ — $ — $ 207.2 $ 76.4 $ 2.4 Cost of sales $ 2,697.6 $ (283.9 ) (c) $ 849.8 $ 1,025.9 $ 657.6 $ 409.1 $ 39.1 Segment profit: Operating income (loss) $ 981.3 $ 0.5 $ 414.5 $ 224.9 $ 159.8 $ 231.4 $ (49.8 ) Income (loss) from equity investees 1.7 — — (0.3 ) 2.0 (d) — — Losses on foreign currency contracts, net (15.8 ) — — (13.7 ) — — (2.1 ) Interest expense (116.3 ) — (81.6 ) (10.8 ) (1.6 ) (22.0 ) (0.3 ) Income (loss) before income taxes $ 850.9 $ 0.5 $ 332.9 $ 200.1 $ 160.2 $ 209.4 $ (52.2 ) Partnership Adjusted EBITDA (a) $ 503.6 Noncontrolling interests’ net income (loss) $ 200.0 $ — $ 223.7 $ (1.5 ) $ — $ — $ (22.2 ) Depreciation and amortization $ 222.5 $ (0.1 ) $ 92.6 $ 67.1 $ 20.9 $ 41.5 $ 0.5 Capital expenditures (including the effects of accruals) $ 238.6 $ — $ 47.2 $ 47.8 $ 15.6 $ 126.8 $ 1.2 As of March 31, 2018 Total assets $ 12,445.3 $ (59.4 ) $ 4,149.8 $ 3,562.3 $ 1,347.7 $ 3,204.0 $ 240.9 Short-term borrowings $ 302.8 $ — $ 154.5 $ 3.3 $ 10.0 $ 135.0 $ — Goodwill $ 3,218.1 $ — $ 2,001.3 $ 1,023.2 $ 11.5 $ 182.1 $ — Six Months Ended March 31, 2017 Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 3,853.3 $ — $ 1,540.8 $ 1,159.8 $ 557.1 $ 595.1 $ 0.5 Intersegment revenues $ — $ (164.3 ) (c) $ — $ — $ 136.4 $ 26.3 $ 1.6 Cost of sales $ 1,718.6 $ (162.6 ) (c) $ 616.5 $ 571.1 $ 501.6 $ 274.0 $ (82.0 ) Segment profit: Operating income $ 979.4 $ 0.1 $ 369.2 $ 209.9 $ 131.8 $ 198.6 $ 69.8 Income (loss) from equity investees 2.1 — — (0.3 ) 2.4 (d) — — Gains (losses) on foreign currency contracts, net 0.1 — — 0.2 — — (0.1 ) Loss on extinguishments of debt (55.3 ) — (55.3 ) — — — — Interest expense (111.2 ) — (80.0 ) (9.6 ) (1.3 ) (20.3 ) — Income before income taxes $ 815.1 $ 0.1 $ 233.9 $ 200.2 $ 132.9 $ 178.3 $ 69.7 Partnership Adjusted EBITDA (a) $ 456.3 Noncontrolling interests’ net income (loss) $ 152.1 $ — $ 153.9 $ 0.3 $ — $ — $ (2.1 ) Depreciation and amortization $ 197.4 $ (0.1 ) $ 89.6 $ 55.5 $ 16.8 $ 35.1 $ 0.5 Capital expenditures (including the effects of accruals) $ 299.8 $ — $ 53.6 $ 43.0 $ 82.3 $ 120.6 $ 0.3 As of March 31, 2017 Total assets $ 11,385.5 $ (58.6 ) $ 4,238.1 $ 2,804.7 $ 1,200.7 $ 2,909.7 $ 290.9 Short-term borrowings $ 50.1 $ — $ — $ 1.6 $ — $ 48.5 $ — Goodwill $ 2,948.4 $ — $ 1,981.2 $ 773.6 $ 11.5 $ 182.1 $ — (a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: Three Months Ended Six Months Ended 2018 2017 2018 2017 Partnership Adjusted EBITDA $ 309.5 $ 271.2 $ 503.6 $ 456.3 Depreciation and amortization (45.2 ) (45.0 ) (92.6 ) (89.6 ) Interest expense (41.0 ) (40.0 ) (81.6 ) (80.0 ) Loss on extinguishments of debt — (22.1 ) — (55.3 ) Noncontrolling interest (i) 2.3 1.1 3.5 2.5 Income before income taxes $ 225.6 $ 165.2 $ 332.9 $ 233.9 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. (b) Includes net pre-tax (losses) gains on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $(48.1) and $(23.9) during the three months ended March 31, 2018 and 2017 , respectively, and $(41.5) and $81.6 during the six months ended March 31, 2018 and 2017 , respectively. Corporate & Other results for the three and six months ended March 31, 2017 , also include a pre-tax loss of $7.0 associated with the impairment of a cost basis investment (see Note 2). (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) Represents allowance for funds used during construction (“AFUDC”) associated with our PennEast Pipeline equity investment.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Mar. 31, 2018
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.
Derivative Instruments	Derivative Instruments. Derivative instruments are reported on the condensed consolidated balance sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception. 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. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”), 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. Unrealized gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities (for which NPNS has not been elected) are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. From time to time, we also enter into net investment hedges. 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. Beginning October 1, 2016, in order to reduce the volatility in net income associated with our foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we have entered into forward foreign currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “ (Losses) gains on foreign currency contracts, net ” on the Condensed Consolidated Statements of Income. Cash flows from derivative instruments, other than certain cross-currency swaps and net investment hedges, if any, are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges, if any, are included in cash flows from operating activities while cash flows from the currency portion of such hedges, if any, are included in cash flows from financing activities. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows.
Impairment of Cost Basis Investments	Impairment of Cost Basis Investments . We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary. In March 2017, we recorded a pre-tax loss of $7.0 associated with an other-than-temporary impairment of our investment in a private equity partnership that invests in renewable energy companies. This loss is reflected in “ Other operating income, net ” on the Condensed Consolidated Statements of Income for the three and six months ended March 31, 2017.
Income Taxes	Income Taxes. UGI’s consolidated effective income tax rate, defined as total income taxes 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	Use of Estimates. The preparation of financial statements 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.
Reclassifications	Reclassifications. Certain prior period amounts have been reclassified to conform to the current-period presentation.
Accounting Standards Not Yet Adopted	Accounting Standards Not Yet Adopted Other Comprehensive Income. In February 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU provides that the stranded tax effects in AOCI resulting from the TCJA may be reclassified to retained earnings, at the election of the entity, in the period of adoption. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required only prospectively. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit costs and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization when applicable. For entities subject to rate regulation, however, the ASU recognized that in the event a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of a regulatory asset or liability. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) with a retrospective adoption for income statement presentation and a prospective adoption for capitalization. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in the ASU are required to be adopted on a retrospective basis. The ASU is effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. We currently expect to adopt this ASU effective October 1, 2018. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” (“ASU 2014-09”) The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. ASU 2014-09 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. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of analyzing the impact of the new guidance using an integrated approach which includes evaluating differences in the amount and timing of revenue recognition from applying the requirements of the new guidance, reviewing its accounting policies and practices, and assessing the need for changes to its processes, accounting systems and design of internal controls. The Company has completed the assessment of a significant number of its contracts with customers under the new guidance to determine the effect of the adoption of the new guidance. Although the Company has not completed its assessment of the impact of the new guidance, the Company does not expect its adoption will have a material impact on its consolidated financial statements. The Company continues to monitor developments associated with certain utility industry specific guidance for possible impacts on the recognition of revenue by UGI Utilities. The Company anticipates that it will adopt the new standard using the modified retrospective transition method effective October 1, 2018.

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Mar. 31, 2018
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 Six Months Ended 2018 2017 2018 2017 Denominator (thousands of shares): Weighted-average common shares outstanding — basic 173,570 173,624 173,617 173,567 Incremental shares issuable for stock options and awards (a) 2,780 3,512 3,029 3,409 Weighted-average common shares outstanding — diluted 176,350 177,136 176,646 176,976 (a) For the three and six months ended March 31, 2018 , there were 2,486 shares associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive. For the three and six months ended March 31, 2017 , there were no such antidilutive shares.

Inventories (Tables)

Inventories (Tables)	6 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
Components of Inventories	Inventories comprise the following: March 31, September 30, March 31, Non-utility LPG and natural gas $ 163.0 $ 188.4 $ 143.1 Gas Utility natural gas 3.5 39.5 2.4 Materials, supplies and other 61.8 50.7 57.5 Total inventories $ 228.3 $ 278.6 $ 203.0

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Summary of Discrete Deferred Tax Adjustments	Discrete deferred income tax adjustments recorded during each of the three month periods ended December 31, 2017 and March 31, 2018, and the six months ended March 31, 2018, which reduced (increased) income tax expense consisted primarily of the following items: Provisional amounts - Three months ended December 31, 2017 Changes to provisional amounts - Three months ended March 31, 2018 Provisional amounts - Six months ended March 31, 2018 Reduction in net deferred tax liabilities in the U.S. from the reduction of the U.S. tax rate $ 180.3 $ — $ 180.3 Establishment of valuation allowances related to deferred tax assets impacted by TCJA (12.6 ) 5.0 (7.6 ) Toll-tax on un-repatriated earnings (1.7 ) 0.3 (1.4 ) Total discrete deferred income tax adjustments $ 166.0 $ 5.3 $ 171.3 Impact on earnings per share: Basic earnings per share $ 0.96 $ 0.03 $ 0.99 Diluted earnings per share $ 0.94 $ 0.03 $ 0.97

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	6 Months Ended
	Mar. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Components of Company's Goodwill and Intangible Assets	Goodwill and intangible assets comprise the following: March 31, September 30, March 31, Goodwill (not subject to amortization) $ 3,218.1 $ 3,107.2 $ 2,948.4 Intangible assets: Customer relationships, noncompete agreements and other $ 867.0 $ 817.8 $ 764.3 Accumulated amortization (376.2 ) (340.2 ) (342.4 ) Intangible assets, net (definite-lived) 490.8 477.6 421.9 Trademarks and tradenames (indefinite-lived) 136.3 134.1 129.1 Total intangible assets, net $ 627.1 $ 611.7 $ 551.0

Utility Regulatory Assets and29

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)	6 Months Ended
	Mar. 31, 2018
Regulated Operations [Abstract]
Schedule of Regulatory Assets	The following regulatory assets and liabilities associated with UGI Utilities are included in our accompanying condensed consolidated balance sheets: March 31, September 30, March 31, Regulatory assets: Income taxes recoverable $ 128.3 $ 121.4 $ 120.3 Underfunded pension and postretirement plans 135.3 141.3 175.6 Environmental costs 59.8 61.6 62.2 Deferred fuel and power costs 0.7 7.7 1.3 Removal costs, net 30.5 31.0 28.8 Other 7.0 5.9 6.5 Total regulatory assets $ 361.6 $ 368.9 $ 394.7 Regulatory liabilities (a): Postretirement benefits $ 17.1 $ 17.5 $ 17.0 Deferred fuel and power refunds 35.3 10.6 13.8 State tax benefits — distribution system repairs 19.9 18.4 16.1 Excess federal deferred income taxes (b) 301.2 — — Other 7.2 2.7 3.6 Total regulatory liabilities $ 380.7 $ 49.2 $ 50.5 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Condensed Consolidated Balance Sheets. (b) Balance at March 31, 2018 , comprises excess deferred federal income taxes resulting from the enactment of the TCJA (see below and Note 5 ).
Schedule of Regulatory Liabilities	The following regulatory assets and liabilities associated with UGI Utilities are included in our accompanying condensed consolidated balance sheets: March 31, September 30, March 31, Regulatory assets: Income taxes recoverable $ 128.3 $ 121.4 $ 120.3 Underfunded pension and postretirement plans 135.3 141.3 175.6 Environmental costs 59.8 61.6 62.2 Deferred fuel and power costs 0.7 7.7 1.3 Removal costs, net 30.5 31.0 28.8 Other 7.0 5.9 6.5 Total regulatory assets $ 361.6 $ 368.9 $ 394.7 Regulatory liabilities (a): Postretirement benefits $ 17.1 $ 17.5 $ 17.0 Deferred fuel and power refunds 35.3 10.6 13.8 State tax benefits — distribution system repairs 19.9 18.4 16.1 Excess federal deferred income taxes (b) 301.2 — — Other 7.2 2.7 3.6 Total regulatory liabilities $ 380.7 $ 49.2 $ 50.5 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Condensed Consolidated Balance Sheets. (b) Balance at March 31, 2018 , comprises excess deferred federal income taxes resulting from the enactment of the TCJA (see below and Note 5 ).

Energy Services Accounts Rece30

Energy Services Accounts Receivable Securitization Facility (Tables)	6 Months Ended
	Mar. 31, 2018
Transfers and Servicing [Abstract]
Schedule of Transfer of Trade Receivables	Information regarding the trade receivables transferred to ESFC and the amounts sold to the bank for the six months ended March 31, 2018 and 2017 , as well as the balance of ESFC trade receivables at March 31, 2018 , September 30, 2017 and March 31, 2017 , is as follows: Six Months Ended March 31, 2018 2017 Trade receivables transferred to ESFC during the period $ 806.9 $ 633.7 ESFC trade receivables sold to the bank during the period $ 128.0 $ 151.0 March 31, 2018 September 30, 2017 March 31, 2017 ESFC trade receivables — end of period (a) $ 99.6 $ 44.8 $ 85.3 (a) At March 31, 2018 and September 30, 2017 , the amounts of ESFC trade receivables sold to the bank were $10.0 and $39.0 , respectively. At March 31, 2017 , there were no ESFC trade receivables sold to the bank. Amounts sold to the bank are reflected as “ Short-term borrowings ” on the Condensed Consolidated Balance Sheets.

Defined Benefit Pension and O31

Defined Benefit Pension and Other Postretirement Plans (Tables)	6 Months Ended
	Mar. 31, 2018
Retirement Benefits [Abstract]
Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs	Net periodic pension expense and other postretirement benefit costs include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended March 31, 2018 2017 2018 2017 Service cost $ 2.8 $ 3.0 $ 0.2 $ 0.3 Interest cost 6.5 6.1 0.2 0.2 Expected return on assets (8.6 ) (8.3 ) (0.2 ) (0.1 ) Amortization of: Prior service cost (benefit) 0.1 — — (0.2 ) Actuarial loss 3.3 4.2 — — Net benefit cost 4.1 5.0 0.2 0.2 Change in associated regulatory liabilities — — (0.1 ) (0.1 ) Net benefit cost after change in regulatory liabilities $ 4.1 $ 5.0 $ 0.1 $ 0.1 Pension Benefits Other Postretirement Benefits Six Months Ended March 31, 2018 2017 2018 2017 Service cost $ 5.6 $ 6.0 $ 0.4 $ 0.5 Interest cost 13.0 12.3 0.4 0.4 Expected return on assets (17.2 ) (16.6 ) (0.4 ) (0.3 ) Amortization of: Prior service cost (benefit) 0.2 0.1 (0.1 ) (0.3 ) Actuarial loss 6.6 8.3 — 0.1 Net benefit cost 8.2 10.1 0.3 0.4 Change in associated regulatory liabilities — — (0.2 ) (0.2 ) Net benefit cost after change in regulatory liabilities $ 8.2 $ 10.1 $ 0.1 $ 0.2

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	6 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Financial Assets and Financial Liabilities that are Measured at Fair Value on a Recurring Basis	The following table presents on a gross basis our financial assets and liabilities, including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of March 31, 2018 , September 30, 2017 and March 31, 2017 : Asset (Liability) Level 1 Level 2 Level 3 Total March 31, 2018: Derivative instruments: Assets: Commodity contracts $ 39.6 $ 27.0 $ — $ 66.6 Foreign currency contracts $ — $ 13.9 $ — $ 13.9 Liabilities: Commodity contracts $ (24.3 ) $ (13.5 ) $ — $ (37.8 ) Foreign currency contracts $ — $ (43.5 ) $ — $ (43.5 ) Interest rate contracts $ — $ (1.9 ) $ — $ (1.9 ) Cross-currency contracts $ — $ (2.2 ) $ — $ (2.2 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 37.9 $ — $ — $ 37.9 September 30, 2017: Derivative instruments: Assets: Commodity contracts $ 27.2 $ 76.9 $ — $ 104.1 Foreign currency contracts $ — $ 12.2 $ — $ 12.2 Liabilities: Commodity contracts $ (27.7 ) $ (11.4 ) $ — $ (39.1 ) Foreign currency contracts $ — $ (38.2 ) $ — $ (38.2 ) Interest rate contracts $ — $ (2.3 ) $ — $ (2.3 ) Cross-currency contracts $ — $ (2.9 ) $ — $ (2.9 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 35.6 $ — $ — $ 35.6 March 31, 2017: Derivative instruments: Assets: Commodity contracts $ 56.0 $ 18.0 $ — $ 74.0 Foreign currency contracts $ — $ 15.6 $ — $ 15.6 Cross-currency contracts $ — $ 3.0 $ — $ 3.0 Liabilities: Commodity contracts $ (28.0 ) $ (11.0 ) $ — $ (39.0 ) Foreign currency contracts $ — $ (1.5 ) $ — $ (1.5 ) Interest rate contracts $ — $ (2.2 ) $ — $ (2.2 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 35.2 $ — $ — $ 35.2 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.
Schedule of Carrying Amount and Estimated Fair Value of Long-term Debt	The carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) at March 31, 2018 , September 30, 2017 and March 31, 2017 were as follows: March 31, 2018 September 30, 2017 March 31, 2017 Carrying amount $ 4,316.4 $ 4,211.9 $ 4,238.9 Estimated fair value $ 4,287.3 $ 4,346.8 $ 4,255.0

Derivative Instruments and He33

Derivative Instruments and Hedging Activities (Tables)	6 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts Related to Open Derivative Contracts	The following table summarizes, by derivative type, the gross notional amounts related to open derivative contracts as of March 31, 2018 , September 30, 2017 and March 31, 2017 , and the final settlement date of the Company's open derivative transactions as of March 31, 2018 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through March 31, 2018 September 30, 2017 March 31, 2017 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms March 2019 12.7 14.8 9.0 FTRs contracts Kilowatt hours May 2018 25.5 101.2 14.6 Non-utility Operations LPG swaps & options Gallons March 2020 229.2 325.5 241.6 Natural gas futures, forward and pipeline contracts (a) Dekatherms March 2022 128.9 75.9 56.5 Natural gas basis swap contracts Dekatherms March 2022 74.1 104.2 107.2 NYMEX natural gas storage Dekatherms March 2019 0.9 1.9 1.4 NYMEX propane storage Gallons N/A — 0.3 — Electricity long forward and futures contracts (a) Kilowatt hours January 2022 4,184.1 4,440.3 668.7 Electricity short forward and futures contracts Kilowatt hours May 2021 490.9 447.0 526.1 Interest Rate Risk: Interest rate swaps Euro October 2020 € 645.8 € 645.8 € 645.8 Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2021 $ 496.2 $ 424.8 $ 321.8 Cross-currency contracts USD April 2020 $ 49.9 $ 59.1 $ 59.1 (a) Amounts at March 31, 2018 and September 30, 2017 , include derivative contracts held by DVEP which was acquired on August 31, 2017.
Schedule of Derivative Assets, Liabilities and the Effects of Offsetting	The following table presents the Company’s derivative assets and liabilities by type, as well as the effects of offsetting, as of March 31, 2018 , September 30, 2017 and March 31, 2017 : March 31, September 30, March 31, Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 0.3 $ 3.2 $ 14.2 Cross-currency contracts — — 3.0 0.3 3.2 17.2 Derivatives subject to PGC and DS mechanisms: Commodity contracts 0.9 1.7 2.1 Derivatives not designated as hedging instruments: Commodity contracts 65.7 102.4 71.9 Foreign currency contracts 13.6 9.0 1.4 79.3 111.4 73.3 Total derivative assets — gross 80.5 116.3 92.6 Gross amounts offset in the balance sheet (31.5 ) (35.7 ) (31.8 ) Cash collateral received (0.4 ) (8.3 ) (0.2 ) Total derivative assets — net $ 48.6 $ 72.3 $ 60.6 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ (4.0 ) $ (5.5 ) $ — Cross-currency contracts (2.2 ) (2.9 ) — Interest rate contracts (1.9 ) (2.3 ) (2.2 ) (8.1 ) (10.7 ) (2.2 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (0.6 ) (1.5 ) (0.2 ) Derivatives not designated as hedging instruments: Commodity contracts (37.2 ) (37.6 ) (38.8 ) Foreign currency contracts (39.5 ) (32.7 ) (1.5 ) (76.7 ) (70.3 ) (40.3 ) Total derivative liabilities — gross (85.4 ) (82.5 ) (42.7 ) Gross amounts offset in the balance sheet 31.5 35.7 31.8 Total derivative liabilities — net $ (53.9 ) $ (46.8 ) $ (10.9 )
Effects of Derivative Instruments on Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest	The following tables provide information on the effects of derivative instruments on the condensed consolidated statements of income and changes in AOCI for the six months ended March 31, 2018 and 2017 : Three Months Ended March 31,: Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Cash Flow Hedges: 2018 2017 2018 2017 Foreign currency contracts $ (3.1 ) $ (1.7 ) $ (3.9 ) $ 8.9 Cost of sales Cross-currency contracts 0.3 0.3 0.3 — Interest expense/other operating income, net Interest rate contracts 0.5 0.6 (0.7 ) (1.0 ) Interest expense Total $ (2.3 ) $ (0.8 ) $ (4.3 ) $ 7.9 Gain (Loss) Location of Gain (Loss) Derivatives Not Designated as Hedging Instruments: 2018 2017 Commodity contracts $ (41.8 ) $ 22.0 Cost of sales Commodity contracts (0.2 ) 0.8 Revenues Commodity contracts 0.1 0.1 Operating and administrative expenses Foreign currency contracts (11.0 ) (1.2 ) (Losses) gains on foreign currency contracts, net Total $ (52.9 ) $ 21.7 Six Months Ended March 31,: Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Cash Flow Hedges: 2018 2017 2018 2017 Foreign currency contracts $ (4.5 ) $ 15.5 $ (3.1 ) $ 16.8 Cost of sales Cross-currency contracts 0.4 0.2 0.5 (0.3 ) Interest expense/other operating income, net Interest rate contracts 1.2 1.8 (1.2 ) (2.0 ) Interest expense Total $ (2.9 ) $ 17.5 $ (3.8 ) $ 14.5 Gain (Loss) Location of Gain (Loss) Derivatives Not Designated as Hedging Instruments: 2018 2017 Commodity contracts $ (17.4 ) $ 130.5 Cost of sales Commodity contracts (1.5 ) 0.9 Revenues Commodity contracts 0.2 — Operating and administrative expenses Foreign currency contracts (15.8 ) 0.1 (Losses) gains on foreign currency contracts, net Total $ (34.5 ) $ 131.5

Accumulated Other Comprehensi34

Accumulated Other Comprehensive Income (Tables)	6 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income	The tables below present changes in AOCI during the three and six months ended March 31, 2018 and 2017 : Three Months Ended March 31, 2018 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — December 31, 2017 $ (18.8 ) $ (22.2 ) $ (30.5 ) $ (71.5 ) Other comprehensive (loss) income before reclassification adjustments (after-tax) — (1.6 ) 35.9 34.3 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.4 4.3 — 4.7 Reclassification adjustments tax benefit (0.1 ) (1.5 ) — (1.6 ) Reclassification adjustments (after-tax) 0.3 2.8 — 3.1 Other comprehensive income attributable to UGI 0.3 1.2 35.9 37.4 AOCI — March 31, 2018 $ (18.5 ) $ (21.0 ) $ 5.4 $ (34.1 ) Three Months Ended March 31, 2017 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — December 31, 2016 $ (28.1 ) $ (5.6 ) $ (183.1 ) $ (216.8 ) Other comprehensive (loss) income before reclassification adjustments (after-tax) — (0.5 ) 17.8 17.3 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.7 (7.9 ) — (7.2 ) Reclassification adjustments tax (benefit) expense (0.3 ) 2.5 — 2.2 Reclassification adjustments (after-tax) 0.4 (5.4 ) — (5.0 ) Other comprehensive income (loss) attributable to UGI 0.4 (5.9 ) 17.8 12.3 AOCI — March 31, 2017 $ (27.7 ) $ (11.5 ) $ (165.3 ) $ (204.5 ) Six Months Ended March 31, 2018 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — September 30, 2017 $ (19.2 ) $ (21.4 ) $ (52.8 ) $ (93.4 ) Other comprehensive (loss) income before reclassification adjustments (after-tax) — (2.0 ) 58.2 56.2 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 1.0 3.8 — 4.8 Reclassification adjustments tax benefit (0.3 ) (1.4 ) — (1.7 ) Reclassification adjustments (after-tax) 0.7 2.4 — 3.1 Other comprehensive income attributable to UGI 0.7 0.4 58.2 59.3 AOCI — March 31, 2018 $ (18.5 ) $ (21.0 ) $ 5.4 $ (34.1 ) Six Months Ended March 31, 2017 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — September 30, 2016 $ (29.1 ) $ (13.4 ) $ (112.2 ) $ (154.7 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) — 11.8 (53.1 ) (41.3 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 2.3 (14.5 ) — (12.2 ) Reclassification adjustments tax (benefit) expense (0.9 ) 4.6 — 3.7 Reclassification adjustments (after-tax) 1.4 (9.9 ) — (8.5 ) Other comprehensive income (loss) attributable to UGI 1.4 1.9 (53.1 ) (49.8 ) AOCI — March 31, 2017 $ (27.7 ) $ (11.5 ) $ (165.3 ) $ (204.5 )

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Schedule of Segment Reporting Information	Three Months Ended March 31, 2018 Total Eliminations AmeriGas Propane UGI International Midstream & Marketing UGI Corporate & Other (b) Revenues $ 2,812.0 $ — $ 1,040.3 $ 909.6 $ 436.2 $ 424.6 $ 1.3 Intersegment revenues $ — $ (188.9 ) (c) $ — $ — $ 129.0 $ 58.7 $ 1.2 Cost of sales $ 1,560.2 $ (187.9 ) (c) $ 483.7 $ 541.1 $ 418.6 $ 257.3 $ 47.4 Segment profit: Operating income (loss) $ 589.5 $ 0.3 $ 266.6 $ 131.8 $ 107.5 $ 135.1 $ (51.8 ) Income (loss) from equity investees 0.7 — — (0.1 ) 0.8 (d) — — Losses on foreign currency contracts, net (11.0 ) — — (9.0 ) — — (2.0 ) Interest expense (58.1 ) — (41.0 ) (5.2 ) (0.7 ) (11.1 ) (0.1 ) Income (loss) before income taxes $ 521.1 $ 0.3 $ 225.6 $ 117.5 $ 107.6 $ 124.0 $ (53.9 ) Partnership Adjusted EBITDA (a) $ 309.5 Noncontrolling interests’ net income (loss) $ 131.7 $ — $ 155.7 $ (1.2 ) $ — $ — $ (22.8 ) Depreciation and amortization $ 112.2 $ (0.1 ) $ 45.2 $ 34.9 $ 10.8 $ 21.1 $ 0.3 Capital expenditures (including the effects of accruals) $ 110.1 $ — $ 23.6 $ 26.1 $ 4.3 $ 55.1 $ 1.0 Three Months Ended March 31, 2017 Total Eliminations AmeriGas Propane UGI International Midstream & Marketing UGI Corporate & Other (b) Revenues $ 2,173.8 $ — $ 863.6 $ 620.7 $ 347.5 $ 341.2 $ 0.8 Intersegment revenues $ — $ (95.8 ) (c) $ — $ — $ 76.2 $ 18.8 $ 0.8 Cost of sales $ 1,071.2 $ (94.9 ) (c) $ 355.8 $ 313.1 $ 309.8 $ 164.5 $ 22.9 Segment profit: Operating income (loss) $ 513.2 $ — $ 227.3 $ 121.0 $ 82.1 $ 116.4 $ (33.6 ) Income (loss) from equity investees 2.3 — — (0.1 ) 2.4 (d) — — (Losses) gains on foreign currency contracts, net (1.2 ) — — 0.1 — — (1.3 ) Loss on extinguishments of debt (22.1 ) — (22.1 ) — — — — Interest expense (55.8 ) — (40.0 ) (4.8 ) (0.7 ) (10.3 ) — Income (loss) before income taxes $ 436.4 $ — $ 165.2 $ 116.2 $ 83.8 $ 106.1 $ (34.9 ) Partnership Adjusted EBITDA (a) $ 271.2 Noncontrolling interests’ net income (loss) $ 91.9 $ — $ 112.7 $ 0.1 $ — $ — $ (20.9 ) Depreciation and amortization $ 99.3 $ (0.1 ) $ 45.0 $ 27.6 $ 8.8 $ 17.7 $ 0.3 Capital expenditures (including the effects of accruals) $ 126.2 $ — $ 27.2 $ 21.5 $ 20.8 $ 56.5 $ 0.2 Six Months Ended March 31, 2018 Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 4,937.2 $ — $ 1,827.6 $ 1,693.8 $ 686.0 $ 730.0 $ (0.2 ) Intersegment revenues $ — $ (286.0 ) (c) $ — $ — $ 207.2 $ 76.4 $ 2.4 Cost of sales $ 2,697.6 $ (283.9 ) (c) $ 849.8 $ 1,025.9 $ 657.6 $ 409.1 $ 39.1 Segment profit: Operating income (loss) $ 981.3 $ 0.5 $ 414.5 $ 224.9 $ 159.8 $ 231.4 $ (49.8 ) Income (loss) from equity investees 1.7 — — (0.3 ) 2.0 (d) — — Losses on foreign currency contracts, net (15.8 ) — — (13.7 ) — — (2.1 ) Interest expense (116.3 ) — (81.6 ) (10.8 ) (1.6 ) (22.0 ) (0.3 ) Income (loss) before income taxes $ 850.9 $ 0.5 $ 332.9 $ 200.1 $ 160.2 $ 209.4 $ (52.2 ) Partnership Adjusted EBITDA (a) $ 503.6 Noncontrolling interests’ net income (loss) $ 200.0 $ — $ 223.7 $ (1.5 ) $ — $ — $ (22.2 ) Depreciation and amortization $ 222.5 $ (0.1 ) $ 92.6 $ 67.1 $ 20.9 $ 41.5 $ 0.5 Capital expenditures (including the effects of accruals) $ 238.6 $ — $ 47.2 $ 47.8 $ 15.6 $ 126.8 $ 1.2 As of March 31, 2018 Total assets $ 12,445.3 $ (59.4 ) $ 4,149.8 $ 3,562.3 $ 1,347.7 $ 3,204.0 $ 240.9 Short-term borrowings $ 302.8 $ — $ 154.5 $ 3.3 $ 10.0 $ 135.0 $ — Goodwill $ 3,218.1 $ — $ 2,001.3 $ 1,023.2 $ 11.5 $ 182.1 $ — Six Months Ended March 31, 2017 Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 3,853.3 $ — $ 1,540.8 $ 1,159.8 $ 557.1 $ 595.1 $ 0.5 Intersegment revenues $ — $ (164.3 ) (c) $ — $ — $ 136.4 $ 26.3 $ 1.6 Cost of sales $ 1,718.6 $ (162.6 ) (c) $ 616.5 $ 571.1 $ 501.6 $ 274.0 $ (82.0 ) Segment profit: Operating income $ 979.4 $ 0.1 $ 369.2 $ 209.9 $ 131.8 $ 198.6 $ 69.8 Income (loss) from equity investees 2.1 — — (0.3 ) 2.4 (d) — — Gains (losses) on foreign currency contracts, net 0.1 — — 0.2 — — (0.1 ) Loss on extinguishments of debt (55.3 ) — (55.3 ) — — — — Interest expense (111.2 ) — (80.0 ) (9.6 ) (1.3 ) (20.3 ) — Income before income taxes $ 815.1 $ 0.1 $ 233.9 $ 200.2 $ 132.9 $ 178.3 $ 69.7 Partnership Adjusted EBITDA (a) $ 456.3 Noncontrolling interests’ net income (loss) $ 152.1 $ — $ 153.9 $ 0.3 $ — $ — $ (2.1 ) Depreciation and amortization $ 197.4 $ (0.1 ) $ 89.6 $ 55.5 $ 16.8 $ 35.1 $ 0.5 Capital expenditures (including the effects of accruals) $ 299.8 $ — $ 53.6 $ 43.0 $ 82.3 $ 120.6 $ 0.3 As of March 31, 2017 Total assets $ 11,385.5 $ (58.6 ) $ 4,238.1 $ 2,804.7 $ 1,200.7 $ 2,909.7 $ 290.9 Short-term borrowings $ 50.1 $ — $ — $ 1.6 $ — $ 48.5 $ — Goodwill $ 2,948.4 $ — $ 1,981.2 $ 773.6 $ 11.5 $ 182.1 $ — (a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: Three Months Ended Six Months Ended 2018 2017 2018 2017 Partnership Adjusted EBITDA $ 309.5 $ 271.2 $ 503.6 $ 456.3 Depreciation and amortization (45.2 ) (45.0 ) (92.6 ) (89.6 ) Interest expense (41.0 ) (40.0 ) (81.6 ) (80.0 ) Loss on extinguishments of debt — (22.1 ) — (55.3 ) Noncontrolling interest (i) 2.3 1.1 3.5 2.5 Income before income taxes $ 225.6 $ 165.2 $ 332.9 $ 233.9 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. (b) Includes net pre-tax (losses) gains on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $(48.1) and $(23.9) during the three months ended March 31, 2018 and 2017 , respectively, and $(41.5) and $81.6 during the six months ended March 31, 2018 and 2017 , respectively. Corporate & Other results for the three and six months ended March 31, 2017 , also include a pre-tax loss of $7.0 associated with the impairment of a cost basis investment (see Note 2). (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) Represents allowance for funds used during construction (“AFUDC”) associated with our PennEast Pipeline equity investment.
Reconciliation of Adjusted EBITDA to (Loss) Income Before Income Taxes	The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: Three Months Ended Six Months Ended 2018 2017 2018 2017 Partnership Adjusted EBITDA $ 309.5 $ 271.2 $ 503.6 $ 456.3 Depreciation and amortization (45.2 ) (45.0 ) (92.6 ) (89.6 ) Interest expense (41.0 ) (40.0 ) (81.6 ) (80.0 ) Loss on extinguishments of debt — (22.1 ) — (55.3 ) Noncontrolling interest (i) 2.3 1.1 3.5 2.5 Income before income taxes $ 225.6 $ 165.2 $ 332.9 $ 233.9 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

Nature of Operations (Details)

Nature of Operations (Details) $ in Millions	6 Months Ended
	Mar. 31, 2018USD ($)county	Mar. 31, 2017USD ($)
Investment [Line Items]
General Partner incentive distribution | $	$ 22.7	$ 20.9
Number of counties of operation | county	1
Amerigas Propane | AmeriGas Partners
Investment [Line Items]
General Partner held a general partner interest in AmeriGas Partners	1.00%
Percentage of limited partnership interest in AmeriGas Partners	25.30%
General public as limited partner interests in AmeriGas Partners	73.70%
Amerigas Propane | AmeriGas OLP
Investment [Line Items]
Effective ownership interest in AmeriGas OLP	27.00%

Summary of Significant Accoun37

Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details) - shares	3 Months Ended		6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Denominator (thousands of shares):
Weighted-average common shares outstanding - basic (in shares)	173,570,000	173,624,000	173,617,000	173,567,000
Incremental shares issuable for stock options and awards (in shares)	2,780,000	3,512,000	3,029,000	3,409,000
Weighted-average common shares outstanding - diluted (in shares)	176,350,000	177,136,000	176,646,000	176,976,000
Antidilutive shares excluded from calculation of earnings per share		0	2,486,000	0

Summary of Significant Accoun38

Summary of Significant Accounting Policies - Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Mar. 31, 2017	Mar. 31, 2018
Accounting Policies [Abstract]
Cost-method investments, impairment	$ 7	$ 7

Inventories - Components of Inv

Inventories - Components of Inventories (Details) - USD ($) $ in Millions	Mar. 31, 2018	Sep. 30, 2017	Mar. 31, 2017
Inventory
Total inventories	$ 228.3	$ 278.6	$ 203
Non-utility LPG and natural gas
Inventory
Total inventories	163	188.4	143.1
Gas Utility natural gas
Inventory
Total inventories	3.5	39.5	2.4
Materials, supplies and other
Inventory
Total inventories	$ 61.8	$ 50.7	$ 57.5

Inventories - Narrative (Detail

Inventories - Narrative (Details) - UGI Utilities $ in Millions	6 Months Ended
	Mar. 31, 2018storage_agreementBcf	Sep. 30, 2017USD ($)Bcf	Mar. 31, 2017Bcf
Inventory
Number of storage agreements | storage_agreement	5
Volume of gas storage inventories released under SCAAs with non-affiliates (in bcf) | Bcf	0	2.3	0
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $		$ 6.7
Maximum
Inventory
SCAA contract term (in years)	3 years

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		6 Months Ended		12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2018	Mar. 31, 2017	Sep. 30, 2018
Operating Loss Carryforwards [Line Items]
Reduction in net deferred income tax liabilities due to the remeasuring of existing federal deferred income tax assets and liabilities	$ 5		$ 388.8
Regulatory liability, excess deferred federal income taxes due to tax reform		$ 216.1
Increase in regulatory liabilities for the tax effect of future revenue reductions		87.8
Estimated deferred tax benefit resulting from future income tax reduction	34		54.5
Foreign Tax Authority | French Parliament
Operating Loss Carryforwards [Line Items]
Effective income tax rate reconciliation, change in enacted tax rate, amount (excluding tax cuts and jobs act of 2017 Impact)	1.1			$ 5
Foreign Tax Authority | French Parliament | January 1, 2022 (Fiscal 2023)
Operating Loss Carryforwards [Line Items]
Income tax benefit, continuing operations, adjustment of deferred taxes	(3.7)	$ 17.3	$ 13.6
Increase in per share, basic and diluted resulting from future income tax reduction (in dollars per share)		$ 0.08
Foreign Tax Authority | French Parliament | January 1, 2020 (Fiscal 2021)
Operating Loss Carryforwards [Line Items]
Income tax benefit, continuing operations, adjustment of deferred taxes	$ 27.4
Increase in per share, basic and diluted resulting from future income tax reduction (in dollars per share)		$ 0.15
Scenario, Forecast
Operating Loss Carryforwards [Line Items]
Effective income tax rate reconciliation, blended federal rate					24.50%

Income Taxes - Summary of Tax C

Income Taxes - Summary of Tax Cuts and Jobs Act of 2017 Effects (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		6 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Reduction in net deferred tax liabilities in the U.S. from the reduction of the U.S. tax rate	$ 0	$ 180.3	$ 180.3
Establishment of valuation allowances related to deferred tax assets impacted by TCJA	5	(12.6)	(7.6)
Toll-tax on un-repatriated earnings	0.3	(1.7)	(1.4)
Total discrete deferred income tax adjustments	$ 5.3	$ 166	$ 171.3
Basic earnings per share (USD per share)	$ 0.03	$ 0.96	$ 0.99
Diluted earnings per share (USD per share)	$ 0.03	$ 0.94	$ 0.97

Goodwill and Intangible Asset43

Goodwill and Intangible Assets - Components of Company's Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	Mar. 31, 2018	Sep. 30, 2017	Mar. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill (not subject to amortization)	$ 3,218.1	$ 3,107.2	$ 2,948.4
Intangible assets:
Customer relationships, noncompete agreements and other	867	817.8	764.3
Accumulated amortization	(376.2)	(340.2)	(342.4)
Intangible assets, net (definite-lived)	490.8	477.6	421.9
Trademarks and tradenames (indefinite-lived)	136.3	134.1	129.1
Total intangible assets, net	$ 627.1	$ 611.7	$ 551

Goodwill and Intangible Asset44

Goodwill and Intangible Assets - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		6 Months Ended
	Apr. 30, 2018	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Amortization expense of intangible assets		$ 13.7	$ 12.4	$ 28.5	$ 24.9
Remainder of Fiscal 2018		28.3		28.3
Fiscal 2,019		54.7		54.7
Fiscal 2,020		53.3		53.3
Fiscal 2,021		51.4		51.4
Fiscal 2,022		49.7		49.7
Indefinite-lived trade names		$ 82.9		$ 82.9
Subsequent Event | Trademarks and Trade Names
Finite-Lived Intangible Assets [Line Items]
Finite-lived intangible asset, useful life	4 years
Scenario, Forecast
Finite-Lived Intangible Assets [Line Items]
Finite lived intangible asset impairment	$ 70
Estimate net income impact	$ 13

Utility Regulatory Assets and45

Utility Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility (Details) - UGI Utilities - USD ($) $ in Millions	Mar. 31, 2018	Sep. 30, 2017	Mar. 31, 2017
Regulatory Assets
Regulatory assets	$ 361.6	$ 368.9	$ 394.7
Regulatory Liabilities
Regulatory liabilities	380.7	49.2	50.5
Postretirement benefits
Regulatory Liabilities
Regulatory liabilities	17.1	17.5	17
Deferred fuel and power refunds
Regulatory Liabilities
Regulatory liabilities	35.3	10.6	13.8
State tax benefits — distribution system repairs
Regulatory Liabilities
Regulatory liabilities	19.9	18.4	16.1
Excess federal deferred income taxes
Regulatory Liabilities
Regulatory liabilities	301.2	0	0
Other
Regulatory Liabilities
Regulatory liabilities	7.2	2.7	3.6
Income taxes recoverable
Regulatory Assets
Regulatory assets	128.3	121.4	120.3
Underfunded pension and postretirement plans
Regulatory Assets
Regulatory assets	135.3	141.3	175.6
Environmental costs
Regulatory Assets
Regulatory assets	59.8	61.6	62.2
Deferred fuel and power costs
Regulatory Assets
Regulatory assets	0.7	7.7	1.3
Removal costs, net
Regulatory Assets
Regulatory assets	30.5	31	28.8
Other
Regulatory Assets
Regulatory assets	$ 7	$ 5.9	$ 6.5

Utility Regulatory Assets and46

Utility Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) - USD ($) $ in Millions	Jan. 26, 2018	Oct. 20, 2017	Jul. 01, 2017	Jan. 01, 2017	Oct. 19, 2016	Apr. 01, 2016	Apr. 01, 2015	Mar. 31, 2018	Sep. 30, 2014	Sep. 30, 2017	Mar. 31, 2017
Minimum
Regulatory Assets
Average remaining depreciable lives of associated property.								1 year
Maximum
Regulatory Assets
Average remaining depreciable lives of associated property.								65 years
Pennsylvania Public Utility Commission
Regulatory Assets
DSIC, percent of amount billed to customers									0.00%
Pennsylvania Public Utility Commission | Electric Utility
Regulatory Assets
Requested rate increase amount	$ 9.2
Pennsylvania Public Utility Commission | PNG
Regulatory Assets
Increase in annual base distribution rate		$ 11.3
DSIC, percent of amount billed to customers			7.50%				0.00%	0.00%
Pennsylvania Public Utility Commission | UGI Gas
Regulatory Assets
Increase in annual base distribution rate					$ 27
Pennsylvania Public Utility Commission | CPG
Regulatory Assets
DSIC, percent of amount billed to customers			7.50%			0.00%
Pennsylvania Public Utility Commission | Maximum
Regulatory Assets
DSIC, percent of amount billed to customers				5.00%
Gas Utility
Regulatory Assets
Fair value of unrealized gains (losses)								$ 0.3		$ 0.1	$ 2

Energy Services Accounts Rece47

Energy Services Accounts Receivable Securitization Facility - Narrative (Details) - USD ($)	6 Months Ended
	Oct. 31, 2018	Apr. 30, 2018
Scenario, Forecast | Maximum
Accounts, Notes, Loans and Financing Receivable
Receivables facility	$ 75,000,000	$ 150,000,000

Energy Services Accounts Rece48

Energy Services Accounts Receivable Securitization Facility - Trade Receivables Transferred and Sold (Details) - ESFC - USD ($)	6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Sep. 30, 2017
Accounts, Notes, Loans and Financing Receivable
Trade receivables transferred to ESFC during the period	$ 806,900,000	$ 633,700,000
ESFC trade receivables sold to the bank during the period	128,000,000	151,000,000
ESFC trade receivables - end of period	99,600,000	85,300,000	$ 44,800,000
Outstanding balance of trade receivables sold	$ 10,000,000	$ 0	$ 39,000,000

Debt - Narrative (Details)

Debt - Narrative (Details)	Oct. 31, 2017USD ($)	Dec. 31, 2017USD ($)	Mar. 31, 2018USD ($)	Mar. 31, 2017USD ($)	Mar. 31, 2018USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2017EUR (€)	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
Loss on extinguishments of debt			$ 0	$ 22,100,000	$ 0	$ 55,300,000
Amerigas Propane | Senior Notes | 7.00% Senior Notes
Debt Instrument [Line Items]
Stated interest rate				7.00%		7.00%
Flaga | Term Loan | Flaga Term Loan Due September 2018
Debt Instrument [Line Items]
Repayment of debt		$ 9,200,000
Line of credit								$ 59,100,000
Flaga | Term Loan | Flaga Term Loan Due September 2020
Debt Instrument [Line Items]
Line of credit								49,900,000
UGI Utilities | Unsecured Debt
Debt Instrument [Line Items]
Debt instrument, face amount	$ 125,000,000
Periodic payment, principal	$ 1,600,000
Minimum | UGI Utilities | Unsecured Debt
Debt Instrument [Line Items]
Basis spread on variable rate	0.00%
Maximum | UGI Utilities | Unsecured Debt
Debt Instrument [Line Items]
Basis spread on variable rate	1.875%
Revolving Credit Facility | Line of Credit | AmeriGas Credit Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity								600,000,000
Revolving Credit Facility | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity | €							€ 300,000,000
Required ratio of total indebtedness to EBITDA		3.50
Letter of Credit | Line of Credit | AmeriGas Credit Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity								$ 150,000,000
Line of Credit | Minimum | AmeriGas OLP | AmeriGas Credit Agreement
Debt Instrument [Line Items]
Facility fee		0.30%
Line of Credit | Maximum | AmeriGas OLP | AmeriGas Credit Agreement
Debt Instrument [Line Items]
Facility fee		0.50%
Federal Funds Rate | AmeriGas Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate		0.50%
Base Rate | Minimum | AmeriGas Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate		0.50%
Base Rate | Maximum | AmeriGas Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate		1.75%
Eurodollar | Minimum | AmeriGas Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate		1.50%
Eurodollar | Maximum | AmeriGas Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate		2.75%
EURIBOR | Revolving Credit Facility | Minimum | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate		1.45%
EURIBOR | Revolving Credit Facility | Maximum | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate		2.35%
London Interbank Offered Rate (LIBOR) | Minimum | Flaga | Term Loan | Flaga Term Loan Due September 2018
Debt Instrument [Line Items]
Basis spread on variable rate		1.125%
London Interbank Offered Rate (LIBOR) | Revolving Credit Facility | Minimum | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate		1.70%
London Interbank Offered Rate (LIBOR) | Revolving Credit Facility | Maximum | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate		2.60%

Commitments and Contingencies (

Commitments and Contingencies (Details)	Nov. 07, 2017	Mar. 31, 2018USD ($)subsidiarylb	Oct. 31, 2014lawsuit	Jul. 01, 2019USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)
Loss Contingencies
Capital contributions		$ 0
Class action lawsuits (more than) | lawsuit			35
Amount of propane in cylinders before reduction (in pounds) | lb		17
Amount of propane in cylinders after reduction (in pounds) | lb		15
UGI Gas | Environmental Matters
Loss Contingencies
Environmental expenditures cap during calendar year		$ 2,500,000
CPG MGP | Environmental Matters
Loss Contingencies
Environmental expenditures cap during calendar year		1,800,000
PNG MGP | Environmental Matters
Loss Contingencies
Environmental expenditures cap during calendar year		1,100,000
CPG, PNG and UGI Gas COAs
Loss Contingencies
Accrual for environmental loss contingencies		$ 51,900,000			$ 54,300,000		$ 55,700,000
UGI Utilities | PNG and CPG
Loss Contingencies
Number of subsidiaries acquired with similar histories | subsidiary		2
AmeriGas OLP | Saranac Lake, New York | New York State Department of Environment Conservation Remediation Plan
Loss Contingencies
Accrual for environmental loss contingencies						$ 7,500,000
Estimated remediation plan cost							$ 27,700,000
Capital Unit, Class B
Loss Contingencies
Weighted average price of common units, volume, period	20 days
Basis spread on dividend yield	1.30%
Conversion of stock, period subsequent to initial issuance, election one	5 years
Conversion of stock, conversion ratio	1
Conversion of stock, period subsequent to initial issuance, election two	6 years
Minimum | Capital Unit, Class B
Loss Contingencies
Conversion of stock, closing trading price, percentage	110.00%
Forecast
Loss Contingencies
Capital contributions				$ 225,000,000

Defined Benefit Pension and O51

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		6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 2.8	$ 3	$ 5.6	$ 6
Interest cost	6.5	6.1	13	12.3
Expected return on assets	(8.6)	(8.3)	(17.2)	(16.6)
Amortization of:
Prior service cost (benefit)	0.1		0.2	0.1
Actuarial loss	3.3	4.2	6.6	8.3
Net benefit cost	4.1	5	8.2	10.1
Change in associated regulatory liabilities	0	0	0	0
Net benefit cost after change in regulatory liabilities	4.1	5	8.2	10.1
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	0.2	0.3	0.4	0.5
Interest cost	0.2	0.2	0.4	0.4
Expected return on assets	(0.2)	(0.1)	(0.4)	(0.3)
Amortization of:
Prior service cost (benefit)		(0.2)	(0.1)	(0.3)
Actuarial loss	0	0	0	0.1
Net benefit cost	0.2	0.2	0.3	0.4
Change in associated regulatory liabilities	(0.1)	(0.1)	(0.2)	(0.2)
Net benefit cost after change in regulatory liabilities	$ 0.1	$ 0.1	$ 0.1	$ 0.2

Defined Benefit Pension and O52

Defined Benefit Pension and Other Postretirement Plans - Narrative (Details) - USD ($)	3 Months Ended		6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans
Contribution made to Pension and Post-retirement Plans			$ 6,700,000	$ 5,700,000
Expected contribution to pension plan during remainder of fiscal year	$ 6,700,000		6,700,000
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	200,000	$ 200,000	300,000	400,000
Contribution made to Pension and Post-retirement Plans			0	0
Unfunded Plan | Nonqualified Plan
Defined Benefit Plans and Other Postretirement Benefit Plans
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 0	$ 0	$ 0	$ 0

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	Mar. 31, 2018	Sep. 30, 2017	Mar. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	$ 80.5	$ 116.3	$ 92.6
Derivative financial instruments, liabilities	(85.4)	(82.5)	(42.7)
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	37.9	35.6	35.2
Fair Value, Measurements, Recurring | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	66.6	104.1	74
Derivative financial instruments, liabilities	(37.8)	(39.1)	(39)
Fair Value, Measurements, Recurring | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	13.9	12.2	15.6
Derivative financial instruments, liabilities	(43.5)	(38.2)	(1.5)
Fair Value, Measurements, Recurring | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, liabilities	(1.9)	(2.3)	(2.2)
Fair Value, Measurements, Recurring | Cross-currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets			3
Derivative financial instruments, liabilities	(2.2)	(2.9)
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	37.9	35.6	35.2
Fair Value, Measurements, Recurring | Level 1 | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	39.6	27.2	56
Derivative financial instruments, liabilities	(24.3)	(27.7)	(28)
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	0	0
Fair Value, Measurements, Recurring | Level 1 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, liabilities	0	0	0
Fair Value, Measurements, Recurring | Level 1 | Cross-currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets			0
Derivative financial instruments, liabilities	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	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	27	76.9	18
Derivative financial instruments, liabilities	(13.5)	(11.4)	(11)
Fair Value, Measurements, Recurring | Level 2 | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	13.9	12.2	15.6
Derivative financial instruments, liabilities	(43.5)	(38.2)	(1.5)
Fair Value, Measurements, Recurring | Level 2 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, liabilities	(1.9)	(2.3)	(2.2)
Fair Value, Measurements, Recurring | Level 2 | Cross-currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets			3
Derivative financial instruments, liabilities	(2.2)	(2.9)
Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	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	0	0
Fair Value, Measurements, Recurring | Level 3 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, liabilities	0	0	0
Fair Value, Measurements, Recurring | Level 3 | Cross-currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets			$ 0
Derivative financial instruments, liabilities	$ 0	$ 0

Fair Value Measurements - Long-

Fair Value Measurements - Long-term Debt (Details) - USD ($) $ in Millions	Mar. 31, 2018	Sep. 30, 2017	Mar. 31, 2017
Carrying amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 4,316.4	$ 4,211.9	$ 4,238.9
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 4,287.3	$ 4,346.8	$ 4,255

Derivative Instruments and He55

Derivative Instruments and Hedging Activities - Narrative (Details) - USD ($)	Mar. 31, 2018	Sep. 30, 2017	Mar. 31, 2017
Derivative [Line Items]
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	$ (3,500,000)
Amount of net gains associated with currency rate risk to be reclassified into earnings during the next 12 months	(3,700,000)
Restricted cash in brokerage accounts	10,600,000	$ 10,300,000	$ 300,000
Foreign currency contracts
Derivative [Line Items]
Notional amount	496,200,000	$ 424,800,000	321,800,000
Net Investment Hedging | Foreign currency contracts
Derivative [Line Items]
Notional amount	$ 0		$ 0

Derivative Instruments and He56

Derivative Instruments and Hedging Activities - Schedule of Notional Amounts (Details) € in Millions, kWh in Millions, gal in Millions, MMBTU in Millions, $ in Millions	Mar. 31, 2018EUR (€)galkWhMMBTU	Mar. 31, 2018USD ($)galkWhMMBTU	Sep. 30, 2017EUR (€)galkWhMMBTU	Sep. 30, 2017USD ($)galkWhMMBTU	Mar. 31, 2017EUR (€)galkWhMMBTU	Mar. 31, 2017USD ($)galkWhMMBTU
Commodity contracts | Electricity | Long
Derivative [Line Items]
Notional amount (in units) | kWh	4,184.1	4,184.1	4,440.3	4,440.3	668.7	668.7
Commodity contracts | Electricity | Short
Derivative [Line Items]
Notional amount (in units) | kWh	490.9	490.9	447	447	526.1	526.1
Commodity contracts | Propane
Derivative [Line Items]
Notional amount (in units) | gal	229.2	229.2	325.5	325.5	241.6	241.6
Natural gas futures, forward and pipeline contracts (in dekatherms) | Natural Gas
Derivative [Line Items]
Notional amount (in units)	128.9	128.9	75.9	75.9	56.5	56.5
Natural gas basis swap contracts (in dekatherms) | Natural Gas
Derivative [Line Items]
Notional amount (in units)	74.1	74.1	104.2	104.2	107.2	107.2
NYMEX natural gas storage (in dekatherms) | Natural Gas
Derivative [Line Items]
Notional amount (in units)	0.9	0.9	1.9	1.9	1.4	1.4
NYMEX propane storage (in gallons) | Propane
Derivative [Line Items]
Notional amount (in units) | gal	0	0	0.3	0.3	0	0
Interest rate swaps
Derivative [Line Items]
Notional amount | €	€ 645.8		€ 645.8		€ 645.8
Forward foreign currency exchange contracts
Derivative [Line Items]
Notional amount | $		$ 496.2		$ 424.8		$ 321.8
Cross-currency contracts
Derivative [Line Items]
Notional amount | $		$ 49.9		$ 59.1		$ 59.1
Regulated Utility Operations | Commodity contracts | Natural Gas
Derivative [Line Items]
Notional amount (in units)	12.7	12.7	14.8	14.8	9	9
Regulated Utility Operations | FTRs (in kilowatts) | Electricity
Derivative [Line Items]
Notional amount (in units) | kWh	25.5	25.5	101.2	101.2	14.6	14.6

Derivative Instruments and He57

Derivative Instruments and Hedging Activities - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2018	Sep. 30, 2017	Mar. 31, 2017
Derivative assets:
Total derivative assets — gross	$ 80.5	$ 116.3	$ 92.6
Gross amounts offset in the balance sheet	(31.5)	(35.7)	(31.8)
Cash collateral received	(0.4)	(8.3)	(0.2)
Total derivative assets — net	48.6	72.3	60.6
Derivative liabilities:
Total derivative liabilities — gross	(85.4)	(82.5)	(42.7)
Gross amounts offset in the balance sheet	31.5	35.7	31.8
Total derivative liabilities — net	(53.9)	(46.8)	(10.9)
Derivatives designated as hedging instruments
Derivative assets:
Total derivative assets — gross	0.3	3.2	17.2
Derivative liabilities:
Total derivative liabilities — gross	(8.1)	(10.7)	(2.2)
Derivatives designated as hedging instruments | Foreign currency contracts
Derivative assets:
Total derivative assets — gross	0.3	3.2	14.2
Derivative liabilities:
Total derivative liabilities — gross	(4)	(5.5)	0
Derivatives designated as hedging instruments | Cross-currency contracts
Derivative assets:
Total derivative assets — gross	0	0	3
Derivative liabilities:
Total derivative liabilities — gross	(2.2)	(2.9)	0
Derivatives designated as hedging instruments | Interest rate contracts
Derivative liabilities:
Total derivative liabilities — gross	(1.9)	(2.3)	(2.2)
Derivatives subject to PGC and DS mechanisms | Commodity contracts
Derivative assets:
Total derivative assets — gross	0.9	1.7	2.1
Derivative liabilities:
Total derivative liabilities — gross	(0.6)	(1.5)	(0.2)
Derivatives not designated as hedging instruments
Derivative assets:
Total derivative assets — gross	79.3	111.4	73.3
Derivative liabilities:
Total derivative liabilities — gross	(76.7)	(70.3)	(40.3)
Derivatives not designated as hedging instruments | Foreign currency contracts
Derivative assets:
Total derivative assets — gross	13.6	9	1.4
Derivative liabilities:
Total derivative liabilities — gross	(39.5)	(32.7)	(1.5)
Derivatives not designated as hedging instruments | Commodity contracts
Derivative assets:
Total derivative assets — gross	65.7	102.4	71.9
Derivative liabilities:
Total derivative liabilities — gross	$ (37.2)	$ (37.6)	$ (38.8)

Derivative Instruments and He58

Derivative Instruments and Hedging Activities - Effects of Derivative Instruments on the Condensed Consolidated Statements of Income and Changes in AOCI (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Derivatives Not Designated as Hedging Instruments
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	$ (52.9)	$ 21.7	$ (34.5)	$ 131.5
Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	(2.3)	(0.8)	(2.9)	17.5
Gain (Loss) Reclassified from AOCI into Income	(4.3)	7.9	(3.8)	14.5
Foreign currency contracts | Derivatives Not Designated as Hedging Instruments | (Losses) gains on foreign currency contracts, net
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(11)	(1.2)	(15.8)	0.1
Foreign currency contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	(3.1)	(1.7)	(4.5)	15.5
Foreign currency contracts | Cash Flow Hedges | Cost of sales
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	(3.9)	8.9	(3.1)	16.8
Cross-currency contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	0.3	0.3	0.4	0.2
Cross-currency contracts | Cash Flow Hedges | Interest expense/other operating income, net
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	0.3	0	0.5	(0.3)
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Cost of sales
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(41.8)	22	(17.4)	130.5
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Revenues
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(0.2)	0.8	(1.5)	0.9
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Operating and administrative expenses
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	0.1	0.1	0.2	0
Interest rate contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	0.5	0.6	1.2	1.8
Interest rate contracts | Cash Flow Hedges | Interest expense
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	$ (0.7)	$ (1)	$ (1.2)	$ (2)

Accumulated Other Comprehensi59

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period			$ 3,740.9
Other comprehensive (loss) income before reclassification adjustments (after-tax)	$ 34.3	$ 17.3	56.2	$ (41.3)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	4.7	(7.2)	4.8	(12.2)
Six Months Ended March 31, 2018	(1.6)	2.2	(1.7)	3.7
Reclassification adjustments (after-tax)	3.1	(5)	3.1	(8.5)
Other comprehensive income attributable to UGI	37.4	12.3	59.3	(49.8)
Balance, end of period	4,421	3,937.4	4,421	3,937.4
Postretirement Benefit Plans
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(18.8)	(28.1)	(19.2)	(29.1)
Other comprehensive (loss) income before reclassification adjustments (after-tax)	0	0	0	0
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	0.4	0.7	1	2.3
Six Months Ended March 31, 2018	(0.1)	(0.3)	(0.3)	(0.9)
Reclassification adjustments (after-tax)	0.3	0.4	0.7	1.4
Other comprehensive income attributable to UGI	0.3	0.4	0.7	1.4
Balance, end of period	(18.5)	(27.7)	(18.5)	(27.7)
Derivative Instruments
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(22.2)	(5.6)	(21.4)	(13.4)
Other comprehensive (loss) income before reclassification adjustments (after-tax)	(1.6)	(0.5)	(2)	11.8
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	4.3	(7.9)	3.8	(14.5)
Six Months Ended March 31, 2018	(1.5)	2.5	(1.4)	4.6
Reclassification adjustments (after-tax)	2.8	(5.4)	2.4	(9.9)
Other comprehensive income attributable to UGI	1.2	(5.9)	0.4	1.9
Balance, end of period	(21)	(11.5)	(21)	(11.5)
Foreign Currency
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(30.5)	(183.1)	(52.8)	(112.2)
Other comprehensive (loss) income before reclassification adjustments (after-tax)	35.9	17.8	58.2	(53.1)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	0	0	0	0
Six Months Ended March 31, 2018	0	0	0	0
Reclassification adjustments (after-tax)	0	0	0	0
Other comprehensive income attributable to UGI	35.9	17.8	58.2	(53.1)
Balance, end of period	5.4	(165.3)	5.4	(165.3)
Total
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(71.5)	(216.8)	(93.4)	(154.7)
Amounts reclassified from AOCI:
Balance, end of period	$ (34.1)	$ (204.5)	$ (34.1)	$ (204.5)

Segment Information - Narrative

Segment Information - Narrative (Details)	6 Months Ended
	Mar. 31, 2018segment
Segment Reporting [Abstract]
Number of reportable segments	4

Segment Information - Schedule

Segment Information - Schedule of Segment Reporting Information (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017	Sep. 30, 2017
Segment Reporting Information [Line Items]
Revenues	$ 2,812	$ 2,173.8	$ 4,937.2	$ 3,853.3
Cost of sales	1,560.2	1,071.2	2,697.6	1,718.6
Segment profit:
Operating income (loss)	589.5	513.2	981.3	979.4
Income (loss) from equity investees	0.7	2.3	1.7	2.1
(Losses) gains on foreign currency contracts, net	(11)	(1.2)	(15.8)	0.1
Loss on extinguishments of debt	0	(22.1)	0	(55.3)
Interest expense	(58.1)	(55.8)	(116.3)	(111.2)
Income (loss) before income taxes	521.1	436.4	850.9	815.1
Noncontrolling interests’ net income (loss)	131.7	91.9	200	152.1
Depreciation and amortization	112.2	99.3	222.5	197.4
Capital expenditures (including the effects of accruals)	110.1	126.2	238.6	299.8
Total assets	12,445.3	11,385.5	12,445.3	11,385.5	$ 11,582.2
Short-term borrowings	302.8	50.1	302.8	50.1	366.9
Goodwill	3,218.1	2,948.4	3,218.1	2,948.4	$ 3,107.2
Cost-method Investments, Other than Temporary Impairment		7	7
Eliminations
Segment Reporting Information [Line Items]
Revenues	(188.9)	(95.8)	(286)	(164.3)
Cost of sales	(187.9)	(94.9)	(283.9)	(162.6)
Segment profit:
Operating income (loss)	0.3	0	0.5	0.1
Income (loss) from equity investees	0	0	0	0
(Losses) gains on foreign currency contracts, net	0	0	0	0
Loss on extinguishments of debt		0		0
Interest expense	0	0	0	0
Income (loss) before income taxes	0.3	0	0.5	0.1
Noncontrolling interests’ net income (loss)	0	0	0	0
Depreciation and amortization	(0.1)	(0.1)	(0.1)	(0.1)
Capital expenditures (including the effects of accruals)	0	0	0	0
Total assets	(59.4)	(58.6)	(59.4)	(58.6)
Short-term borrowings	0	0	0	0
Goodwill	0	0	0	0
Eliminations | AmeriGas Propane
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
Eliminations | UGI International
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
Eliminations | Midstream & Marketing
Segment Reporting Information [Line Items]
Revenues	129	76.2	207.2	136.4
Eliminations | UGI Utilities
Segment Reporting Information [Line Items]
Revenues	58.7	18.8	76.4	26.3
Corporate, Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Revenues	1.2	0.8	2.4	1.6
Operating Segments | AmeriGas Propane
Segment Reporting Information [Line Items]
Revenues	1,040.3	863.6	1,827.6	1,540.8
Cost of sales	483.7	355.8	849.8	616.5
Segment profit:
Operating income (loss)	266.6	227.3	414.5	369.2
Income (loss) from equity investees	0	0	0	0
(Losses) gains on foreign currency contracts, net	0	0	0	0
Loss on extinguishments of debt	0	(22.1)	0	(55.3)
Interest expense	(41)	(40)	(81.6)	(80)
Income (loss) before income taxes	225.6	165.2	332.9	233.9
Partnership Adjusted EBITDA	309.5	271.2	503.6	456.3
Noncontrolling interests’ net income (loss)	155.7	112.7	223.7	153.9
Depreciation and amortization	45.2	45	92.6	89.6
Capital expenditures (including the effects of accruals)	23.6	27.2	47.2	53.6
Total assets	4,149.8	4,238.1	4,149.8	4,238.1
Short-term borrowings	154.5	0	154.5	0
Goodwill	2,001.3	1,981.2	2,001.3	1,981.2
Operating Segments | UGI International
Segment Reporting Information [Line Items]
Revenues	909.6	620.7	1,693.8	1,159.8
Cost of sales	541.1	313.1	1,025.9	571.1
Segment profit:
Operating income (loss)	131.8	121	224.9	209.9
Income (loss) from equity investees	(0.1)	(0.1)	(0.3)	(0.3)
(Losses) gains on foreign currency contracts, net	(9)	0.1	(13.7)	0.2
Loss on extinguishments of debt		0		0
Interest expense	(5.2)	(4.8)	(10.8)	(9.6)
Income (loss) before income taxes	117.5	116.2	200.1	200.2
Noncontrolling interests’ net income (loss)	(1.2)	0.1	(1.5)	0.3
Depreciation and amortization	34.9	27.6	67.1	55.5
Capital expenditures (including the effects of accruals)	26.1	21.5	47.8	43
Total assets	3,562.3	2,804.7	3,562.3	2,804.7
Short-term borrowings	3.3	1.6	3.3	1.6
Goodwill	1,023.2	773.6	1,023.2	773.6
Operating Segments | Midstream & Marketing
Segment Reporting Information [Line Items]
Revenues	436.2	347.5	686	557.1
Cost of sales	418.6	309.8	657.6	501.6
Segment profit:
Operating income (loss)	107.5	82.1	159.8	131.8
Income (loss) from equity investees	0.8	2.4	2	2.4
(Losses) gains on foreign currency contracts, net	0	0	0	0
Loss on extinguishments of debt		0		0
Interest expense	(0.7)	(0.7)	(1.6)	(1.3)
Income (loss) before income taxes	107.6	83.8	160.2	132.9
Noncontrolling interests’ net income (loss)	0	0	0	0
Depreciation and amortization	10.8	8.8	20.9	16.8
Capital expenditures (including the effects of accruals)	4.3	20.8	15.6	82.3
Total assets	1,347.7	1,200.7	1,347.7	1,200.7
Short-term borrowings	10	0	10	0
Goodwill	11.5	11.5	11.5	11.5
Operating Segments | UGI Utilities
Segment Reporting Information [Line Items]
Revenues	424.6	341.2	730	595.1
Cost of sales	257.3	164.5	409.1	274
Segment profit:
Operating income (loss)	135.1	116.4	231.4	198.6
Income (loss) from equity investees	0	0	0	0
(Losses) gains on foreign currency contracts, net	0	0	0	0
Loss on extinguishments of debt		0		0
Interest expense	(11.1)	(10.3)	(22)	(20.3)
Income (loss) before income taxes	124	106.1	209.4	178.3
Noncontrolling interests’ net income (loss)	0	0	0	0
Depreciation and amortization	21.1	17.7	41.5	35.1
Capital expenditures (including the effects of accruals)	55.1	56.5	126.8	120.6
Total assets	3,204	2,909.7	3,204	2,909.7
Short-term borrowings	135	48.5	135	48.5
Goodwill	182.1	182.1	182.1	182.1
Corporate & Other
Segment Reporting Information [Line Items]
Revenues	1.3	0.8	(0.2)	0.5
Cost of sales	47.4	22.9	39.1	(82)
Segment profit:
Operating income (loss)	(51.8)	(33.6)	(49.8)	69.8
Income (loss) from equity investees	0	0	0	0
(Losses) gains on foreign currency contracts, net	(2)	(1.3)	(2.1)	(0.1)
Loss on extinguishments of debt		0		0
Interest expense	(0.1)	0	(0.3)	0
Income (loss) before income taxes	(53.9)	(34.9)	(52.2)	69.7
Noncontrolling interests’ net income (loss)	(22.8)	(20.9)	(22.2)	(2.1)
Depreciation and amortization	0.3	0.3	0.5	0.5
Capital expenditures (including the effects of accruals)	1	0.2	1.2	0.3
Total assets	240.9	290.9	240.9	290.9
Short-term borrowings	0	0	0	0
Goodwill	0	0	0	0
Gains (losses) on unsettled commodity derivative instruments, net	$ (48.1)	$ (23.9)	$ (41.5)	$ 81.6

Segment Information - Reconcili

Segment Information - Reconciliation of Partnership Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Segment Reporting Information [Line Items]
Depreciation and amortization	$ (112.2)	$ (99.3)	$ (222.5)	$ (197.4)
Interest expense	(58.1)	(55.8)	(116.3)	(111.2)
Loss on extinguishments of debt	0	(22.1)	0	(55.3)
Income (loss) before income taxes	521.1	436.4	$ 850.9	$ 815.1
Amerigas Propane | AmeriGas OLP
Segment Reporting Information [Line Items]
General Partnership interest (percentage)			1.01%	1.01%
Operating Segments | Amerigas Propane
Segment Reporting Information [Line Items]
Partnership Adjusted EBITDA	309.5	271.2	$ 503.6	$ 456.3
Depreciation and amortization	(45.2)	(45)	(92.6)	(89.6)
Interest expense	(41)	(40)	(81.6)	(80)
Loss on extinguishments of debt	0	(22.1)	0	(55.3)
Noncontrolling interest	2.3	1.1	3.5	2.5
Income (loss) before income taxes	$ 225.6	$ 165.2	$ 332.9	$ 233.9