UGI (UGI) 10-Q 7 Feb 19 2019 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Dec. 31, 2018	Jan. 31, 2019
Document and Entity Information [Abstract]
Entity Registrant Name	UGI CORP /PA/
Entity Central Index Key	884,614
Document Type	10-Q
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Document Fiscal Year Focus	2,019
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--09-30
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		173,844,100

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 477.6	$ 452.6	$ 446.4
Restricted cash	17.4	9.6	19.8
Accounts receivable (less allowances for doubtful accounts of $38.5, $35.1 and $35.1, respectively)	1,144.3	751.9	1,101.8
Accrued utility revenues	64.7	14	95.9
Inventories	293.7	318.2	307.3
Utility regulatory assets	3.3	7.5	0.6
Derivative instruments	60.2	142.5	73.4
Prepaid expenses and other current assets	181	191.8	135.4
Total current assets	2,242.2	1,888.1	2,180.6
Property, plant and equipment, at cost (less accumulated depreciation of $3,228.3, $3,153.9 and $3,393.1, respectively)	5,855.1	5,808.2	5,690.5
Goodwill	3,154.8	3,160.4	3,185.5
Intangible assets, net	505.2	513.6	641.9
Utility regulatory assets	295.5	293.5	362.2
Derivative instruments	29.9	43.5	13.3
Other assets	285.6	273.6	269.9
Total assets	12,368.3	11,980.9	12,343.9
Current liabilities:
Current maturities of long-term debt	19.5	18.8	224.1
Short-term borrowings	676.3	424.9	586.1
Accounts payable	753.3	561.8	680.8
Derivative instruments	56.8	11.7	32.7
Other current liabilities	677.2	714.9	692.3
Total current liabilities	2,183.1	1,732.1	2,216
Long-term debt	4,150.7	4,146.5	4,056.4
Deferred income taxes	973.4	991.9	890.7
Derivative instruments	25	12.8	22.2
Other noncurrent liabilities	989.5	997.6	1,076.5
Total liabilities	8,321.7	7,880.9	8,261.8
Commitments and contingencies (Note 11)
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 174,262,763, 174,142,997 and 173,997,441 shares, respectively)	1,206.5	1,200.8	1,189.3
Retained earnings	2,620.8	2,610.7	2,429.3
Accumulated other comprehensive loss	(133.1)	(110.4)	(71.5)
Treasury stock, at cost	(24.8)	(19.7)	(45.4)
Total UGI Corporation stockholders’ equity	3,669.4	3,681.4	3,501.7
Noncontrolling interests, principally in AmeriGas Partners	377.2	418.6	580.4
Total equity	4,046.6	4,100	4,082.1
Total liabilities and equity	$ 12,368.3	$ 11,980.9	$ 12,343.9

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Accounts receivable, allowances for doubtful accounts	$ 38.5	$ 35.1	$ 35.1
Property, plant and equipment, accumulated depreciation and amortization	$ 3,228.3	$ 3,153.9	$ 3,393.1
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)	174,262,763	174,142,997	173,997,441

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Statement [Abstract]
Revenues	$ 2,200.2	$ 2,125.2
Costs and expenses:
Cost of sales (excluding depreciation and amortization shown below)	1,425	1,137.4
Operating and administrative expenses	503.2	486.9
Depreciation and amortization	111.2	110.3
Other operating income, net	(6.9)	(4.4)
Total costs and expenses	2,032.5	1,730.2
Operating income	167.7	395
Income from equity investees	1.5	1
Loss on extinguishments of debt	(6.1)	0
Other non-operating income (expense), net	9	(8)
Interest expense	(60.2)	(58.2)
(Loss) income before income taxes	111.9	329.8
Income tax (expense) benefit	(23.4)	104.4
Net income including noncontrolling interests	88.5	434.2
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners	(24.3)	(68.3)
Net income attributable to UGI Corporation	$ 64.2	$ 365.9
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in USD per share)	$ 0.37	$ 2.11
Diluted (in USD per share)	$ 0.36	$ 2.07
Weighted-average common shares outstanding (thousands):
Basic (in shares)	174,413	173,670
Diluted (in shares)	177,566	176,948
Dividends declared per common share (in USD per share)	$ 0.26	$ 0.25

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income including noncontrolling interests	$ 88.5	$ 434.2
Other comprehensive income (loss):
Net losses on derivative instruments (net of tax of $0.4 and $0.2, respectively)	(1.5)	(0.4)
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(0.3) and $0.1, respectively)	0.7	(0.4)
Foreign currency adjustments (net of tax of $2.8 and $0.0, respectively)	(15.6)	22.3
Benefit plans (net of tax of $(0.1), and $(0.2), respectively)	0.3	0.4
Other comprehensive (loss) income	(16.1)	21.9
Comprehensive income including noncontrolling interests	72.4	456.1
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	(24.3)	(68.3)
Comprehensive income attributable to UGI Corporation	$ 48.1	$ 387.8

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Tax on (loss) gain on derivative instruments	$ 0.4	$ 0.2
Tax on reclassification on derivative instruments	(0.3)	0.1
Other comprehensive income (loss), foreign currency translation adjustment, tax	2.8	0
Tax on benefit plans	$ (0.1)	$ (0.2)

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income including noncontrolling interests	$ 88.5	$ 434.2
Adjustments to reconcile net income including noncontrolling interest to net cash provided by operating activities:
Depreciation and amortization	111.2	110.3
Deferred income tax benefit, net	(20.7)	(173.9)
Provision for uncollectible accounts	10.3	9.3
Changes in unrealized gains and losses on derivative instruments	165.9	(6.6)
Loss on extinguishments of debt	6.1	0
Other, net	10.9	7.6
Net change in:
Accounts receivable and accrued utility revenues	(457.6)	(530.5)
Inventories	23	(23.5)
Utility deferred fuel and power costs, net of changes in unsettled derivatives	(12.5)	11.6
Accounts payable	217.4	235
Derivative instruments collateral deposits (paid) received	(22.2)	3.7
Other current assets	(11.4)	(34)
Other current liabilities	(12.3)	(11.8)
Net cash provided by operating activities	96.6	31.4
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(183.3)	(147.5)
Acquisitions of businesses and assets, net of cash acquired	(15)	(175.8)
Other	4.3	5.3
Net cash used by investing activities	(194)	(318)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(45.3)	(43.3)
Distributions on AmeriGas Partners publicly held Common Units	(65.7)	(65.7)
Issuances of long-term debt, net of issuance costs	728.9	124.3
Repayments of long-term debt	(721.1)	(41.9)
Increase in short-term borrowings	243.4	212.5
Receivables Facility net borrowings	8	6
Issuances of UGI Common Stock	6.9	1.4
Repurchases of UGI Common Stock	(16.9)	(9.5)
Other	(4.2)	(2.7)
Net cash provided by financing activities	134	181.1
EFFECT OF EXCHANGE RATE CHANGES ON CASH	(3.8)	3
Cash, cash equivalents and restricted cash increase (decrease)	32.8	(102.5)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Cash, cash equivalents and restricted cash at end of period	495	466.2
Cash, cash equivalents and restricted cash at beginning of period	$ 462.2	$ 568.7

Condensed Consolidated Statem_5

Condensed Consolidated Statements of Changes in Equity (unaudited) - USD ($) $ in Millions	Total	Total UGI 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 principle - ASC 606				$ 0
Balance, beginning of period at Sep. 30, 2017			$ 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			(1.3)
Equity-based compensation expense			2
Tax Cuts and Jobs Act of 2017, reclassification from AOCI to retained earnings, tax effect				0	0
Losses on treasury stock transactions in connection with employee and director plans				0
Net income	$ 434.2			365.9			68.3
Cash dividends on Common Stock ($0.26 and $0.25 per share, respectively)				(43.3)
Net losses on derivative instruments	(0.4)				(0.4)
Reclassification of net losses (gains) on derivative instruments	(0.4)				(0.4)
Benefit plans	0.4				0.4
Foreign currency adjustments	22.3				22.3
Common Stock issued in connection with employee and director plans, net of tax withheld						2.7
Repurchases of Common Stock						(9.5)
Reacquired Common Stock — employee and director plans						0
Dividends and distributions							(65.7)
Other							0.2
Balance, end of period at Dec. 31, 2017	$ 4,082.1	$ 3,501.7	1,189.3	2,429.3	(71.5)	(45.4)	580.4
Increase (Decrease) in Stockholders' Equity
Common stock, dividends, per share, cash paid	$ 0.025
Cumulative effect of change in accounting principle - ASC 606				(7.1)
Balance, beginning of period at Sep. 30, 2018	$ 4,100		1,200.8	2,610.7	(110.4)	(19.7)	418.6
Balance, beginning of period at Sep. 30, 2018	4,100		1,200.8	2,610.7	(110.4)	(19.7)	418.6
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			3.7
Equity-based compensation expense			2
Tax Cuts and Jobs Act of 2017, reclassification from AOCI to retained earnings, tax effect	(6.6)			6.6	(6.6)
Losses on treasury stock transactions in connection with employee and director plans				(8.3)
Net income	88.5			64.2			24.3
Cash dividends on Common Stock ($0.26 and $0.25 per share, respectively)				(45.3)
Net losses on derivative instruments	(1.5)				(1.5)
Reclassification of net losses (gains) on derivative instruments	0.7				0.7
Benefit plans	0.3				0.3
Foreign currency adjustments	(15.6)				(15.6)
Common Stock issued in connection with employee and director plans, net of tax withheld						12.2
Repurchases of Common Stock						(16.9)
Reacquired Common Stock — employee and director plans						(0.4)
Dividends and distributions							(65.7)
Other							0
Balance, end of period at Dec. 31, 2018	$ 4,046.6	$ 3,669.4	$ 1,206.5	$ 2,620.8	$ (133.1)	$ (24.8)	$ 377.2
Increase (Decrease) in Stockholders' Equity
Common stock, dividends, per share, cash paid	$ 0.026

Nature of Operations

Nature of Operations	3 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations	Note 1 — Nature of Operations 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 LPG and market energy products and services. We conduct a domestic propane marketing and distribution business through AmeriGas Partners. AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary, AmeriGas OLP. AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc., serves as the General Partner of AmeriGas Partners and AmeriGas OLP. At December 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 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 2018 Annual Report. Incentive distributions received by the General Partner during the three months ended December 31, 2018 and 2017 were $11.3 each. Our wholly owned subsidiary, Enterprises, through subsidiaries, conducts (1) an LPG distribution business throughout much of Europe and (2) an energy marketing business in France, Belgium, the Netherlands and the United Kingdom. These businesses are conducted principally through our subsidiaries, UGI France, Flaga, AvantiGas, DVEP and UniverGas. Energy Services conducts directly and through subsidiaries energy marketing, midstream transmission, LNG, storage, natural gas gathering, natural gas production, electricity generation and energy services businesses primarily in the Mid-Atlantic region of the U.S. UGID owns all or a portion of electricity generation facilities principally located in Pennsylvania. HVAC, a first-tier subsidiary of Enterprises, also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in portions of eastern and central Pennsylvania. Energy Services and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation by the FERC. UGI Utilities owns and operates Gas Utility, a natural gas distribution utility business in eastern and central Pennsylvania and in a portion of one Maryland county directly and, prior to the Utility Merger on October 1, 2018, through PNG and CPG. Gas Utility is subject to regulation by the PAPUC and the FERC and, with respect to a small service territory in one Maryland county, the MDPSC. UGI Utilities also owns and operates Electric Utility, an electric distribution utility located in northeastern Pennsylvania. Electric Utility is subject to regulation by the PAPUC and the FERC.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Dec. 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 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, 2018 , Condensed Consolidated Balance Sheet was derived from audited financial statements but does not include all disclosures required by GAAP. These financial statements should be read in conjunction with the financial statements and related notes included in the Company’s 2018 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. Revenue Recognition. Effective October 1, 2018, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers,” which, as amended, is included in ASC 606. This new accounting guidance supersedes previous revenue recognition requirements in ASC 605. ASC 606 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. We adopted this new accounting guidance using the modified retrospective transition method to those contracts which were not completed as of October 1, 2018. Periods prior to October 1, 2018, have not been restated and continue to be reported in accordance with ASC 605. The Company recorded a $7.1 reduction to opening retained earnings as of October 1, 2018, to reflect the cumulative effect of ASC 606 on certain contracts not complete as of the date of adoption. The adoption of ASC 606 did not, and is not expected to, have a material impact on the amount or timing of our revenue recognition and on our consolidated net income, cash flows or financial position. Certain revenues such as revenue from leases, financial instruments and other revenues are not within the scope of ASC 606 because they are not from contracts with customers. Such revenues are accounted for in accordance with other GAAP. Revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, are not included in revenues. Gross receipts taxes at Midstream & Marketing and Electric Utility are presented on a gross basis. The Company has elected to use the practical expedient to expense the costs to obtain contracts when incurred for contracts that have a term less than one year . The costs incurred to obtain contracts that have duration of longer than one year are not material. See Note 4 for the additional disclosures regarding the Company’s revenue from contracts with customers. Restricted Cash. Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. Upon adoption of revised accounting guidance in October 2018 (see Note 3 ), restricted cash is included within the Company’s Condensed Consolidated Statements of Cash Flows, with changes in the balance no longer reflected as a separate investing activity. The retrospective application of the new guidance on the previously reported cash flows from investing activities for the three months ended December 31, 2017, resulted in the elimination of the item “Decrease in restricted cash,” which had previously been reported as a use of cash of $9.5 . The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Condensed Consolidated Balance Sheets to the corresponding amounts reported on the Condensed Consolidated Statements of Cash Flows: Cash, Cash Equivalents and Restricted Cash December 31, 2018 December 31, 2017 September 30, 2018 September 30, 2017 Cash and cash equivalents $ 477.6 $ 446.4 $ 452.6 $ 558.4 Restricted cash 17.4 19.8 9.6 10.3 Cash, cash equivalents and restricted cash $ 495.0 $ 466.2 $ 462.2 $ 568.7 Earnings Per Common Share. Basic earnings per share attributable to UGI shareholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI 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 2018 2017 Denominator (thousands of shares): Weighted-average common shares outstanding — basic 174,413 173,670 Incremental shares issuable for stock options and awards (a) 3,153 3,278 Weighted-average common shares outstanding — diluted 177,566 176,948 (a) For the three months ended December 31, 2018 and 2017 , there were 30 and 146 shares, respectively, associated with outstanding stock option awards that were excluded from the computation of diluted earnings per share above because their effect was antidilutive. Derivative Instruments. Derivative instruments are reported on the Condensed Consolidated Balance Sheets at their fair values, unless the NPNS exception is elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or if it qualifies and is designated as a hedge for accounting purposes. Certain of our derivative instruments qualify and are designated as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in 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. We do not designate our commodity and certain foreign currency derivative instruments as hedges under GAAP. Changes in the fair values of these derivative instruments are reflected in net income. Gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities 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 the cumulative translation adjustment section of AOCI until such foreign net investment is sold or liquidated. 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 enter 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 “ Other non-operating income (expense), 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 14 . 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 6 for discussions regarding the December 22, 2017, enactment of the TCJA in the U.S. and the December 2017 French Finance Bills. Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions. Reclassifications. Certain amounts for the three months ended December 31, 2017, have been reclassified as a result of the adoption of revised accounting guidance pertaining to certain net periodic pension and other postretirement benefit costs and restricted cash (see Note 3 ). In addition, certain other prior-period amounts have been reclassified to conform to the current-period presentation. Other non-operating income (expense), net. Included in “ Other non-operating income (expense), net ,” on the Condensed Consolidated Statements of Income are net gains and losses on forward foreign currency contracts used to reduce volatility in net income associated with our foreign operations, and non-service income (expense) associated with our pension and other postretirement plans.

Accounting Changes

Accounting Changes	3 Months Ended
	Dec. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Changes	Note 3 — Accounting Changes New Accounting Standards Adopted Effective October 1, 2018 Revenue Recognition. Effective October 1, 2018, the Company adopted new accounting guidance regarding revenue recognition. See Notes 2 and 4 for a detailed description of the impact of the new guidance and related disclosures. Cloud Computing Implementation Costs. In August 2018, the FASB issued ASU No. 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.” The new guidance requires a customer in a cloud computing arrangement that is a service contract to capitalize certain implementation costs as if the arrangement was an internal-use software project. These deferred implementation costs are expensed over the fixed, noncancelable term of the service arrangement plus any reasonably certain renewal periods. The new guidance also requires the entity to present the expense related to the capitalized implementation costs in the same income statement line as the hosting service fees; to classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments for hosting service fees; and to present the capitalized implementation costs in the balance sheet in the same line item in which prepaid hosting service fees are presented. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We adopted this ASU effective October 1, 2018, and applied the guidance prospectively to all implementation costs associated with cloud computing arrangements that are service contracts incurred beginning October 1, 2018. The adoption of the new guidance did not have a material impact on our results of operations for the three months ended December 31, 2018 . Stranded Tax Effects in Accumulated Other Comprehensive Income. In February 2018, the FASB issued 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 remeasurement of deferred income taxes associated with items included in AOCI due to the enactment of the TCJA may be reclassified to retained earnings, at the election of the entity, in the period the ASU is adopted. We adopted this ASU effective October 1, 2018. In connection with the adoption of this guidance, we reclassified a benefit of $6.6 from AOCI to opening retained earnings as of October 1, 2018, to reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of AOCI. 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 cost 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, including UGI Utilities, 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 guidance became effective for the Company beginning October 1, 2018, with retrospective adoption for the presentation of pension and postretirement expense on the income statement and a prospective adoption for capitalization. The Company’s Condensed Consolidated Statement of Income for the three months ended December 31, 2017 , has been recast to reflect the retrospective adoption for the presentation of the non-service cost component of net periodic pension and other postretirement benefit cost, net of estimated amounts capitalized, within “ Other non-operating income (expense), net ,” on the Condensed Consolidated Statement of Income. Previously, the non-service cost components were reflected in “Operating and administrative expenses.” For the three months ended December 31, 2018 , the amount of income comprising the non-service cost components of our pension and postretirement benefit plans, net of amounts capitalized, presented in " Other non-operating income (expense), net ,” totaled $0.1 . For the three months ended December 31, 2017, the amount of expense comprising the non-service cost components of our pension and postretirement benefit plans, net of amounts capitalized, which has been reclassified from "Operating and administrative expenses" to " Other non-operating income (expense), net ,” totaled $3.2 . Statement of Cash Flows - Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” The guidance in this ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, as well as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents are included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statement of cash flows. The amendments in the ASU are required to be adopted on a retrospective basis. We adopted this ASU effective October 1, 2018. Adoption of this new guidance resulted in a change in presentation of restricted cash on the Condensed Consolidated Statement of Cash Flows; otherwise, this guidance did not have a significant impact on our Condensed Consolidated Statement of Cash Flows and disclosures (see Note 2 , “Restricted Cash”). Accounting Standards Not Yet Adopted Pension and Other Postretirement Benefit Costs Disclosures. In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. The amendments in this ASU are effective for interim and annual periods beginning October 1, 2020 (Fiscal 2021). The guidance shall be adopted retrospectively for all periods presented in the financial statements. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Fair Value Measurements Disclosures. In August 2018, the FASB issued ASU No. 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. The amendments in this ASU are effective for annual periods beginning October 1, 2020 (Fiscal 2021). The guidance regarding removing and modifying disclosures will be adopted on a retrospective basis and the guidance regarding new disclosures will be adopted on a prospective basis. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted. 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 the Company for interim and annual periods beginning October 1, 2019 (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 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. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, 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 the Company for interim and annual periods beginning October 1, 2019 (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 unless an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption. We will adopt ASU No. 2016-02, as updated, effective October 1, 2019, and expect to elect the transition option which would allow the Company to maintain historical presentation for periods before October 1, 2019. The Company has completed a preliminary assessment for evaluating the impact of the guidance and anticipates that its adoption will result in a significant amount of right-of-use assets and lease liabilities for leases in effect at the adoption date. The Company has begun implementation activities including accumulating contracts and lease data in formats compatible with a new lease management system that will assist with the initial adoption of the standard.

Revenue from Contracts with Cus

Revenue from Contracts with Customers (Notes)	3 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customers	Note 4 — Revenue from Contracts with Customers The Company recognizes revenue when control of promised goods or services is transferred to our customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The Company generally has the right to consideration from a customer in an amount that corresponds directly with the value to the customer for our performance completed to date. As such, we have elected to recognize revenue in the amount to which we have a right to invoice except in the case of certain UGI Utilities’ large delivery service customers and Midstream & Marketing’s peaking contracts for which we recognize revenue on a straight-line basis over the term of the contract, consistent with when the performance obligations are satisfied by the Company. We do not have a significant financing component in our contracts because we receive payment shortly before, at, or shortly after the transfer of control of the good or service. Because the period between the time the performance obligation is satisfied and payment is received is one year or less, the Company has elected to apply the significant financing component practical expedient and no amount of consideration has been allocated as a financing component. The Company’s revenues from contracts with customers are discussed below. Utility Revenues UGI Utilities supplies natural gas and electricity and provides distribution services of natural gas and electricity to residential, commercial, and industrial customers who are generally billed at standard regulated tariff rates approved by the PAPUC through the ratemaking process. Tariff rates include a component that provides for a reasonable opportunity to recover operating costs and expenses and to earn a return on net investment, and a component that provides for the recovery, subject to reasonableness reviews, of PGC and DS costs. Customers may choose to purchase their natural gas and electricity from Gas Utility or Electric Utility, or, alternatively, may contract separately with alternate suppliers. Accordingly, our contracts with customers comprise two promised goods or services: (1) delivery service of natural gas and electricity through the Company’s utility distribution systems and (2) the natural gas or electricity commodity itself for those customers who choose to purchase the natural gas or electricity directly from the Company. Revenue is not recorded for the sale of natural gas or electricity to customers who have contracted separately with alternate suppliers. For those customers who choose to purchase their natural gas or electricity from the Company, the performance obligation includes both the supply of the commodity and the delivery service. The terms of our core market customer contracts are generally considered day-to-day as customers can discontinue service at any time without penalty. Performance obligations are generally satisfied over time as the natural gas or electricity is delivered to customers, at which point the customers simultaneously receive and consume the benefits provided by the delivery service and, when applicable, the commodity. Amounts are billed to customers based upon the reading of a customer’s meter which occurs on a cycle basis throughout each reporting period. An unbilled amount is recorded at the end of each reporting period based upon estimated amounts of natural gas or electricity delivered to customers since the date of the last meter reading. These unbilled estimates consider various factors such as historical customer usage patterns, customer rates and weather. UGI Utilities has certain fixed-term contracts with large commercial and industrial customers to provide natural gas delivery services at contracted rates and at volumes generally based on the customer’s needs. The performance obligation to provide the contracted delivery service for these large commercial and industrial customers is satisfied over time and revenue is generally recognized on a straight-line basis. UGI Utilities makes off-system sales whereby natural gas delivered to our system in excess of amounts needed to fulfill our distribution system needs is sold to other customers, primarily other distributors of natural gas, based on an agreed-upon price and volume between the Company and the counterparty. Gas Utility also sells excess capacity whereby interstate pipeline capacity in excess of amounts needed to meet our customer obligations is sold to other distributors of natural gas based upon an agreed-upon rate. Off-system sales and capacity releases are generally entered into one month at a time and comprise the sale of a specific volume of gas or pipeline capacity at a specific delivery point or points over a specific time. As such, performance obligations associated with off-system sales and capacity release customers are satisfied, and associated revenue is recorded, when the agreed upon volume of natural gas is delivered or capacity is provided, and title is transferred, in accordance with the contract terms. Electric Utility provides transmission services to PJM by allowing PJM to access Electric Utility’s electricity transmission facilities. In exchange for providing access, PJM pays Electric Utility consideration determined by a formula-based rate approved by FERC. The formula-based rate, which is updated annually, allows recovery of costs incurred to provide transmission services and return on transmission-related net investment. We recognize revenue over time as we provide transmission service. Other Utility revenues represent revenues from other ancillary services provided to customers and are generally recorded as the service is provided to customers. Non-Utility Revenues LPG . AmeriGas Propane and UGI International record revenue principally from the sale of LPG to retail and wholesale customers. The primary performance obligation associated with the sale of LPG is the delivery of propane to (1) the customer’s point of delivery for retail customers and (2) the customer’s specified location where LPG is picked up by wholesale customers, at which point control of the propane is transferred to the customer, the performance obligation is satisfied, and the associated revenue is recognized. For contracts with retail customers that consume LPG from a metered tank, we recognize revenue as LPG is consumed, at which point we have right to invoice, and generally invoice monthly based on consumption. Contracts with customers comprise different types of contracts with varying length terms, fixed or variable prices, and fixed or variable quantities. Contracts with our residential customers, which comprise a substantial number of our customer contracts, are generally one year or less. Customer contracts for the sale of LPG include fixed-price, fixed-quantity contracts under which LPG is provided to a customer at a fixed price and a fixed volume, and contracts that provide for the sale of propane at market prices at date of delivery with no fixed volumes. AmeriGas Propane offers contracts that permit the customer to lock in a fixed price for their volumes for a fee and also provide the customer with the option to pre-buy a fixed amount of propane at a fixed price. Amounts received under pre-buy arrangements are recorded as a contract liability when received and recorded as revenue when LPG is delivered and control is transferred to the customer. Fees associated with fixed-price contracts are recorded as contract liabilities and recorded ratably over the contract period. AmeriGas Propane and UGI International also distribute LPG to customers in portable cylinders. Under certain contracts, filled cylinders are delivered, and control is transferred, to a reseller. In such instances, the reseller is our customer and we record revenue upon delivery to the reseller. Under other contracts, filled cylinders are delivered to a reseller, but the Company retains control of the cylinders. In such instances, we record revenue at the time the reseller transfers control of the cylinder to the end user. Certain retail LPG customers receive credits which we account for as variable consideration. We estimate these credits based upon past practices and historical customer experience and we reduce our revenues recognized for these credits. Energy Marketing. Midstream & Marketing and UGI International operate energy marketing businesses that sell energy commodities, principally natural gas and electricity, to residential, commercial, industrial and wholesale customers. In addition, UGI International provides system balancing and procurement services to other energy marketers in the Netherlands. Midstream & Marketing and UGI International market natural gas and electricity on full-requirements or agreed-upon volume bases under contracts with varying length terms and at fixed or floating prices that are based on market indices adjusted for differences in price between the market location and delivery locations. Performance obligations associated with these contracts primarily comprise the delivery of the natural gas and electricity over a contractual period of time. Performance obligations also include other energy-related ancillary services provided to customers such as capacity. For performance obligations that are satisfied at a point in time such as the delivery of natural gas, revenue is recorded when customers take control of the natural gas. Revenue is recorded for performance obligations that qualify as a series, when customers consume the natural gas or electricity delivered, which corresponds to the amount invoiced to the customer. For transactions where the price or volume is not fixed, the transaction price is not determined until delivery occurs. The billed amount, and the revenue recorded, is based upon consumption by the customer. In addition to providing natural gas and electricity to end use customers, our energy marketing business in the Netherlands has contracts with third-party natural gas and electricity marketers to provide BRP services in the electricity and natural gas markets in the Netherlands. These contracts are typically multi-year agreements and include full BRP services which include, among other things, estimating, procuring and scheduling all energy requirements to meet third-party marketers’ needs, or provide more limited system procurement and balancing services. The amount of revenue recognized from our BRP customers is based upon the amount of energy delivered with respect to these agreements, and the level of BRP services provided. We typically receive payments from our BRP customers one month in advance of our performing the related services. Amounts received in advance are deferred on the balance sheet as contract liabilities. Based upon an evaluation of the terms and conditions of the BRP contracts and our ability to control the goods or services provided to the third-party marketers, in addition to other factors, we are considered a principal in these contracts and are required to record the revenue associated with the sale of energy to the third-party energy marketers on a gross basis. We record the associated revenue ratably over time, typically monthly, as the performance obligations are satisfied. Midstream. Midstream & Marketing provides natural gas pipeline transportation, natural gas gathering and natural gas underground storage services, which generally contain a performance obligation for the Company to have availability to transport or store a product. Additionally, the Company provides stand-ready services to sell supplemental energy products and related services, primarily LNG and propane-air mixtures during periods of high demand that typically results from cold weather. The Company also sells LNG to end-user customers for use by trucks, drilling rigs and other motored vehicles and equipment, and facilities that are located off the natural gas grid. Contracts for natural gas transportation and gathering services are typically long-term contracts with terms of up to 30 years , while contracts for storage are typically for a one -year or multiple storage season periods. Contracts to provide natural gas during periods of high demand have terms of up to 15 years. Contracts to sell LNG for trucks, drilling rigs and other motor vehicles and facilities are typically short-term (less than one year). Depending on the type of services provided or goods sold, midstream revenues may consist of demand rates, commodity rates, and transportation rates and may include other fees for ancillary services. Pipeline transportation, natural gas gathering and storage services provided and services to stand ready to sell supplemental energy products and services each are considered to have a single performance obligation satisfied through the passage of time ratably based upon providing a stand-ready service on a monthly basis. Contracts to sell LNG to end-user customers contain performance obligations to deliver LNG over the term of the contract and revenue is recognized at a point in time when the control of the energy products is transferred to the customer. The price in the contract corresponds to our efforts to satisfy the performance obligation and reflects the consideration we expect to receive for the satisfied performance obligation, and, therefore, the revenue is recognized based on the volume delivered and the price within the contract. In cases where shipping & handling occurs prior to the LNG being delivered to the customer’s storage vessel, we have elected to treat this as a cost of fulfillment and not a separate performance obligation. Revenues are typically billed and payment received monthly. Advance fees received from customers for stand-ready services are deferred as contract liabilities and revenue is recognized ratably over time as the performance obligation is satisfied over a period less than one year. Electricity Generation. Midstream & Marketing also sells power generated from our electricity generation assets in the wholesale electricity markets administered by PJM regional transmission organization. Power contracts with PJM consist of the sale of power, capacity and ancillary services, all of which are considered a bundle of various services. Performance obligations are satisfied over time, generally on a daily basis, as electricity is delivered to and simultaneously consumed by the customer. As such, the Company has elected to recognize revenue in the amount to which we have a right to invoice which is based on market prices at the time of the delivery of the electricity to the customers. Other. Other revenues from contracts with customers are generated primarily from services and products provided by Midstream & Marketing’s HVAC business and AmeriGas Propane’s parts and services business. The performance obligations of these businesses include installation, repair and warranty agreements associated with HVAC equipment and installation services provided for combined heat and power and solar panel installations. For installation and repair goods and services, the performance obligations under these contracts are satisfied, and revenue is recognized, as control of the product is transferred or the services are rendered. For warranty services, revenue is recorded ratably over the warranty period. Other LPG revenues from contracts with customers are generated primarily from certain fees AmeriGas Partners and UGI International charge associated with the delivery of LPG, including hazmat safety compliance, inspection, metering, installation, fuel recovery and certain other services. Revenues from fees are typically recorded when the LPG is delivered to the customer or the associated service is completed. Contract Balances The timing of revenue recognition may differ from the timing of invoicing to customers or cash receipts. Contract assets represent our right to consideration after the performance obligations have been satisfied when such right is conditioned on something other than the passage of time. Contract assets were not material at December 31, 2018. Substantially all of our receivables are unconditional rights to consideration and are included in “Accounts receivable” and, in the case of UGI Utilities, “Accrued utility revenues” on the Condensed Consolidated Balance Sheets. Amounts billed are generally due within the following month. Contract liabilities arise when payment from a customer is received before the performance obligations have been satisfied and represent the Company’s obligations to transfer goods or services to a customer for which we have received consideration. The balance of contract liabilities was $ 94.0 and $115.6 at December 31, 2018 and October 1, 2018, respectively, and are included in “Other current liabilities” on the Condensed Consolidated Balance Sheets. Revenue recognized for the three months ended December 31, 2018, from the amount included in contract liabilities at October 1, 2018 was $ 58.1 . Revenue Disaggregation The following table presents our disaggregated revenues by reportable segment for the three months ended December 31, 2018: Total Eliminations AmeriGas Propane UGI International Midstream & Marketing (a) UGI Utilities (a) Corporate & Other Revenues from contracts with customers: Utility: Core Market: Residential $ 175.7 $ — $ — $ — $ — $ 175.7 $ — Commercial & Industrial 67.6 — — — — 67.6 — Large delivery service 39.5 — — — — 39.5 — Off-system sales and capacity releases 15.2 (22.9 ) — — — 38.1 — Other (b) 0.5 (0.7 ) — — — 1.2 — Total Utility 298.5 (23.6 ) — — — 322.1 — Non-Utility: LPG: Retail 1,229.7 — 721.9 507.8 — — — Wholesale 60.0 — 21.0 39.0 — — — Energy Marketing 468.9 (47.5 ) — 143.1 373.3 — — Midstream: Pipeline 19.4 — — — 19.4 — — Peaking 2.0 (38.7 ) — — 40.7 — — Other 1.0 — — — 1.0 — — Electricity Generation 11.7 — — — 11.7 — — Other 84.0 (0.7 ) 60.6 12.4 11.7 — — Total Non-Utility 1,876.7 (86.9 ) 803.5 702.3 457.8 — — Total revenues from contracts with customers 2,175.2 (110.5 ) 803.5 702.3 457.8 322.1 — Other revenues (c) 25.0 (1.1 ) 16.7 8.4 1.6 0.6 (1.2 ) Total revenues $ 2,200.2 $ (111.6 ) $ 820.2 $ 710.7 $ 459.4 $ 322.7 $ (1.2 ) (a) Includes intersegment revenues principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (b) UGI Utilities includes unallocated negative surcharge revenue of $(4.1) as a result of a PAPUC Order issued May 17, 2018, related to TCJA (see Note 8). (c) Primarily represents revenues from tank rentals at AmeriGas Propane and UGI International, revenues from certain gathering assets at Midstream & Marketing, and gains and losses on commodity derivative instruments not associated with current-period transactions reflected in Corporate & Other, all of which are not within the scope of ASC 606 and accounted for in accordance with other GAAP. Remaining Performance Obligations The Company has elected to use practical expedients as allowed in ASC 606 to exclude disclosures related to the aggregate amount of the transaction price allocated to certain performance obligations that are unsatisfied as of the end of the reporting period because these contracts have an initial expected term of one year or less, or we have a right to bill the customer in an amount that corresponds directly with the value of services provided to the customer to date. Certain contracts with customers at Midstream & Marketing and UGI Utilities contain minimum future performance obligations through 2047 and 2053, respectively. At December 31, 2018, Midstream & Marketing and UGI Utilities expect to record approximately $1.5 billion and $0.2 billion of revenues, respectively, related to the minimum future performance obligations over the remaining terms of the related contracts.

Inventories

Inventories	3 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
Inventories	Note 5 — Inventories Inventories comprise the following: December 31, September 30, December 31, Non-utility LPG and natural gas $ 206.7 $ 231.7 $ 216.4 Gas Utility natural gas 34.9 37.3 34.6 Materials, supplies and other 52.1 49.2 56.3 Total inventories $ 293.7 $ 318.2 $ 307.3 At December 31, 2018 , UGI Utilities was a party to five principal SCAAs with terms of up to three years. Pursuant to the SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above. As of December 31, 2018 , UGI Utilities had SCAAs with Energy Services, the effects of which are eliminated in consolidation, and with a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at December 31, 2018 , September 30, 2018 and December 31, 2017 , comprising 1.9 bcf, 2.3 bcf and 1.8 bcf of natural gas, was $4.6 , $5.4 , and $5.1 , respectively.

Income Taxes

Income Taxes	3 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Note 6 — Income Taxes TCJA On December 22, 2017, the TCJA was enacted into law. Among the significant changes resulting from the law, the TCJA reduced the U.S. federal income tax rate from 35% to 21% , effective January 1, 2018, created a territorial tax system with a one-time mandatory “toll tax” on previously un-repatriated foreign earnings, and allowed for immediate capital expensing of certain qualified property. It also applied restrictions on the deductibility of interest expense, eliminated bonus depreciation for regulated utilities and certain FERC-regulated property beginning in Fiscal 2019, and applied a broader application of compensation limitations. In accordance with GAAP as determined by ASC 740 we are required to record the effects of tax law changes in the period enacted. As further discussed below, our results for the three months ended December 31, 2017, contained provisional estimates of the impact of the TCJA. These amounts were considered provisional because they used estimates for which tax returns had not yet been filed and because estimated amounts could have been impacted by future regulatory and accounting guidance if and when issued. We adjusted provisional amounts as further information became available and as we refined our calculations. As permitted by SEC Staff Accounting Bulletin No. 118, these adjustments occurred during the reasonable “measurement period” defined as twelve months from the date of enactment. During the three months ended December 31, 2018, adjustments to provisional amounts recorded in prior periods were not material. As a result of the enactment of the TCJA on December 22, 2017, during the three months ended December 31, 2017, we reduced our net deferred income tax liabilities due to the remeasuring of our existing federal deferred income tax assets and liabilities. Because current law requires that excess deferred income taxes associated with UGI Utilities’ regulated utility plant assets are to be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred taxes, UGI Utilities recorded a regulatory liability related to such excess deferred income taxes (see Note 8). For the three months ended December 31, 2017, discrete deferred income tax adjustments reduced income tax expense by $166.0 and consisted primarily of the following items: (1) a $180.3 reduction in net deferred tax liabilities in the U.S from the reduction of the U.S. tax rate; (2) the establishment of $12.6 of valuation allowances related to deferred tax assets impacted by U.S. tax law changes; and (3) a $1.7 “toll tax” on un-repatriated foreign earnings. For the three months ended December 31, 2018 and 2017, we included the estimated impacts of the TCJA in determining our estimated annual effective income tax rates. We are subject to a 21.0% U.S. federal tax rate in Fiscal 2019. We were subject to a blended U.S. federal tax rate of 24.5% for Fiscal 2018 because our fiscal year contained the effective date of the rate change from 35% to 21% on January 1, 2018. As a result, the U.S. federal income tax rates included in our estimated annual effective tax rates used for the three months ended December 31, 2018 and 2017 were based on rates of 21.0% and 24.5% , respectively. Our estimated annual effective tax rate was not impacted by any regulatory action taken by the PAPUC. December 2017 French Finance Bills In December 2017, the December 2017 French Finance Bills were approved. One impact of the December 2017 French Finance Bills was an increase in the Fiscal 2018 corporate income tax rate in France from 34.4% to 39.4% . 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 . The estimated annual effective income tax rate used in determining income taxes for the three months ended December 31, 2017, reflected the impact of the single year Fiscal 2018 income tax rate 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 months ended December 31, 2017, by $3.9 .

Goodwill and Intangible Assets

Goodwill and Intangible Assets	3 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	Note 7 — Goodwill and Intangible Assets Goodwill and intangible assets comprise the following: December 31, September 30, December 31, Goodwill (not subject to amortization) $ 3,154.8 $ 3,160.4 $ 3,185.5 Intangible assets: Customer relationships, noncompete agreements and other $ 853.0 $ 848.6 $ 862.0 Trademarks and tradenames 7.9 7.9 — Accumulated amortization (405.4 ) (393.2 ) (355.0 ) Intangible assets, net (definite-lived) 455.5 463.3 507.0 Trademarks and tradenames (indefinite-lived) 49.7 50.3 134.9 Total intangible assets, net $ 505.2 $ 513.6 $ 641.9 The changes in goodwill and intangible assets are primarily due to acquisitions and the effects of foreign currency translation. Amortization expense of intangible assets was $14.6 and $14.8 for the three months ended December 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 2019 and for the next four fiscal years is as follows: remainder of Fiscal 2019 — $43.4 ; Fiscal 2020 — $56.7 ; Fiscal 2021 — $53.4 ; Fiscal 2022 — $50.4 ; Fiscal 2023 — $48.9 .

Utility Regulatory Assets and L

Utility Regulatory Assets and Liabilities and Regulatory Matters	3 Months Ended
	Dec. 31, 2018
Regulated Operations [Abstract]
Utility Regulatory Assets and Liabilities and Regulatory Matters	Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 in the Company’s 2018 Annual Report. Other than removal costs, UGI Utilities 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: December 31, September 30, December 31, Regulatory assets: Income taxes recoverable $ 115.2 $ 110.1 $ 126.5 Underfunded pension and postretirement plans 85.3 87.1 138.3 Environmental costs 58.5 58.8 60.8 Removal costs, net 31.3 32.0 31.4 Other 8.5 13.0 5.8 Total regulatory assets $ 298.8 $ 301.0 $ 362.8 Regulatory liabilities (a): Postretirement benefits $ 17.3 $ 17.8 $ 17.3 Deferred fuel and power refunds 22.2 36.7 12.7 State tax benefits — distribution system repairs 23.5 22.6 19.1 PAPUC temporary rates order 24.8 24.4 — Excess federal deferred income taxes 280.9 285.2 303.9 Other 4.8 3.5 4.5 Total regulatory liabilities $ 373.5 $ 390.2 $ 357.5 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Condensed Consolidated Balance Sheets. 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 PGC rates in the case of Gas Utility and 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 retail core-market customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at December 31, 2018 , September 30, 2018 and December 31, 2017 were $0.8 , $2.9 and $(1.7) , respectively. PAPUC Temporary Rates Order. On May 17, 2018, the PAPUC ordered each regulated utility currently not in a general base rate case proceeding, including UGI Gas, PNG and CPG, to reduce their rates through the establishment of a negative surcharge applied to bills rendered on or after July 1, 2018. The temporary negative surcharge will be reconciled at the end of each fiscal year to actual tax savings realized. Any difference in the amount of bill credit received by customers and the amount of benefits received by the Company during the period the negative surcharge is in effect is reconciled in the calculation of a new negative surcharge effective January 1 of the subsequent calendar year. The negative surcharge will remain in place until the effective date of new rates established in the utility’s next general base rate proceeding. For the merged Gas Utility, such negative surcharge reduced base rate revenues by 5.78% , 3.90% and 8.19% , respectively, for the UGI South, UGI North and UGI Central rate districts for the three months ended December 31, 2018 and is subject to reconciliation during the period the negative surcharges remain in effect. In its May 17, 2018 Order, the PAPUC also required Pennsylvania utilities to establish a regulatory liability for tax benefits that accrued during the period beginning January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate. The rate treatment of this regulatory liability, plus accrued interest, for each Gas Utility rate district will be addressed in a future proceeding and the Company cannot predict the ultimate treatment of this liability. In UGI Gas’s base rate proceeding filed January 28, 2019 (see “ Base Rate Filings ” below), UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $26.2 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, inclusive of interest, thereby satisfying a requirement to make a proposal for distributing those benefits within three years of the May 17, 2018 Order. The negative surcharge will become effective for a twelve-month period beginning on the effective date of the new base rates. For Pennsylvania utilities that were in a general base rate proceeding, including Electric Utility, no negative surcharge applies. The tax benefits that accrued during the period January 1, 2018 through October 26, 2018, the date before Electric Utility’s base rate case became effective (see below), were refunded to Electric Utility ratepayers through a one-time bill credit. 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 6). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess federal deferred income taxes resulting from the remeasurement 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 is being amortized and credited to tax expense. Other Regulatory Matters Utility Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and MDPSC, respectively, to merge PNG and CPG into UGI Utilities, with a targeted effective date of October 1, 2018. After receiving all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged into UGI Utilities effective October 1, 2018. Consistent with the MDPSC order issued July 25, 2018, and the PAPUC order issued September, 26, 2018, the former CPG, PNG and UGI Utilities, Inc. Gas Division service territories became the UGI Central, UGI North and UGI South rate districts of the UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI Utilities’ obligations under the settlement approved by the PAPUC include various non-monetary conditions requiring UGI Utilities to maintain separate accounting-type schedules for limited future ratemaking purposes. Base Rate Filings. On January 28, 2019, UGI Gas filed a request with the PAPUC to increase its operating revenues for residential, commercial and industrial customers by $ 71.1 annually. The requested rate increase applies to the consolidated UGI Central, UGI North and UGI South rate districts. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and fund new programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Additionally, UGI Gas has proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return $26.2 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, inclusive of interest. As proposed, the negative surcharge will become effective for a twelve-month period beginning on the effective date of the new base rates. UGI Gas is requesting that the new gas rates become effective March 29, 2019. However, the PAPUC typically suspends the effective date for general base rate proceedings for a period not to exceed nine months after the filing date to allow for investigation and public hearings. UGI Utilities cannot predict the timing or the ultimate outcome of the rate case review process. On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution revenues by $9.2 , which was later reduced by Electric Utility to $7.7 to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final order providing for a $3.2 annual base distribution rate increase for Electric Utility, effective October 27, 2018. As part of the final order, Electric Utility provided customers with a one-time $0.2 billing credit associated with 2018 TCJA tax benefits. On November 26, 2018, the Pennsylvania Office of Consumer Advocate filed an appeal to the Pennsylvania Commonwealth Court challenging the PAPUC’s acceptance of the UGI Utilities’ use of a fully projected future test year and handling of consolidated federal income tax benefits. UGI Utilities cannot predict the ultimate outcome of this appeal. On January 19, 2017, PNG (now the UGI North rate district of Gas Utility) filed a rate request with the PAPUC to increase PNG’s annual base operating revenues for residential, commercial and industrial customers by $21.7 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2017, all active parties supported the filing of a Joint Petition for Approval of Settlement of all issues with the PAPUC providing for an $11.3 PNG annual base distribution rate increase. On August 31, 2017, the PAPUC approved the Joint Petition and the increase became effective October 20, 2017. Manor Township, Pennsylvania Natural Gas Incident Complaint. In connection with a July 2, 2017, explosion in Manor Township, Lancaster County, Pennsylvania, that resulted in the death of one UGI Utilities employee and injuries to two UGI Utilities employees and one sewer authority employee, and destroyed two residences and damaged several other homes, the BIE filed a formal complaint at the PAPUC in which BIE alleged that UGI Utilities committed multiple violations of federal and state gas pipeline regulations in connection with its emergency response leading up to the explosion, and it requested that the PAPUC order UGI Utilities to pay approximately $2.1 in civil penalties, which is the maximum allowable fine. On November 16, 2018, UGI Utilities filed its formal written answer contesting the BIE complaint. The matter remains pending before the PAPUC.

Energy Services Accounts Receiv

Energy Services Accounts Receivable Securitization Facility	3 Months Ended
	Dec. 31, 2018
Transfers and Servicing [Abstract]
Energy Services Accounts Receivable Securitization Facility	Note 9 — Energy Services Accounts Receivable Securitization Facility Energy Services has a Receivables Facility currently scheduled to expire in October 2019. The Receivables Facility, as amended, provides Energy Services 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 uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes. Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, 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 and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable. Losses on sales of receivables to the bank during the three months ended December 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 three months ended December 31, 2018 and 2017 , as well as the balance of ESFC trade receivables at December 31, 2018 , September 30, 2018 and December 31, 2017 , is as follows: Three Months Ended December 31, 2018 2017 Trade receivables transferred to ESFC during the period $ 392.6 $ 270.6 ESFC trade receivables sold to the bank during the period $ 25.0 $ 48.0 December 31, 2018 September 30, 2018 December 31, 2017 ESFC trade receivables — end of period (a) $ 135.4 $ 65.0 $ 101.0 (a) At December 31, 2018 , September 30, 2018 , and December 31, 2017 , the amounts of ESFC trade receivables sold to the bank were $10.0 , $2.0 and $45.0 , respectively. Amounts sold to the bank are reflected as “ Short-term borrowings ” on the Condensed Consolidated Balance Sheets.

Debt

Debt	3 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt	Note 10 — Debt UGI International. On October 18, 2018, UGI International, LLC, a wholly owned second-tier subsidiary of UGI, entered into the 2018 UGI International Credit Facilities Agreement, a five -year unsecured Senior Facilities Agreement with a consortium of banks consisting of (1) a €300 variable-rate term loan which was drawn on October 25, 2018, and (2) a €300 senior unsecured multicurrency revolving facility agreement. The 2018 UGI International Credit Facilities Agreement matures on October 18, 2023. Term loan borrowings bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate, which euribor rate has a floor of zero. The margin on term loan borrowings, which ranges from 1.55% to 3.20% , is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined. The initial margin on term loan borrowings is 1.70% . UGI International, LLC has entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on term loan borrowings at 0.34% . Under the multicurrency revolving credit facility 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 1.20% to 2.85% . Loans made in U.S. dollars will bear interest at the associated LIBOR rate plus a margin ranging from 1.45% to 3.10% . The margin on revolving facility borrowings is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined. Restrictive covenants under the 2018 UGI International Credit Facilities Agreement include restrictions on the incurrence of additional indebtedness and also restrict liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. In addition, the 2018 UGI International Credit Facilities Agreement requires a ratio of consolidated total net indebtedness to consolidated EBITDA, as defined, not to exceed 3.85 to 1.00. On October 25, 2018, UGI International, LLC issued, in an underwritten private placement, €350 principal amount of the UGI International 3.25% Senior Notes due November 1, 2025. The UGI International 3.25% Senior Notes rank equal in right of payment with indebtedness issued under the 2018 UGI International Credit Facilities Agreement. The net proceeds from the UGI International 3.25% Senior Notes and the 2018 UGI International Credit Facilities Agreement variable-rate term loan plus cash on hand were used on October 25, 2018 (1) to repay €540 outstanding principal of UGI France’s variable-rate term loan under its 2015 senior facilities agreement; €45.8 outstanding principal of Flaga’s variable-rate term loan; and $49.9 outstanding principal of Flaga’s U.S. dollar variable-rate term loan, plus accrued and unpaid interest, and (2) for general corporate purposes. Because these outstanding term loans were refinanced on a long-term basis in October 2018, we have classified €60 of such debt due in April 2019 as long-term debt on the September 30, 2018 Consolidated Balance Sheet. Upon entering into the 2018 UGI International Credit Facilities Agreement, we also terminated (1) UGI International’s existing revolving credit facility agreement dated December 19, 2017, (2) UGI France’s revolving credit facility under its 2015 senior facilities agreement and (3) Flaga’s credit facility agreement. We have designated term loan borrowings under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes as net investment hedges. UGI Utilities Subsequent Event. On February 1, 2019, UGI Utilities issued in a private placement $150 of UGI Utilities 4.55% Senior Notes due February 1, 2049. The UGI Utilities 4.55% Senior Notes were issued pursuant to a Note Purchase Agreement dated December 21, 2018, between UGI Utilities and certain note purchasers. The UGI Utilities 4.55% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the sale of the UGI Utilities 4.55% Senior Notes were used to reduce short-term borrowings and for general corporate purposes. The UGI Utilities 4.55% Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The UGI Utilities 4.55% Senior Notes require UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 11 — 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 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. UGI’s capital contributions may be made from time to time through July 1, 2019 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 Standby Equity Commitment Agreement, AmeriGas Partners will issue to UGI or a wholly owned subsidiary new Class B Common Units representing limited partner interests in AmeriGas Partners. The Class B Common 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 Common 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 Common Units. While outstanding, the Class B Common 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 Common Units, holders may elect to convert all or any portion of the Class B Common 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 Common Units, the Partnership may elect to convert all or any portion of the Class B Common 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 Common 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 Common 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 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 South and Electric Utility. Beginning in 2006 and 2008, UGI Utilities also owned and operated two acquired subsidiaries (CPG and PNG), which now constitute UGI North and UGI Central, with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. CPG and PNG merged into UGI Utilities effective October 1, 2018. Prior to the Utility Merger, each of UGI Utilities and its subsidiaries, CPG and PNG, were subject to COAs with the PADEP to address the remediation of specified former MGP sites in Pennsylvania. In accordance with the COAs, as amended to recognize the Utility Merger, UGI Utilities, as the successor to CPG and PNG, is 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 and in the case of one COA, an additional obligation to plug specific natural gas wells, or make expenditures for such activities in an amount equal to an annual environmental cost cap. The cost cap of the three COAs, in the aggregate, is $5.4 . The three COAs are currently scheduled to terminate at the end of 2031, 2020 and 2020. At December 31, 2018 , September 30, 2018 and December 31, 2017 , our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $50.5 , $51.0 and $53.4 , respectively. UGI Utilities has recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 8 ). 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 receives 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 December 31, 2018 , September 30, 2018 and December 31, 2017 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania was material. AmeriGas Propane AmeriGas OLP Saranac Lake. In 2008, the NYDEC notified AmeriGas OLP that the NYDEC 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 NYDEC disclosed contamination related to a former MGP. AmeriGas OLP responded to the NYDEC in 2009 to dispute the contention it was a PRP as it did not operate the MGP and appeared to only own a portion of the site. In 2017, the NYDEC communicated to AmeriGas OLP that the NYDEC had previously issued three RODs related to remediation of the site totaling approximately $27.7 and requested additional information regarding AmeriGas OLP’s purported ownership. AmeriGas renewed its challenge to designation as a PRP and identified potential defenses. The NYDEC subsequently identified a third party PRP with respect to the site. The NYDEC commenced implementation of the remediation plan in the spring of 2018. Based on our evaluation of the available information, the Partnership accrued an undiscounted environmental remediation liability of $7.5 related to the site during the third quarter of Fiscal 2017. 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, 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 Missouri District Court. As the result of rulings on a series of procedural filings, including petitions filed with the Eighth Circuit and the U.S. Supreme Court, both the federal and state law claims of the direct customer plaintiffs and the state law claims of the indirect customer plaintiffs were remanded to the Western Missouri District Court. The decision of the Western Missouri District Court to dismiss the federal antitrust claims of the indirect customer plaintiffs was upheld by the Eighth Circuit. Motions are pending before the Western Missouri District Court regarding the indirect purchasers’ state law claims. 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	3 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
Defined Benefit Pension and Other Postretirement Plans	Note 12 — Defined Benefit Pension and Other Postretirement Plans The U.S. Pension Plan is 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 benefits are based on years of service, age and employee compensation. 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 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 December 31, 2018 2017 2018 2017 Service cost $ 2.5 $ 2.8 $ — $ 0.2 Interest cost 6.8 6.5 0.2 0.2 Expected return on assets (9.0 ) (8.6 ) (0.2 ) (0.2 ) Amortization of: Prior service cost (benefit) 0.1 0.1 (0.1 ) (0.1 ) Actuarial loss 1.9 3.3 — 0.1 Net benefit cost (benefit) 2.3 4.1 (0.1 ) 0.2 Change in associated regulatory liabilities — — (0.3 ) (0.1 ) Net benefit cost (benefit) after change in regulatory liabilities $ 2.3 $ 4.1 $ (0.4 ) $ 0.1 The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. During the three months ended December 31, 2018 , the Company made no cash contributions to the U.S. Pension Plan. During the three months ended December 31, 2017 , the Company made cash contributions to the U.S. Pension Plan of $3.4 . The Company expects to make additional cash contributions of approximately $11.5 to the U.S. Pension Plan during the remainder of Fiscal 2019 . UGI Utilities has established a 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 the 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 three months ended December 31, 2018 and 2017 . We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. Net costs associated with these plans for the three months ended December 31, 2018 and 2017 , were not material.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 13 — Fair Value Measurements Recurring Fair Value Measurements The following table presents, on a gross basis, our financial assets and liabilities, including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of December 31, 2018 , September 30, 2018 and December 31, 2017 : Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2018: Derivative instruments: Assets: Commodity contracts $ 72.1 $ 27.9 $ — $ 100.0 Foreign currency contracts $ — $ 24.4 $ — $ 24.4 Liabilities: Commodity contracts $ (35.6 ) $ (78.0 ) $ — $ (113.6 ) Foreign currency contracts $ — $ (8.8 ) $ — $ (8.8 ) Interest rate contracts $ — $ (3.7 ) $ — $ (3.7 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 38.0 $ — $ — $ 38.0 September 30, 2018: Derivative instruments: Assets: Commodity contracts $ 93.5 $ 117.5 $ — $ 211.0 Foreign currency contracts $ — $ 20.6 $ — $ 20.6 Cross-currency contracts $ — $ 0.9 $ — $ 0.9 Liabilities: Commodity contracts $ (33.6 ) $ (9.8 ) $ — $ (43.4 ) Foreign currency contracts $ — $ (14.4 ) $ — $ (14.4 ) Interest rate contracts $ — $ (1.0 ) $ — $ (1.0 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 40.8 $ — $ — $ 40.8 December 31, 2017: Derivative instruments: Assets: Commodity contracts $ 47.9 $ 71.7 $ — $ 119.6 Foreign currency contracts $ — $ 11.6 $ — $ 11.6 Liabilities: Commodity contracts $ (31.0 ) $ (13.5 ) $ — $ (44.5 ) Foreign currency contracts $ — $ (39.9 ) $ — $ (39.9 ) Interest rate contracts $ — $ (2.1 ) $ — $ (2.1 ) Cross-currency contracts $ — $ (0.9 ) $ — $ (0.9 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 37.7 $ — $ — $ 37.7 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 12 .) 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. 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 December 31, 2018 , September 30, 2018 and December 31, 2017 were as follows: December 31, 2018 September 30, 2018 December 31, 2017 Carrying amount $ 4,211.0 $ 4,199.4 $ 4,319.5 Estimated fair value $ 3,970.8 $ 4,150.3 $ 4,430.0 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 14 . Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	3 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 14 — 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. For more information on the accounting for our derivative instruments, see Note 2 . Commodity Price Risk Regulated Utility Operations Natural Gas Gas Utility’s tariffs contain clauses that permit recovery of all prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PAPUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses 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 8 ). 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 December 31, 2018 , September 30, 2018 and December 31, 2017 , all Electric Utility forward electricity purchase contracts were subject to the NPNS exception. 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 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 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 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 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 Prior to their repayment on October 25, 2018 (see Note 10 ), UGI France’s and Flaga’s long-term debt agreements had interest rates that were generally indexed to short-term market interest rates. UGI France and Flaga entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rates and LIBOR rates of interest on this variable-rate debt. We designated these interest rate swaps as cash flow hedges. These interest rate swaps were settled concurrent with the repayment of the UGI France and Flaga long-term debt. In November 2018, UGI International, LLC entered into pay-fixed, receive-variable interest rate swaps through October 18, 2022, to fix the underlying euribor rate on the 2018 UGI International Credit Facilities Agreement term loan borrowings at 0.34% . We designated these interest rate swaps as cash flow hedges. UGI Utilities has a variable-rate term loan with an interest rate that is indexed to short-term market interest rates. UGI Utilities has entered into a forward starting, amortizing, pay-fixed, receive-variable interest rate swap agreement commencing September 30, 2019, that generally fixes the underlying variable interest rate on borrowings at 3.00% through July 2022. We have designated this interest rate swap as a cash flow hedge. The remainder of our 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 IRPAs. We account for IRPAs as cash flow hedges. At December 31, 2018 , September 30, 2018 and December 31, 2017 , we had no unsettled IRPAs. At December 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 December 31, 2018 , the amount of net gains associated with these contracts expected to be reclassified into earnings during the next twelve months based upon current fair values is $1.4 . 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 to the euro and British pound sterling, we enter 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 “ Other non-operating income (expense), 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. We use the forward rate method for measuring ineffectiveness for these net investment hedges and all changes in the fair value of the forward foreign currency contracts are reported in the cumulative translation adjustment section of AOCI. Concurrent with the issuance of euro-denominated long-term debt under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes in October 2018, we designated this euro-denominated debt as net investment hedges of a portion of our euro-denominated UGI International net investment (see Note 10 ). Cross-currency Contracts Prior to its repayment on October 25, 2018 (see Note 10 ), Flaga entered 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 its U.S. dollar denominated variable-rate term loan. These cross-currency hedges included 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 included interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designated these cross-currency swaps as cash flow hedges. These cross-currency swaps were settled concurrent with the repayment of Flaga’s U.S. dollar variable rate term loan in October 2018. Quantitative Disclosures Related to Derivative Instruments The following table summarizes by derivative type the gross notional amounts related to open derivative contracts at December 31, 2018 , September 30, 2018 and December 31, 2017 , and the final settlement date of the Company's open derivative transactions as of December 31, 2018 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through December 31, 2018 September 30, 2018 December 31, 2017 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms September 2019 14.7 23.2 13.4 FTRs contracts Kilowatt hours N/A — — 63.1 Non-utility Operations LPG swaps Gallons January 2021 450.4 394.3 275.4 Natural gas futures, forward and pipeline contracts Dekatherms October 2023 188.0 159.7 128.3 Natural gas basis swap contracts Dekatherms March 2023 81.2 54.4 90.2 NYMEX natural gas storage Dekatherms June 2019 0.7 1.8 1.3 NYMEX propane storage Gallons April 2019 0.3 0.6 0.1 Electricity long forward and futures contracts Kilowatt hours May 2022 3,974.7 4,307.6 4,733.9 Electricity short forward and futures contracts Kilowatt hours May 2022 366.7 359.3 325.2 Interest Rate Risk: Interest rate swaps Euro October 2022 € 300.0 € 585.8 € 645.8 Interest rate swaps USD July 2022 $ 114.1 $ 114.1 $ — Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2021 $ 408.6 $ 512.2 $ 485.7 Forward foreign currency exchange contracts Euro October 2024 € 172.8 € — € — Cross-currency contracts USD N/A $ — $ 49.9 $ 49.9 Derivative Instrument Credit Risk We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2018 , September 30, 2018 and December 31, 2017 , restricted cash in brokerage accounts totaled $17.4 , $9.6 and $19.8 , 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 December 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 December 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 December 31, 2018 , September 30, 2018 and December 31, 2017 : December 31, September 30, December 31, Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 2.3 $ 1.5 $ 1.2 Cross-currency contracts — 0.9 — 2.3 2.4 1.2 Derivatives subject to PGC and DS mechanisms: Commodity contracts 1.3 3.0 0.4 Derivatives not designated as hedging instruments: Commodity contracts 98.7 208.0 119.2 Foreign currency contracts 22.1 19.1 10.4 120.8 227.1 129.6 Total derivative assets — gross 124.4 232.5 131.2 Gross amounts offset in the balance sheet (34.3 ) (34.3 ) (32.5 ) Cash collateral received — (12.2 ) (12.0 ) Total derivative assets — net $ 90.1 $ 186.0 $ 86.7 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ — $ (0.4 ) $ (5.6 ) Cross-currency contracts — — (0.9 ) Interest rate contracts (3.7 ) (1.0 ) (2.1 ) (3.7 ) (1.4 ) (8.6 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (0.5 ) (0.1 ) (2.3 ) Derivatives not designated as hedging instruments: Commodity contracts (113.1 ) (43.3 ) (42.2 ) Foreign currency contracts (8.8 ) (14.0 ) (34.3 ) (121.9 ) (57.3 ) (76.5 ) Total derivative liabilities — gross (126.1 ) (58.8 ) (87.4 ) Gross amounts offset in the balance sheet 34.3 34.3 32.5 Cash collateral pledged 10.0 — — Total derivative liabilities — net $ (81.8 ) $ (24.5 ) $ (54.9 ) Effects 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 three months ended December 31, 2018 and 2017 : Three Months Ended December 31,: Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Cash Flow Hedges: 2018 2017 2018 2017 Foreign currency contracts $ 1.0 $ (1.4 ) $ 0.8 $ 0.8 Cost of sales Cross-currency contracts (0.1 ) 0.1 (0.3 ) 0.2 Interest expense/other operating income, net Interest rate contracts (2.8 ) 0.7 (1.5 ) (0.5 ) Interest expense Total $ (1.9 ) $ (0.6 ) $ (1.0 ) $ 0.5 Net Investment Hedges: Foreign currency contracts $ 0.9 $ — Gain (Loss) Location of Gain (Loss) Derivatives Not Designated as Hedging Instruments: 2018 2017 Commodity contracts $ (159.7 ) $ 24.4 Cost of sales Commodity contracts (2.8 ) (1.3 ) Revenues Commodity contracts (0.4 ) 0.1 Operating and administrative expenses Foreign currency contracts 8.9 (4.8 ) Other non-operating income (expense), net Total $ (154.0 ) $ 18.4 For the three months ended December 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	3 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Accumulated Other Comprehensive Income	Note 15 — Accumulated Other Comprehensive Income The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2018 and 2017 : Three Months Ended December 31, 2018 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — September 30, 2018 $ (11.0 ) $ (16.1 ) $ (83.3 ) $ (110.4 ) Other comprehensive loss before reclassification adjustments (after-tax) — (1.5 ) (15.6 ) (17.1 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.4 1.0 — 1.4 Reclassification adjustments tax expense (0.1 ) (0.3 ) — (0.4 ) Reclassification adjustments (after-tax) 0.3 0.7 — 1.0 Other comprehensive income (loss) attributable to UGI 0.3 (0.8 ) (15.6 ) (16.1 ) Reclassification of stranded income tax effects related to TCJA (2.9 ) (3.7 ) — (6.6 ) AOCI — December 31, 2018 $ (13.6 ) $ (20.6 ) $ (98.9 ) $ (133.1 ) Three Months Ended December 31, 2017 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) — (0.4 ) 22.3 21.9 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.6 (0.5 ) — 0.1 Reclassification adjustments tax (benefit) expense (0.2 ) 0.1 — (0.1 ) Reclassification adjustments (after-tax) 0.4 (0.4 ) — — Other comprehensive income (loss) attributable to UGI 0.4 (0.8 ) 22.3 21.9 AOCI — December 31, 2017 $ (18.8 ) $ (22.2 ) $ (30.5 ) $ (71.5 ) For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 14 .

Segment Information

Segment Information	3 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Segment Information	Note 16 — 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 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 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 2018 Annual Report. We evaluate AmeriGas Propane’s performance principally based upon 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 December 31, 2018 Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 2,200.2 $ — $ 820.2 $ 710.7 $ 372.5 $ 299.1 $ (2.3 ) Intersegment revenues $ — $ (111.6 ) (c) $ — $ — $ 86.9 $ 23.6 $ 1.1 Cost of sales $ 1,425.0 $ (110.8 ) (c) $ 378.5 $ 448.6 $ 377.5 $ 159.5 $ 171.7 Segment profit: Operating income (loss) $ 167.7 $ 0.4 $ 166.6 $ 58.3 $ 41.1 $ 77.0 $ (175.7 ) Income from equity investees 1.5 — — — 1.5 (d) — — Loss on extinguishments of debt (6.1 ) — — (6.1 ) — — — Other non-operating income (expense), net 9.0 — — 0.7 — 0.4 7.9 Interest expense (60.2 ) — (42.4 ) (5.4 ) (0.5 ) (11.7 ) (0.2 ) Income (loss) before income taxes $ 111.9 $ 0.4 $ 124.2 $ 47.5 $ 42.1 $ 65.7 $ (168.0 ) Partnership Adjusted EBITDA (a) $ 210.7 Noncontrolling interests’ net income (loss) $ 24.3 $ — $ 81.5 $ 0.1 $ — $ — $ (57.3 ) Depreciation and amortization $ 111.2 $ — $ 45.7 $ 31.4 $ 11.5 $ 22.5 $ 0.1 Capital expenditures (including the effects of accruals) $ 161.8 $ — $ 31.0 $ 27.8 $ 25.1 $ 77.3 $ 0.6 As of December 31, 2018 Total assets $ 12,368.3 $ (144.3 ) $ 4,020.6 $ 3,287.5 $ 1,504.9 $ 3,424.8 $ 274.8 Short-term borrowings $ 676.3 $ — $ 368.5 $ 1.8 $ 10.0 $ 296.0 $ — Goodwill $ 3,154.8 $ — $ 2,003.0 $ 951.9 $ 17.8 $ 182.1 $ — Three Months Ended December 31, 2017 Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 2,125.2 $ — $ 787.3 $ 784.2 $ 249.8 $ 305.4 $ (1.5 ) Intersegment revenues $ — $ (97.1 ) (c) $ — $ — $ 78.2 $ 17.7 $ 1.2 Cost of sales $ 1,137.4 $ (96.0 ) (c) $ 366.1 $ 484.8 $ 239.0 $ 151.8 $ (8.3 ) Segment profit: Operating income (e) $ 395.0 $ 0.2 $ 147.9 $ 93.2 $ 53.4 $ 96.9 $ 3.4 Income (loss) from equity investees 1.0 — — (0.2 ) 1.2 (d) — — Other non-operating expense, net (e) (8.0 ) — — (4.8 ) (1.1 ) (0.6 ) (1.5 ) Interest expense (58.2 ) — (40.6 ) (5.6 ) (0.9 ) (10.9 ) (0.2 ) Income before income taxes $ 329.8 $ 0.2 $ 107.3 $ 82.6 $ 52.6 $ 85.4 $ 1.7 Partnership Adjusted EBITDA (a) $ 194.1 Noncontrolling interests’ net income (loss) $ 68.3 $ — $ 68.0 $ (0.3 ) $ — $ — $ 0.6 Depreciation and amortization $ 110.3 $ — $ 47.4 $ 32.2 $ 10.1 $ 20.4 $ 0.2 Capital expenditures (including the effects of accruals) $ 128.5 $ — $ 23.6 $ 21.7 $ 11.3 $ 71.7 $ 0.2 As of December 31, 2017 Total assets $ 12,343.9 $ (62.6 ) $ 4,206.2 $ 3,450.1 $ 1,325.1 $ 3,174.7 $ 250.4 Short-term borrowings $ 586.1 $ — $ 263.5 $ 41.1 $ 100.0 $ 181.5 $ — Goodwill $ 3,185.5 $ — $ 2,001.3 $ 990.6 $ 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 2018 2017 Partnership Adjusted EBITDA $ 210.7 $ 194.1 Depreciation and amortization (45.7 ) (47.4 ) Interest expense (42.4 ) (40.6 ) Noncontrolling interest (i) 1.6 1.2 Income before income taxes $ 124.2 $ 107.3 (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 $(165.9) and $6.6 during the three months ended December 31, 2018 and 2017 , respectively. (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) Represents AFUDC associated with our PennEast Pipeline equity investment. (e) Amounts reflect the reclassification of non-service income (expense) associated with our pension and other postretirement plans from “Operating and administrative expenses” to “Other non-operating income (expense), net,” on the Condensed Consolidated Statements of Income as a result of the adoption of ASU No. 2017-07 (see Note 3).

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Revenue Recognition	Revenue Recognition. Effective October 1, 2018, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers,” which, as amended, is included in ASC 606. This new accounting guidance supersedes previous revenue recognition requirements in ASC 605. ASC 606 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. We adopted this new accounting guidance using the modified retrospective transition method to those contracts which were not completed as of October 1, 2018. Periods prior to October 1, 2018, have not been restated and continue to be reported in accordance with ASC 605. The Company recorded a $7.1 reduction to opening retained earnings as of October 1, 2018, to reflect the cumulative effect of ASC 606 on certain contracts not complete as of the date of adoption. The adoption of ASC 606 did not, and is not expected to, have a material impact on the amount or timing of our revenue recognition and on our consolidated net income, cash flows or financial position. Certain revenues such as revenue from leases, financial instruments and other revenues are not within the scope of ASC 606 because they are not from contracts with customers. Such revenues are accounted for in accordance with other GAAP. Revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, are not included in revenues. Gross receipts taxes at Midstream & Marketing and Electric Utility are presented on a gross basis. The Company has elected to use the practical expedient to expense the costs to obtain contracts when incurred for contracts that have a term less than one year .
Restricted Cash	Restricted Cash. Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. Upon adoption of revised accounting guidance in October 2018 (see Note 3 ), restricted cash is included within the Company’s Condensed Consolidated Statements of Cash Flows, with changes in the balance no longer reflected as a separate investing activity.
Earnings Per Common Share	Earnings Per Common Share. Basic earnings per share attributable to UGI shareholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI 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 NPNS exception is elected. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is subject to regulatory ratemaking mechanisms or if it qualifies and is designated as a hedge for accounting purposes. Certain of our derivative instruments qualify and are designated as cash flow hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in 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. We do not designate our commodity and certain foreign currency derivative instruments as hedges under GAAP. Changes in the fair values of these derivative instruments are reflected in net income. Gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities 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 the cumulative translation adjustment section of AOCI until such foreign net investment is sold or liquidated. 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 enter 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 “ Other non-operating income (expense), 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.
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 in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.
Reclassifications	Reclassifications. Certain amounts for the three months ended December 31, 2017, have been reclassified as a result of the adoption of revised accounting guidance pertaining to certain net periodic pension and other postretirement benefit costs and restricted cash (see Note 3 ). In addition, certain other prior-period amounts have been reclassified to conform to the current-period presentation.
Other non-operating income (expense), net	Other non-operating income (expense), net. Included in “ Other non-operating income (expense), net ,” on the Condensed Consolidated Statements of Income are net gains and losses on forward foreign currency contracts used to reduce volatility in net income associated with our foreign operations, and non-service income (expense) associated with our pension and other postretirement plans.
Accounting Standards Not Yet Adopted	Accounting Standards Not Yet Adopted Pension and Other Postretirement Benefit Costs Disclosures. In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. The amendments in this ASU are effective for interim and annual periods beginning October 1, 2020 (Fiscal 2021). The guidance shall be adopted retrospectively for all periods presented in the financial statements. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted. Fair Value Measurements Disclosures. In August 2018, the FASB issued ASU No. 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. The amendments in this ASU are effective for annual periods beginning October 1, 2020 (Fiscal 2021). The guidance regarding removing and modifying disclosures will be adopted on a retrospective basis and the guidance regarding new disclosures will be adopted on a prospective basis. Early adoption is permitted. The Company is in the process of assessing the impact on its financial statement disclosures from the adoption of the new guidance and determining the period in which the new guidance will be adopted. 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 the Company for interim and annual periods beginning October 1, 2019 (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 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. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, 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 the Company for interim and annual periods beginning October 1, 2019 (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 unless an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption. We will adopt ASU No. 2016-02, as updated, effective October 1, 2019, and expect to elect the transition option which would allow the Company to maintain historical presentation for periods before October 1, 2019. The Company has completed a preliminary assessment for evaluating the impact of the guidance and anticipates that its adoption will result in a significant amount of right-of-use assets and lease liabilities for leases in effect at the adoption date. The Company has begun implementation activities including accumulating contracts and lease data in formats compatible with a new lease management system that will assist with the initial adoption of the standard.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Restrictions on Cash and Cash Equivalents	The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Condensed Consolidated Balance Sheets to the corresponding amounts reported on the Condensed Consolidated Statements of Cash Flows: Cash, Cash Equivalents and Restricted Cash December 31, 2018 December 31, 2017 September 30, 2018 September 30, 2017 Cash and cash equivalents $ 477.6 $ 446.4 $ 452.6 $ 558.4 Restricted cash 17.4 19.8 9.6 10.3 Cash, cash equivalents and restricted cash $ 495.0 $ 466.2 $ 462.2 $ 568.7
Schedule of Cash and Cash Equivalents	The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Condensed Consolidated Balance Sheets to the corresponding amounts reported on the Condensed Consolidated Statements of Cash Flows: Cash, Cash Equivalents and Restricted Cash December 31, 2018 December 31, 2017 September 30, 2018 September 30, 2017 Cash and cash equivalents $ 477.6 $ 446.4 $ 452.6 $ 558.4 Restricted cash 17.4 19.8 9.6 10.3 Cash, cash equivalents and restricted cash $ 495.0 $ 466.2 $ 462.2 $ 568.7
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 2018 2017 Denominator (thousands of shares): Weighted-average common shares outstanding — basic 174,413 173,670 Incremental shares issuable for stock options and awards (a) 3,153 3,278 Weighted-average common shares outstanding — diluted 177,566 176,948 (a) For the three months ended December 31, 2018 and 2017 , there were 30 and 146 shares, respectively, associated with outstanding stock option awards that were excluded from the computation of diluted earnings per share above because their effect was antidilutive.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	3 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Summary of Disaggregation of Revenue	The following table presents our disaggregated revenues by reportable segment for the three months ended December 31, 2018: Total Eliminations AmeriGas Propane UGI International Midstream & Marketing (a) UGI Utilities (a) Corporate & Other Revenues from contracts with customers: Utility: Core Market: Residential $ 175.7 $ — $ — $ — $ — $ 175.7 $ — Commercial & Industrial 67.6 — — — — 67.6 — Large delivery service 39.5 — — — — 39.5 — Off-system sales and capacity releases 15.2 (22.9 ) — — — 38.1 — Other (b) 0.5 (0.7 ) — — — 1.2 — Total Utility 298.5 (23.6 ) — — — 322.1 — Non-Utility: LPG: Retail 1,229.7 — 721.9 507.8 — — — Wholesale 60.0 — 21.0 39.0 — — — Energy Marketing 468.9 (47.5 ) — 143.1 373.3 — — Midstream: Pipeline 19.4 — — — 19.4 — — Peaking 2.0 (38.7 ) — — 40.7 — — Other 1.0 — — — 1.0 — — Electricity Generation 11.7 — — — 11.7 — — Other 84.0 (0.7 ) 60.6 12.4 11.7 — — Total Non-Utility 1,876.7 (86.9 ) 803.5 702.3 457.8 — — Total revenues from contracts with customers 2,175.2 (110.5 ) 803.5 702.3 457.8 322.1 — Other revenues (c) 25.0 (1.1 ) 16.7 8.4 1.6 0.6 (1.2 ) Total revenues $ 2,200.2 $ (111.6 ) $ 820.2 $ 710.7 $ 459.4 $ 322.7 $ (1.2 ) (a) Includes intersegment revenues principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (b) UGI Utilities includes unallocated negative surcharge revenue of $(4.1) as a result of a PAPUC Order issued May 17, 2018, related to TCJA (see Note 8). (c) Primarily represents revenues from tank rentals at AmeriGas Propane and UGI International, revenues from certain gathering assets at Midstream & Marketing, and gains and losses on commodity derivative instruments not associated with current-period transactions reflected in Corporate & Other, all of which are not within the scope of ASC 606 and accounted for in accordance with other GAAP.

Inventories (Tables)

Inventories (Tables)	3 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
Components of Inventories	Inventories comprise the following: December 31, September 30, December 31, Non-utility LPG and natural gas $ 206.7 $ 231.7 $ 216.4 Gas Utility natural gas 34.9 37.3 34.6 Materials, supplies and other 52.1 49.2 56.3 Total inventories $ 293.7 $ 318.2 $ 307.3

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	3 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Components of Company's Goodwill and Intangible Assets	Goodwill and intangible assets comprise the following: December 31, September 30, December 31, Goodwill (not subject to amortization) $ 3,154.8 $ 3,160.4 $ 3,185.5 Intangible assets: Customer relationships, noncompete agreements and other $ 853.0 $ 848.6 $ 862.0 Trademarks and tradenames 7.9 7.9 — Accumulated amortization (405.4 ) (393.2 ) (355.0 ) Intangible assets, net (definite-lived) 455.5 463.3 507.0 Trademarks and tradenames (indefinite-lived) 49.7 50.3 134.9 Total intangible assets, net $ 505.2 $ 513.6 $ 641.9

Utility Regulatory Assets and_2

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)	3 Months Ended
	Dec. 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: December 31, September 30, December 31, Regulatory assets: Income taxes recoverable $ 115.2 $ 110.1 $ 126.5 Underfunded pension and postretirement plans 85.3 87.1 138.3 Environmental costs 58.5 58.8 60.8 Removal costs, net 31.3 32.0 31.4 Other 8.5 13.0 5.8 Total regulatory assets $ 298.8 $ 301.0 $ 362.8 Regulatory liabilities (a): Postretirement benefits $ 17.3 $ 17.8 $ 17.3 Deferred fuel and power refunds 22.2 36.7 12.7 State tax benefits — distribution system repairs 23.5 22.6 19.1 PAPUC temporary rates order 24.8 24.4 — Excess federal deferred income taxes 280.9 285.2 303.9 Other 4.8 3.5 4.5 Total regulatory liabilities $ 373.5 $ 390.2 $ 357.5 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Condensed Consolidated Balance Sheets.
Schedule of Regulatory Liabilities	The following regulatory assets and liabilities associated with UGI Utilities are included in our accompanying Condensed Consolidated Balance Sheets: December 31, September 30, December 31, Regulatory assets: Income taxes recoverable $ 115.2 $ 110.1 $ 126.5 Underfunded pension and postretirement plans 85.3 87.1 138.3 Environmental costs 58.5 58.8 60.8 Removal costs, net 31.3 32.0 31.4 Other 8.5 13.0 5.8 Total regulatory assets $ 298.8 $ 301.0 $ 362.8 Regulatory liabilities (a): Postretirement benefits $ 17.3 $ 17.8 $ 17.3 Deferred fuel and power refunds 22.2 36.7 12.7 State tax benefits — distribution system repairs 23.5 22.6 19.1 PAPUC temporary rates order 24.8 24.4 — Excess federal deferred income taxes 280.9 285.2 303.9 Other 4.8 3.5 4.5 Total regulatory liabilities $ 373.5 $ 390.2 $ 357.5 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Condensed Consolidated Balance Sheets.

Energy Services Accounts Rece_2

Energy Services Accounts Receivable Securitization Facility (Tables)	3 Months Ended
	Dec. 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 three months ended December 31, 2018 and 2017 , as well as the balance of ESFC trade receivables at December 31, 2018 , September 30, 2018 and December 31, 2017 , is as follows: Three Months Ended December 31, 2018 2017 Trade receivables transferred to ESFC during the period $ 392.6 $ 270.6 ESFC trade receivables sold to the bank during the period $ 25.0 $ 48.0 December 31, 2018 September 30, 2018 December 31, 2017 ESFC trade receivables — end of period (a) $ 135.4 $ 65.0 $ 101.0 (a) At December 31, 2018 , September 30, 2018 , and December 31, 2017 , the amounts of ESFC trade receivables sold to the bank were $10.0 , $2.0 and $45.0 , respectively. Amounts sold to the bank are reflected as “ Short-term borrowings ” on the Condensed Consolidated Balance Sheets.

Defined Benefit Pension and O_2

Defined Benefit Pension and Other Postretirement Plans (Tables)	3 Months Ended
	Dec. 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 December 31, 2018 2017 2018 2017 Service cost $ 2.5 $ 2.8 $ — $ 0.2 Interest cost 6.8 6.5 0.2 0.2 Expected return on assets (9.0 ) (8.6 ) (0.2 ) (0.2 ) Amortization of: Prior service cost (benefit) 0.1 0.1 (0.1 ) (0.1 ) Actuarial loss 1.9 3.3 — 0.1 Net benefit cost (benefit) 2.3 4.1 (0.1 ) 0.2 Change in associated regulatory liabilities — — (0.3 ) (0.1 ) Net benefit cost (benefit) after change in regulatory liabilities $ 2.3 $ 4.1 $ (0.4 ) $ 0.1

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	3 Months Ended
	Dec. 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 December 31, 2018 , September 30, 2018 and December 31, 2017 : Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2018: Derivative instruments: Assets: Commodity contracts $ 72.1 $ 27.9 $ — $ 100.0 Foreign currency contracts $ — $ 24.4 $ — $ 24.4 Liabilities: Commodity contracts $ (35.6 ) $ (78.0 ) $ — $ (113.6 ) Foreign currency contracts $ — $ (8.8 ) $ — $ (8.8 ) Interest rate contracts $ — $ (3.7 ) $ — $ (3.7 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 38.0 $ — $ — $ 38.0 September 30, 2018: Derivative instruments: Assets: Commodity contracts $ 93.5 $ 117.5 $ — $ 211.0 Foreign currency contracts $ — $ 20.6 $ — $ 20.6 Cross-currency contracts $ — $ 0.9 $ — $ 0.9 Liabilities: Commodity contracts $ (33.6 ) $ (9.8 ) $ — $ (43.4 ) Foreign currency contracts $ — $ (14.4 ) $ — $ (14.4 ) Interest rate contracts $ — $ (1.0 ) $ — $ (1.0 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 40.8 $ — $ — $ 40.8 December 31, 2017: Derivative instruments: Assets: Commodity contracts $ 47.9 $ 71.7 $ — $ 119.6 Foreign currency contracts $ — $ 11.6 $ — $ 11.6 Liabilities: Commodity contracts $ (31.0 ) $ (13.5 ) $ — $ (44.5 ) Foreign currency contracts $ — $ (39.9 ) $ — $ (39.9 ) Interest rate contracts $ — $ (2.1 ) $ — $ (2.1 ) Cross-currency contracts $ — $ (0.9 ) $ — $ (0.9 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 37.7 $ — $ — $ 37.7 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 12 .)
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 December 31, 2018 , September 30, 2018 and December 31, 2017 were as follows: December 31, 2018 September 30, 2018 December 31, 2017 Carrying amount $ 4,211.0 $ 4,199.4 $ 4,319.5 Estimated fair value $ 3,970.8 $ 4,150.3 $ 4,430.0

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Dec. 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 at December 31, 2018 , September 30, 2018 and December 31, 2017 , and the final settlement date of the Company's open derivative transactions as of December 31, 2018 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through December 31, 2018 September 30, 2018 December 31, 2017 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms September 2019 14.7 23.2 13.4 FTRs contracts Kilowatt hours N/A — — 63.1 Non-utility Operations LPG swaps Gallons January 2021 450.4 394.3 275.4 Natural gas futures, forward and pipeline contracts Dekatherms October 2023 188.0 159.7 128.3 Natural gas basis swap contracts Dekatherms March 2023 81.2 54.4 90.2 NYMEX natural gas storage Dekatherms June 2019 0.7 1.8 1.3 NYMEX propane storage Gallons April 2019 0.3 0.6 0.1 Electricity long forward and futures contracts Kilowatt hours May 2022 3,974.7 4,307.6 4,733.9 Electricity short forward and futures contracts Kilowatt hours May 2022 366.7 359.3 325.2 Interest Rate Risk: Interest rate swaps Euro October 2022 € 300.0 € 585.8 € 645.8 Interest rate swaps USD July 2022 $ 114.1 $ 114.1 $ — Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2021 $ 408.6 $ 512.2 $ 485.7 Forward foreign currency exchange contracts Euro October 2024 € 172.8 € — € — Cross-currency contracts USD N/A $ — $ 49.9 $ 49.9
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 December 31, 2018 , September 30, 2018 and December 31, 2017 : December 31, September 30, December 31, Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 2.3 $ 1.5 $ 1.2 Cross-currency contracts — 0.9 — 2.3 2.4 1.2 Derivatives subject to PGC and DS mechanisms: Commodity contracts 1.3 3.0 0.4 Derivatives not designated as hedging instruments: Commodity contracts 98.7 208.0 119.2 Foreign currency contracts 22.1 19.1 10.4 120.8 227.1 129.6 Total derivative assets — gross 124.4 232.5 131.2 Gross amounts offset in the balance sheet (34.3 ) (34.3 ) (32.5 ) Cash collateral received — (12.2 ) (12.0 ) Total derivative assets — net $ 90.1 $ 186.0 $ 86.7 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ — $ (0.4 ) $ (5.6 ) Cross-currency contracts — — (0.9 ) Interest rate contracts (3.7 ) (1.0 ) (2.1 ) (3.7 ) (1.4 ) (8.6 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (0.5 ) (0.1 ) (2.3 ) Derivatives not designated as hedging instruments: Commodity contracts (113.1 ) (43.3 ) (42.2 ) Foreign currency contracts (8.8 ) (14.0 ) (34.3 ) (121.9 ) (57.3 ) (76.5 ) Total derivative liabilities — gross (126.1 ) (58.8 ) (87.4 ) Gross amounts offset in the balance sheet 34.3 34.3 32.5 Cash collateral pledged 10.0 — — Total derivative liabilities — net $ (81.8 ) $ (24.5 ) $ (54.9 )
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 three months ended December 31, 2018 and 2017 : Three Months Ended December 31,: Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Cash Flow Hedges: 2018 2017 2018 2017 Foreign currency contracts $ 1.0 $ (1.4 ) $ 0.8 $ 0.8 Cost of sales Cross-currency contracts (0.1 ) 0.1 (0.3 ) 0.2 Interest expense/other operating income, net Interest rate contracts (2.8 ) 0.7 (1.5 ) (0.5 ) Interest expense Total $ (1.9 ) $ (0.6 ) $ (1.0 ) $ 0.5 Net Investment Hedges: Foreign currency contracts $ 0.9 $ — Gain (Loss) Location of Gain (Loss) Derivatives Not Designated as Hedging Instruments: 2018 2017 Commodity contracts $ (159.7 ) $ 24.4 Cost of sales Commodity contracts (2.8 ) (1.3 ) Revenues Commodity contracts (0.4 ) 0.1 Operating and administrative expenses Foreign currency contracts 8.9 (4.8 ) Other non-operating income (expense), net Total $ (154.0 ) $ 18.4

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income	The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2018 and 2017 : Three Months Ended December 31, 2018 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — September 30, 2018 $ (11.0 ) $ (16.1 ) $ (83.3 ) $ (110.4 ) Other comprehensive loss before reclassification adjustments (after-tax) — (1.5 ) (15.6 ) (17.1 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.4 1.0 — 1.4 Reclassification adjustments tax expense (0.1 ) (0.3 ) — (0.4 ) Reclassification adjustments (after-tax) 0.3 0.7 — 1.0 Other comprehensive income (loss) attributable to UGI 0.3 (0.8 ) (15.6 ) (16.1 ) Reclassification of stranded income tax effects related to TCJA (2.9 ) (3.7 ) — (6.6 ) AOCI — December 31, 2018 $ (13.6 ) $ (20.6 ) $ (98.9 ) $ (133.1 ) Three Months Ended December 31, 2017 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) — (0.4 ) 22.3 21.9 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.6 (0.5 ) — 0.1 Reclassification adjustments tax (benefit) expense (0.2 ) 0.1 — (0.1 ) Reclassification adjustments (after-tax) 0.4 (0.4 ) — — Other comprehensive income (loss) attributable to UGI 0.4 (0.8 ) 22.3 21.9 AOCI — December 31, 2017 $ (18.8 ) $ (22.2 ) $ (30.5 ) $ (71.5 )

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Schedule of Segment Reporting Information	Three Months Ended December 31, 2018 Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 2,200.2 $ — $ 820.2 $ 710.7 $ 372.5 $ 299.1 $ (2.3 ) Intersegment revenues $ — $ (111.6 ) (c) $ — $ — $ 86.9 $ 23.6 $ 1.1 Cost of sales $ 1,425.0 $ (110.8 ) (c) $ 378.5 $ 448.6 $ 377.5 $ 159.5 $ 171.7 Segment profit: Operating income (loss) $ 167.7 $ 0.4 $ 166.6 $ 58.3 $ 41.1 $ 77.0 $ (175.7 ) Income from equity investees 1.5 — — — 1.5 (d) — — Loss on extinguishments of debt (6.1 ) — — (6.1 ) — — — Other non-operating income (expense), net 9.0 — — 0.7 — 0.4 7.9 Interest expense (60.2 ) — (42.4 ) (5.4 ) (0.5 ) (11.7 ) (0.2 ) Income (loss) before income taxes $ 111.9 $ 0.4 $ 124.2 $ 47.5 $ 42.1 $ 65.7 $ (168.0 ) Partnership Adjusted EBITDA (a) $ 210.7 Noncontrolling interests’ net income (loss) $ 24.3 $ — $ 81.5 $ 0.1 $ — $ — $ (57.3 ) Depreciation and amortization $ 111.2 $ — $ 45.7 $ 31.4 $ 11.5 $ 22.5 $ 0.1 Capital expenditures (including the effects of accruals) $ 161.8 $ — $ 31.0 $ 27.8 $ 25.1 $ 77.3 $ 0.6 As of December 31, 2018 Total assets $ 12,368.3 $ (144.3 ) $ 4,020.6 $ 3,287.5 $ 1,504.9 $ 3,424.8 $ 274.8 Short-term borrowings $ 676.3 $ — $ 368.5 $ 1.8 $ 10.0 $ 296.0 $ — Goodwill $ 3,154.8 $ — $ 2,003.0 $ 951.9 $ 17.8 $ 182.1 $ — Three Months Ended December 31, 2017 Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 2,125.2 $ — $ 787.3 $ 784.2 $ 249.8 $ 305.4 $ (1.5 ) Intersegment revenues $ — $ (97.1 ) (c) $ — $ — $ 78.2 $ 17.7 $ 1.2 Cost of sales $ 1,137.4 $ (96.0 ) (c) $ 366.1 $ 484.8 $ 239.0 $ 151.8 $ (8.3 ) Segment profit: Operating income (e) $ 395.0 $ 0.2 $ 147.9 $ 93.2 $ 53.4 $ 96.9 $ 3.4 Income (loss) from equity investees 1.0 — — (0.2 ) 1.2 (d) — — Other non-operating expense, net (e) (8.0 ) — — (4.8 ) (1.1 ) (0.6 ) (1.5 ) Interest expense (58.2 ) — (40.6 ) (5.6 ) (0.9 ) (10.9 ) (0.2 ) Income before income taxes $ 329.8 $ 0.2 $ 107.3 $ 82.6 $ 52.6 $ 85.4 $ 1.7 Partnership Adjusted EBITDA (a) $ 194.1 Noncontrolling interests’ net income (loss) $ 68.3 $ — $ 68.0 $ (0.3 ) $ — $ — $ 0.6 Depreciation and amortization $ 110.3 $ — $ 47.4 $ 32.2 $ 10.1 $ 20.4 $ 0.2 Capital expenditures (including the effects of accruals) $ 128.5 $ — $ 23.6 $ 21.7 $ 11.3 $ 71.7 $ 0.2 As of December 31, 2017 Total assets $ 12,343.9 $ (62.6 ) $ 4,206.2 $ 3,450.1 $ 1,325.1 $ 3,174.7 $ 250.4 Short-term borrowings $ 586.1 $ — $ 263.5 $ 41.1 $ 100.0 $ 181.5 $ — Goodwill $ 3,185.5 $ — $ 2,001.3 $ 990.6 $ 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 2018 2017 Partnership Adjusted EBITDA $ 210.7 $ 194.1 Depreciation and amortization (45.7 ) (47.4 ) Interest expense (42.4 ) (40.6 ) Noncontrolling interest (i) 1.6 1.2 Income before income taxes $ 124.2 $ 107.3 (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 $(165.9) and $6.6 during the three months ended December 31, 2018 and 2017 , respectively. (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) Represents AFUDC associated with our PennEast Pipeline equity investment. (e) Amounts reflect the reclassification of non-service income (expense) associated with our pension and other postretirement plans from “Operating and administrative expenses” to “Other non-operating income (expense), net,” on the Condensed Consolidated Statements of Income as a result of the adoption of ASU No. 2017-07 (see Note 3).
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 2018 2017 Partnership Adjusted EBITDA $ 210.7 $ 194.1 Depreciation and amortization (45.7 ) (47.4 ) Interest expense (42.4 ) (40.6 ) Noncontrolling interest (i) 1.6 1.2 Income before income taxes $ 124.2 $ 107.3 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

Nature of Operations (Details)

Nature of Operations (Details) $ in Millions	3 Months Ended
	Dec. 31, 2018USD ($)county	Dec. 31, 2017USD ($)
Investment [Line Items]
General Partner incentive distribution | $	$ 11.3	$ 11.3
Number of counties of operation | county	1
AmeriGas Propane | AmeriGas Partners
Investment [Line Items]
General Partner held a general partner interest in AmeriGas Partners (percentage)	1.00%
Percentage of limited partnership interest in AmeriGas Partners (percentage)	25.30%
General public as limited partner interests in AmeriGas Partners (percentage)	73.70%
AmeriGas Propane | AmeriGas OLP
Investment [Line Items]
Effective ownership interest in AmeriGas OLP (percentage)	27.00%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Oct. 01, 2018	Sep. 30, 2018	Sep. 30, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenue recognition, new accounting pronouncement, timing	less than one year
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of change in accounting for employee share-based payments				$ (7.1)	$ 0
Retained Earnings | Accounting Standards Update 2014-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of change in accounting for employee share-based payments			$ (7.1)
Previously Reported
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase (decrease) in restricted cash		$ (9.5)

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Schedule of Cash and Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017
Accounting Policies [Abstract]
Cash and cash equivalents	$ 477.6	$ 452.6	$ 446.4	$ 558.4
Restricted cash	17.4	9.6	19.8	10.3
Cash, cash equivalents and restricted cash	$ 495	$ 462.2	$ 466.2	$ 568.7

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Denominator:
Weighted-average common shares outstanding - basic (in shares)	174,413	173,670
Incremental shares issuable for stock options and awards (in shares)	3,153	3,278
Weighted-average common shares outstanding - diluted (in shares)	177,566	176,948
Antidilutive shares excluded from calculation of earnings per share (in USD per share)	30	146

Accounting Changes Accounting C

Accounting Changes Accounting Changes - Narrative (Details) - USD ($) $ in Millions	Oct. 01, 2018	Dec. 31, 2018	Dec. 31, 2017	Sep. 30, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Tax Cuts and Jobs Act of 2017, reclassification from AOCI to retained earnings, tax effect		$ (6.6)
Stockholders' equity, including portion attributable to noncontrolling interest		4,046.6	$ 4,082.1	$ 4,100
Accounting Standards Update 2018-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Tax Cuts and Jobs Act of 2017, reclassification from AOCI to retained earnings, tax effect	$ 6.6
Accounting Standards Update 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net periodic defined benefits expense (reversal of expense), excluding service cost component		$ 0.1	$ (3.2)

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Oct. 01, 2018
Disaggregation of Revenue [Line Items]
Contract with customer, liability, current	$ 94	$ 115.6
Contract with customer, liability, revenue recognized	$ 58.1
Natural Gas Transportation And Gathering Services
Disaggregation of Revenue [Line Items]
Term of contract with customer	30 years
Storage Services
Disaggregation of Revenue [Line Items]
Term of contract with customer	1 year
Natural Gas
Disaggregation of Revenue [Line Items]
Term of contract with customer	15 years
Midstream and Marketing
Disaggregation of Revenue [Line Items]
Revenue, remaining performance obligation	$ 1,500
UGI Utilities
Disaggregation of Revenue [Line Items]
Revenue, remaining performance obligation	$ 200

Revenue from Contracts with C_4

Revenue from Contracts with Customers Revenue From Contracts with Customers - Disaggregation (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	May 17, 2018
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 2,175.2
Other revenue	25
Revenues	2,200.2	$ 2,125.2
Negative surcharge			$ (4.1)
Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	175.7
Commercial & Industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	67.6
Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	39.5
Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	15.2
Other (b)
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0.5
Total Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	298.5
Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,229.7
Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	60
Energy Marketing
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	468.9
Pipeline
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	19.4
Peaking
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2
Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1
Electricity Generation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	11.7
Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	84
Total Non-Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,876.7
Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(110.5)
Other revenue	(1.1)
Revenues	(111.6)	(97.1)
Eliminations | Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Eliminations | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Eliminations | Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Eliminations | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(22.9)
Eliminations | Other (b)
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(0.7)
Eliminations | Total Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(23.6)
Eliminations | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Eliminations | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Eliminations | Energy Marketing
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(47.5)
Eliminations | Pipeline
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Eliminations | Peaking
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(38.7)
Eliminations | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Eliminations | Electricity Generation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Eliminations | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(0.7)
Eliminations | Total Non-Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	(86.9)
Eliminations | AmeriGas Propane
Disaggregation of Revenue [Line Items]
Revenues	0	0
Eliminations | UGI International
Disaggregation of Revenue [Line Items]
Revenues	0	0
Eliminations | Midstream and Marketing
Disaggregation of Revenue [Line Items]
Revenues	86.9	78.2
Eliminations | UGI Utilities
Disaggregation of Revenue [Line Items]
Revenues	23.6	17.7
Operating Segments | AmeriGas Propane
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	803.5
Other revenue	16.7
Revenues	820.2	787.3
Operating Segments | AmeriGas Propane | Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | AmeriGas Propane | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | AmeriGas Propane | Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | AmeriGas Propane | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | AmeriGas Propane | Other (b)
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | AmeriGas Propane | Total Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | AmeriGas Propane | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	721.9
Operating Segments | AmeriGas Propane | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	21
Operating Segments | AmeriGas Propane | Energy Marketing
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | AmeriGas Propane | Pipeline
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | AmeriGas Propane | Peaking
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | AmeriGas Propane | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | AmeriGas Propane | Electricity Generation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | AmeriGas Propane | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	60.6
Operating Segments | AmeriGas Propane | Total Non-Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	803.5
Operating Segments | UGI International
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	702.3
Other revenue	8.4
Revenues	710.7	784.2
Operating Segments | UGI International | Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI International | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI International | Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI International | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI International | Other (b)
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI International | Total Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI International | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	507.8
Operating Segments | UGI International | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	39
Operating Segments | UGI International | Energy Marketing
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	143.1
Operating Segments | UGI International | Pipeline
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI International | Peaking
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI International | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI International | Electricity Generation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI International | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	12.4
Operating Segments | UGI International | Total Non-Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	702.3
Operating Segments | Midstream and Marketing
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	457.8
Other revenue	1.6
Revenues	459.4	249.8
Operating Segments | Midstream and Marketing | Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | Midstream and Marketing | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | Midstream and Marketing | Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | Midstream and Marketing | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | Midstream and Marketing | Other (b)
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | Midstream and Marketing | Total Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | Midstream and Marketing | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | Midstream and Marketing | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | Midstream and Marketing | Energy Marketing
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	373.3
Operating Segments | Midstream and Marketing | Pipeline
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	19.4
Operating Segments | Midstream and Marketing | Peaking
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	40.7
Operating Segments | Midstream and Marketing | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1
Operating Segments | Midstream and Marketing | Electricity Generation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	11.7
Operating Segments | Midstream and Marketing | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	11.7
Operating Segments | Midstream and Marketing | Total Non-Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	457.8
Operating Segments | UGI Utilities
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	322.1
Other revenue	0.6
Revenues	322.7	305.4
Operating Segments | UGI Utilities | Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	175.7
Operating Segments | UGI Utilities | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	67.6
Operating Segments | UGI Utilities | Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	39.5
Operating Segments | UGI Utilities | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	38.1
Operating Segments | UGI Utilities | Other (b)
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1.2
Operating Segments | UGI Utilities | Total Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	322.1
Operating Segments | UGI Utilities | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI Utilities | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI Utilities | Energy Marketing
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI Utilities | Pipeline
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI Utilities | Peaking
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI Utilities | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI Utilities | Electricity Generation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI Utilities | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Operating Segments | UGI Utilities | Total Non-Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Other revenue	(1.2)
Revenues	(1.2)	$ (1.5)
Corporate & Other | Residential
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Large delivery service
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Other (b)
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Total Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Energy Marketing
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Pipeline
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Peaking
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Electricity Generation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Corporate & Other | Total Non-Utility
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 0

Inventories - Components of Inv

Inventories - Components of Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Inventory
Total inventories	$ 293.7	$ 318.2	$ 307.3
Non-utility LPG and natural gas
Inventory
Total inventories	206.7	231.7	216.4
Gas Utility natural gas
Inventory
Total inventories	34.9	37.3	34.6
Materials, supplies and other
Inventory
Total inventories	$ 52.1	$ 49.2	$ 56.3

Inventories - Narrative (Detail

Inventories - Narrative (Details) - UGI Utilities $ in Millions	3 Months Ended
	Dec. 31, 2018USD ($)storage_agreementBcf	Sep. 30, 2018USD ($)Bcf	Dec. 31, 2017USD ($)Bcf
Inventory
Number of storage agreements | storage_agreement	5
Volume of gas storage inventories released under SCAAs with non-affiliates (in bcf) | Bcf	1.9	2.3	1.8
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $	$ 4.6	$ 5.4	$ 5.1
Maximum
Inventory
SCAA contract term (in years)	3 years

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Sep. 30, 2018
Operating Loss Carryforwards [Line Items]
Tax Cuts And Jobs Act of 2017, provisional income tax expense (benefit)		$ (166)
Tax Cuts And Jobs Act of 2017, incomplete accounting, change in tax rate, deferred tax liability, provisional income tax (expense) benefit		180.3
Tax Cuts And Jobs Act of 2017, incomplete accounting, change in tax rate, deferred tax asset, provisional income tax expense (benefit)		12.6
Tax Cuts And Jobs Act of 2017, incomplete accounting, transition tax for accumulated foreign earnings, provisional income tax expense (benefit)		$ 1.7
Effective income tax rate reconciliation, blended federal rate	(21.00%)	(24.50%)	(24.50%)
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)		$ 3.9
Foreign Tax Authority | French Parliament | January 1, 2022 (Fiscal 2023)
Operating Loss Carryforwards [Line Items]
Income tax benefit, continuing operations, adjustment of deferred taxes		$ 17.3

Goodwill and Intangible Asset_2

Goodwill and Intangible Assets - Components of Company's Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill (not subject to amortization)	$ 3,154.8	$ 3,160.4	$ 3,185.5
Intangible assets:
Customer relationships, noncompete agreements and other	853	848.6	862
Trademarks and tradenames	7.9	7.9	0
Accumulated amortization	(405.4)	(393.2)	(355)
Intangible assets, net (definite-lived)	455.5	463.3	507
Trademarks and tradenames (indefinite-lived)	49.7	50.3	134.9
Total intangible assets, net	$ 505.2	$ 513.6	$ 641.9

Goodwill and Intangible Asset_3

Goodwill and Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense of intangible assets	$ 14.6	$ 14.8
Remainder of Fiscal 2019	43.4
Fiscal 2,020	56.7
Fiscal 2,021	53.4
Fiscal 2,022	50.4
Fiscal 2,023	$ 48.9

Utility Regulatory Assets and_3

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	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Regulatory Assets
Regulatory assets	$ 298.8	$ 301	$ 362.8
Regulatory Liabilities
Regulatory liabilities	373.5	390.2	357.5
Postretirement benefits
Regulatory Liabilities
Regulatory liabilities	17.3	17.8	17.3
Deferred fuel and power refunds
Regulatory Liabilities
Regulatory liabilities	22.2	36.7	12.7
State tax benefits — distribution system repairs
Regulatory Liabilities
Regulatory liabilities	23.5	22.6	19.1
PAPUC temporary rates order
Regulatory Liabilities
Regulatory liabilities	24.8	24.4	0
Excess federal deferred income taxes
Regulatory Liabilities
Regulatory liabilities	280.9	285.2	303.9
Other
Regulatory Liabilities
Regulatory liabilities	4.8	3.5	4.5
Income taxes recoverable
Regulatory Assets
Regulatory assets	115.2	110.1	126.5
Underfunded pension and postretirement plans
Regulatory Assets
Regulatory assets	85.3	87.1	138.3
Environmental costs
Regulatory Assets
Regulatory assets	58.5	58.8	60.8
Removal costs, net
Regulatory Assets
Regulatory assets	31.3	32	31.4
Other
Regulatory Assets
Regulatory assets	$ 8.5	$ 13	$ 5.8

Utility Regulatory Assets and_4

Utility Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) - USD ($) $ in Millions

Jan. 28, 2019

Dec. 31, 2018

Oct. 27, 2018

Oct. 25, 2018

May 17, 2018

Jan. 26, 2018

Oct. 20, 2017

Jul. 02, 2017

Jan. 19, 2017

Jun. 30, 2018

Sep. 30, 2018

Dec. 31, 2017

UGI South

Regulatory Assets

PUC temporary rates order, percent of reduction in base rate revenues

5.78%

UGI Utilities

Regulatory Assets

Public utilities, civil penalties

$ 2.1

UGI North

Regulatory Assets

PUC temporary rates order, percent of reduction in base rate revenues

3.90%

UGI Central

Regulatory Assets

PUC temporary rates order, percent of reduction in base rate revenues

8.19%

Pennsylvania Public Utility Commission | UGI Gas

Regulatory Assets

Public utilities, tax benefits received

$ 26.2

Pennsylvania Public Utility Commission | Electric Utility

Regulatory Assets

Public utilities, requested rate increase (decrease), amount

$ 7.7

$ 3.2

Public utilities, requested increase in annual base distribution revenues

$ 9.2

Public utilities, customer billing credit

$ 0.2

Pennsylvania Public Utility Commission | PNG

Regulatory Assets

Public utilities, requested rate increase (decrease), amount

$ 21.7

Public utilities, approved rate increase (decrease), amount

$ 11.3

Gas Utility

Regulatory Assets

Fair value of unrealized gains (losses)

$ 0.8

$ 2.9

$ (1.7)

Subsequent Event | Pennsylvania Public Utility Commission | UGI Gas

Regulatory Assets

Public utilities, requested rate increase (decrease), amount

$ 71.1

Public utilities, proposed negative surcharge in customer distribution service bills

4.50%

Minimum

Regulatory Assets

Average remaining depreciable lives of associated property

1 year

Maximum

Regulatory Assets

Average remaining depreciable lives of associated property

65 years

Energy Services Accounts Rece_3

Energy Services Accounts Receivable Securitization Facility - Narrative (Details) - Maximum - USD ($)	6 Months Ended	18 Months Ended
	Apr. 30, 2018	Oct. 31, 2019
Accounts, Notes, Loans and Financing Receivable
Receivables facility	$ 150,000,000
Scenario, Forecast
Accounts, Notes, Loans and Financing Receivable
Receivables facility		$ 75,000,000

Energy Services Accounts Rece_4

Energy Services Accounts Receivable Securitization Facility - Trade Receivables Transferred and Sold (Details) - ESFC - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Sep. 30, 2018
Accounts, Notes, Loans and Financing Receivable
Trade receivables transferred to ESFC during the period	$ 392.6	$ 270.6
ESFC trade receivables sold to the bank during the period	25	48
ESFC trade receivables - end of period	135.4	101	$ 65
Outstanding balance of trade receivables sold	$ 10	$ 45	$ 2

Debt - Narrative (Details)

Debt - Narrative (Details)	Oct. 25, 2018EUR (€)	Oct. 25, 2018USD ($)	Oct. 18, 2018EUR (€)	Feb. 01, 2019USD ($)	Nov. 30, 2018
UGI International Credit Agreement
Debt Instrument [Line Items]
Debt instrument, covenant, total indebtedness to EBITDA ratio, maximum			3.85
UGI International LLC | Senior Notes | 3.25% Senior Unsecured Notes Due November 2025
Debt Instrument [Line Items]
Stated interest rate	3.25%
Debt instrument, face amount	€ 350,000,000
UGI France
Debt Instrument [Line Items]
Repayment of debt	540,000,000
Flaga
Debt Instrument [Line Items]
Repayment of debt	45,800,000
Flaga | Term Loan | Flaga Term Loan Due September 2020
Debt Instrument [Line Items]
Repayment of debt | $		$ 49,900,000
France SAS
Debt Instrument [Line Items]
Long-term debt	€ 60,000,000
UGI Utilities | Senior Notes | 4.55% Senior Notes due February 2049 | Subsequent Event
Debt Instrument [Line Items]
Stated interest rate				4.55%
Debt instrument, face amount | $				$ 150,000,000
Debt instrument, covenant, consolidated debt to consolidated total capital				0.65
Minimum | UGI International LLC | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate			1.55%
Maximum | UGI International LLC | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate			3.20%
Term Loan | UGI International LLC | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Debt instrument, term (in years)			5 years
Long-term debt			€ 300,000,000
Revolving Credit Facility | UGI International LLC | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity			€ 300,000,000
EURIBOR | Revolving Credit Facility | UGI International LLC | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate			1.70%
Derivative, fixed interest rate			0.34%		0.34%
EURIBOR | Revolving Credit Facility | Minimum | UGI International LLC | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate			1.20%
EURIBOR | Revolving Credit Facility | Maximum | UGI International LLC | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate			2.85%
London Interbank Offered Rate (LIBOR) | Revolving Credit Facility | Minimum | UGI International LLC | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate			1.45%
London Interbank Offered Rate (LIBOR) | Revolving Credit Facility | Maximum | UGI International LLC | Line of Credit | UGI International Credit Agreement
Debt Instrument [Line Items]
Basis spread on variable rate			3.10%

Commitments and Contingencies (

Commitments and Contingencies (Details)	Nov. 07, 2017	Dec. 31, 2018USD ($)subsidiarylb	Dec. 31, 2017USD ($)record_of_decision	Jul. 01, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)
Loss Contingencies
Capital contributions		$ 0
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		$ 5,400,000
CPG, PNG and UGI Gas COAs
Loss Contingencies
Accrual for environmental loss contingencies		$ 50,500,000	$ 53,400,000		$ 51,000,000
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
Loss contingency, number of remediation plans | record_of_decision			3
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 O_3

Defined Benefit Pension and Other Postretirement Plans - Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 2.5	$ 2.8
Interest cost	6.8	6.5
Expected return on assets	(9)	(8.6)
Amortization of:
Prior service cost (benefit)	0.1	0.1
Actuarial loss	1.9	3.3
Net benefit cost	2.3	4.1
Change in associated regulatory liabilities	0	0
Net benefit cost after change in regulatory liabilities	2.3	4.1
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	0	0.2
Interest cost	0.2	0.2
Expected return on assets	(0.2)	(0.2)
Amortization of:
Prior service cost (benefit)	(0.1)	(0.1)
Actuarial loss	0	0.1
Net benefit cost	(0.1)	0.2
Change in associated regulatory liabilities	(0.3)	(0.1)
Net benefit cost after change in regulatory liabilities	$ (0.4)	$ 0.1

Defined Benefit Pension and O_4

Defined Benefit Pension and Other Postretirement Plans - Narrative (Details) - USD ($)	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans
Contribution made to pension and post-retirement plans	$ 0	$ 3,400,000
Expected contribution to pension plan during remainder of fiscal year	11,500,000
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans
Contribution made to pension and post-retirement plans	0	0
Defined benefit plan, net periodic benefit cost (credit)	(100,000)	200,000
Unfunded Plan | Nonqualified Plan
Defined Benefit Plans and Other Postretirement Benefit Plans
Defined benefit plan, net periodic benefit cost (credit)	$ 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	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	$ 124.4	$ 232.5	$ 131.2
Derivative financial instruments, liabilities	(126.1)	(58.8)	(87.4)
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	38	40.8	37.7
Fair Value, Measurements, Recurring | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	100	211	119.6
Derivative financial instruments, liabilities	(113.6)	(43.4)	(44.5)
Fair Value, Measurements, Recurring | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	24.4	20.6	11.6
Derivative financial instruments, liabilities	(8.8)	(14.4)	(39.9)
Fair Value, Measurements, Recurring | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, liabilities	(3.7)	(1)	(2.1)
Fair Value, Measurements, Recurring | Cross-currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0.9
Derivative financial instruments, liabilities			(0.9)
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	38	40.8	37.7
Fair Value, Measurements, Recurring | Level 1 | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	72.1	93.5	47.9
Derivative financial instruments, liabilities	(35.6)	(33.6)	(31)
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
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	27.9	117.5	71.7
Derivative financial instruments, liabilities	(78)	(9.8)	(13.5)
Fair Value, Measurements, Recurring | Level 2 | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	24.4	20.6	11.6
Derivative financial instruments, liabilities	(8.8)	(14.4)	(39.9)
Fair Value, Measurements, Recurring | Level 2 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, liabilities	(3.7)	(1)	(2.1)
Fair Value, Measurements, Recurring | Level 2 | Cross-currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0.9
Derivative financial instruments, liabilities			(0.9)
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

Fair Value Measurements - (Deta

Fair Value Measurements - (Details) - USD ($) $ in Millions	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Carrying amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 4,211	$ 4,199.4	$ 4,319.5
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 3,970.8	$ 4,150.3	$ 4,430

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Narrative (Details) - USD ($)	Dec. 31, 2018	Nov. 30, 2018	Oct. 25, 2018	Oct. 18, 2018	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 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	1,400,000
Restricted cash	17,400,000				$ 9,600,000	$ 19,800,000	$ 10,300,000
Interest Rate Protection Agreements
Derivative [Line Items]
Notional amount	$ 0				$ 0	$ 0
UGI International LLC | 3.25% Senior Unsecured Notes Due November 2025 | Senior Notes
Derivative [Line Items]
Stated interest rate			3.25%
UGI International LLC | EURIBOR | UGI International Credit Agreement | Revolving Credit Facility | Line of Credit
Derivative [Line Items]
Derivative, fixed interest rate		0.34%		0.34%
Maximum | UGI Utilities | Unsecured Debt
Derivative [Line Items]
Derivative, fixed interest rate	3.00%

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities - Schedule of Notional Amounts (Details) € in Millions, kWh in Millions, gal in Millions, DTH in Millions, $ in Millions	Dec. 31, 2018EUR (€)DTHkWhgal	Dec. 31, 2018USD ($)DTHkWhgal	Sep. 30, 2018EUR (€)DTHkWhgal	Sep. 30, 2018USD ($)DTHkWhgal	Dec. 31, 2017EUR (€)DTHkWhgal	Dec. 31, 2017USD ($)DTHkWhgal
Commodity contracts | Electricity | Long
Derivative [Line Items]
Notional amount (in units) | kWh	3,974.7	3,974.7	4,307.6	4,307.6	4,733.9	4,733.9
Commodity contracts | Electricity | Short
Derivative [Line Items]
Notional amount (in units) | kWh	366.7	366.7	359.3	359.3	325.2	325.2
Commodity contracts | Propane
Derivative [Line Items]
Notional amount (in units) | gal	450.4	450.4	394.3	394.3	275.4	275.4
Natural gas futures, forward and pipeline contracts (in dekatherms) | Natural Gas
Derivative [Line Items]
Notional amount (in units)	188	188	159.7	159.7	128.3	128.3
Natural gas basis swap contracts (in dekatherms) | Natural Gas
Derivative [Line Items]
Notional amount (in units)	81.2	81.2	54.4	54.4	90.2	90.2
NYMEX natural gas storage (in dekatherms) | Natural Gas
Derivative [Line Items]
Notional amount (in units)	0.7	0.7	1.8	1.8	1.3	1.3
NYMEX propane storage (in gallons) | Propane
Derivative [Line Items]
Notional amount (in units) | gal	0.3	0.3	0.6	0.6	0.1	0.1
Interest rate swaps
Derivative [Line Items]
Notional amount	€ 300	$ 114.1	€ 585.8	$ 114.1	€ 645.8	$ 0
Forward foreign currency exchange contracts
Derivative [Line Items]
Notional amount	€ 172.8	408.6	€ 0	512.2	€ 0	485.7
Cross-currency contracts
Derivative [Line Items]
Notional amount | $		$ 0		$ 49.9		$ 49.9
Regulated Utility Operations | Commodity contracts | Natural Gas
Derivative [Line Items]
Notional amount (in units)	14.7	14.7	23.2	23.2	13.4	13.4
Regulated Utility Operations | FTRs (in kilowatts) | Electricity
Derivative [Line Items]
Notional amount (in units) | kWh	0	0	0	0	63.1	63.1

Derivative Instruments and He_5

Derivative Instruments and Hedging Activities - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Derivative assets:
Total derivative assets — gross	$ 124.4	$ 232.5	$ 131.2
Gross amounts offset in the balance sheet	(34.3)	(34.3)	(32.5)
Cash collateral received	0	(12.2)	(12)
Total derivative assets — net	90.1	186	86.7
Derivative liabilities:
Total derivative liabilities — gross	(126.1)	(58.8)	(87.4)
Gross amounts offset in the balance sheet	34.3	34.3	32.5
Cash collateral pledged	10	0	0
Total derivative liabilities — net	(81.8)	(24.5)	(54.9)
Derivatives designated as hedging instruments
Derivative assets:
Total derivative assets — gross	2.3	2.4	1.2
Derivative liabilities:
Total derivative liabilities — gross	(3.7)	(1.4)	(8.6)
Derivatives designated as hedging instruments | Foreign currency contracts
Derivative assets:
Total derivative assets — gross	2.3	1.5	1.2
Derivative liabilities:
Total derivative liabilities — gross	0	(0.4)	(5.6)
Derivatives designated as hedging instruments | Cross-currency contracts
Derivative assets:
Total derivative assets — gross	0	0.9	0
Derivative liabilities:
Total derivative liabilities — gross	0	0	(0.9)
Derivatives designated as hedging instruments | Interest rate contracts
Derivative liabilities:
Total derivative liabilities — gross	(3.7)	(1)	(2.1)
Derivatives subject to PGC and DS mechanisms | Commodity contracts
Derivative assets:
Total derivative assets — gross	1.3	3	0.4
Derivative liabilities:
Total derivative liabilities — gross	(0.5)	(0.1)	(2.3)
Derivatives not designated as hedging instruments
Derivative assets:
Total derivative assets — gross	120.8	227.1	129.6
Derivative liabilities:
Total derivative liabilities — gross	(121.9)	(57.3)	(76.5)
Derivatives not designated as hedging instruments | Foreign currency contracts
Derivative assets:
Total derivative assets — gross	22.1	19.1	10.4
Derivative liabilities:
Total derivative liabilities — gross	(8.8)	(14)	(34.3)
Derivatives not designated as hedging instruments | Commodity contracts
Derivative assets:
Total derivative assets — gross	98.7	208	119.2
Derivative liabilities:
Total derivative liabilities — gross	$ (113.1)	$ (43.3)	$ (42.2)

Derivative Instruments and He_6

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
	Dec. 31, 2018	Dec. 31, 2017
Derivatives Not Designated as Hedging Instruments
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	$ (154)	$ 18.4
Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	(1.9)	(0.6)
Gain (Loss) Reclassified from AOCI into Income	(1)	0.5
Foreign currency contracts | Derivatives Not Designated as Hedging Instruments | Other non-operating income (expense), net
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	8.9	(4.8)
Foreign currency contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	1	(1.4)
Foreign currency contracts | Cash Flow Hedges | Cost of sales
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	0.8	0.8
Foreign currency contracts | Net Investment Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI, net investment hedge	0.9	0
Cross-currency contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	(0.1)	0.1
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)	0.2
Interest rate contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	(2.8)	0.7
Interest rate contracts | Cash Flow Hedges | Interest expense
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	(1.5)	(0.5)
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Cost of sales
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(159.7)	24.4
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Revenues
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(2.8)	(1.3)
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Operating and administrative expenses
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	$ (0.4)	$ 0.1

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	$ 4,100
Other comprehensive income (loss) before reclassification adjustments (after-tax)	(17.1)	$ 21.9
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	1.4	0.1
Reclassification adjustments tax (benefit) expense	(0.4)	(0.1)
Reclassification adjustments (after-tax)	1	0
Other comprehensive income (loss) attributable to UGI	(16.1)	21.9
Reclassification of stranded income tax effects related to TCJA	(6.6)
Balance, end of period	4,046.6	4,082.1
Postretirement Benefit Plans
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(11)	(19.2)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	0	0
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	0.4	0.6
Reclassification adjustments tax (benefit) expense	(0.1)	(0.2)
Reclassification adjustments (after-tax)	0.3	0.4
Other comprehensive income (loss) attributable to UGI	0.3	0.4
Reclassification of stranded income tax effects related to TCJA	(2.9)
Balance, end of period	(13.6)	(18.8)
Derivative Instruments
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(16.1)	(21.4)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	(1.5)	(0.4)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	1	(0.5)
Reclassification adjustments tax (benefit) expense	(0.3)	0.1
Reclassification adjustments (after-tax)	0.7	(0.4)
Other comprehensive income (loss) attributable to UGI	(0.8)	(0.8)
Reclassification of stranded income tax effects related to TCJA	(3.7)
Balance, end of period	(20.6)	(22.2)
Foreign Currency
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(83.3)	(52.8)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	(15.6)	22.3
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	0	0
Reclassification adjustments tax (benefit) expense	0	0
Reclassification adjustments (after-tax)	0	0
Other comprehensive income (loss) attributable to UGI	(15.6)	22.3
Reclassification of stranded income tax effects related to TCJA	0
Balance, end of period	(98.9)	(30.5)
Total
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(110.4)	(93.4)
Amounts reclassified from AOCI:
Balance, end of period	$ (133.1)	$ (71.5)

Segment Information - Narrative

Segment Information - Narrative (Details)	3 Months Ended
	Dec. 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
	Dec. 31, 2018	Dec. 31, 2017	Sep. 30, 2018
Segment Reporting Information [Line Items]
Revenues	$ 2,200.2	$ 2,125.2
Cost of sales	1,425	1,137.4
Segment profit:
Operating income (loss)	167.7	395
Income from equity investees	1.5	1
Loss on extinguishments of debt	(6.1)	0
Other non-operating income (expense), net	9	(8)
Interest expense	(60.2)	(58.2)
(Loss) income before income taxes	111.9	329.8
Noncontrolling interests’ net loss	24.3	68.3
Depreciation and amortization	111.2	110.3
Capital expenditures (including the effects of accruals)	161.8	128.5
Total assets	12,368.3	12,343.9	$ 11,980.9
Short-term borrowings	676.3	586.1	424.9
Goodwill	3,154.8	3,185.5	$ 3,160.4
Eliminations
Segment Reporting Information [Line Items]
Revenues	(111.6)	(97.1)
Cost of sales	(110.8)	(96)
Segment profit:
Operating income (loss)	0.4	0.2
Income from equity investees	0	0
Loss on extinguishments of debt	0
Other non-operating income (expense), net	0	0
Interest expense	0	0
(Loss) income before income taxes	0.4	0.2
Noncontrolling interests’ net loss	0	0
Depreciation and amortization	0	0
Capital expenditures (including the effects of accruals)	0	0
Total assets	(144.3)	(62.6)
Short-term borrowings	0	0
Goodwill	0	0
Eliminations | AmeriGas Propane
Segment Reporting Information [Line Items]
Revenues	0	0
Eliminations | UGI International
Segment Reporting Information [Line Items]
Revenues	0	0
Eliminations | Midstream & Marketing
Segment Reporting Information [Line Items]
Revenues	86.9	78.2
Eliminations | UGI Utilities
Segment Reporting Information [Line Items]
Revenues	23.6	17.7
Corporate, Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Revenues	1.1	1.2
Operating Segments | AmeriGas Propane
Segment Reporting Information [Line Items]
Revenues	820.2	787.3
Cost of sales	378.5	366.1
Segment profit:
Operating income (loss)	166.6	147.9
Income from equity investees	0	0
Loss on extinguishments of debt	0
Other non-operating income (expense), net	0	0
Interest expense	(42.4)	(40.6)
(Loss) income before income taxes	124.2	107.3
Partnership Adjusted EBITDA	210.7	194.1
Noncontrolling interests’ net loss	81.5	68
Depreciation and amortization	45.7	47.4
Capital expenditures (including the effects of accruals)	31	23.6
Total assets	4,020.6	4,206.2
Short-term borrowings	368.5	263.5
Goodwill	2,003	2,001.3
Operating Segments | UGI International
Segment Reporting Information [Line Items]
Revenues	710.7	784.2
Cost of sales	448.6	484.8
Segment profit:
Operating income (loss)	58.3	93.2
Income from equity investees	0	(0.2)
Loss on extinguishments of debt	(6.1)
Other non-operating income (expense), net	0.7	(4.8)
Interest expense	(5.4)	(5.6)
(Loss) income before income taxes	47.5	82.6
Noncontrolling interests’ net loss	0.1	(0.3)
Depreciation and amortization	31.4	32.2
Capital expenditures (including the effects of accruals)	27.8	21.7
Total assets	3,287.5	3,450.1
Short-term borrowings	1.8	41.1
Goodwill	951.9	990.6
Operating Segments | Midstream & Marketing
Segment Reporting Information [Line Items]
Revenues	459.4	249.8
Revenues, before intersegment effect	372.5
Cost of sales	377.5	239
Segment profit:
Operating income (loss)	41.1	53.4
Income from equity investees	1.5	1.2
Loss on extinguishments of debt	0
Other non-operating income (expense), net	0	(1.1)
Interest expense	(0.5)	(0.9)
(Loss) income before income taxes	42.1	52.6
Noncontrolling interests’ net loss	0	0
Depreciation and amortization	11.5	10.1
Capital expenditures (including the effects of accruals)	25.1	11.3
Total assets	1,504.9	1,325.1
Short-term borrowings	10	100
Goodwill	17.8	11.5
Operating Segments | UGI Utilities
Segment Reporting Information [Line Items]
Revenues	322.7	305.4
Revenues, before intersegment effect	299.1
Cost of sales	159.5	151.8
Segment profit:
Operating income (loss)	77	96.9
Income from equity investees	0	0
Loss on extinguishments of debt	0
Other non-operating income (expense), net	0.4	(0.6)
Interest expense	(11.7)	(10.9)
(Loss) income before income taxes	65.7	85.4
Noncontrolling interests’ net loss	0	0
Depreciation and amortization	22.5	20.4
Capital expenditures (including the effects of accruals)	77.3	71.7
Total assets	3,424.8	3,174.7
Short-term borrowings	296	181.5
Goodwill	182.1	182.1
Corporate & Other
Segment Reporting Information [Line Items]
Revenues	(1.2)	(1.5)
Revenues, before intersegment effect	(2.3)
Cost of sales	171.7	(8.3)
Segment profit:
Operating income (loss)	(175.7)	3.4
Income from equity investees	0	0
Loss on extinguishments of debt	0
Other non-operating income (expense), net	7.9	(1.5)
Interest expense	(0.2)	(0.2)
(Loss) income before income taxes	(168)	1.7
Noncontrolling interests’ net loss	(57.3)	0.6
Depreciation and amortization	0.1	0.2
Capital expenditures (including the effects of accruals)	0.6	0.2
Total assets	274.8	250.4
Short-term borrowings	0	0
Goodwill	$ 0	$ 0

Segment Information - Reconcili

Segment Information - Reconciliation of Partnership Adjusted EBITDA (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Depreciation and amortization	$ (111.2)	$ (110.3)
Interest expense	(60.2)	(58.2)
(Loss) income before income taxes	$ 111.9	329.8
AmeriGas Propane | AmeriGas OLP
Segment Reporting Information [Line Items]
General partnership interest (percentage)	1.01%
Operating Segments | AmeriGas Propane
Segment Reporting Information [Line Items]
Partnership Adjusted EBITDA	$ 210.7	194.1
Depreciation and amortization	(45.7)	(47.4)
Interest expense	(42.4)	(40.6)
Noncontrolling interest	1.6	1.2
(Loss) income before income taxes	124.2	107.3
Corporate & Other
Segment Reporting Information [Line Items]
Depreciation and amortization	(0.1)	(0.2)
Interest expense	(0.2)	(0.2)
(Loss) income before income taxes	(168)	1.7
Gains (losses) on unsettled commodity derivative instruments, net	$ (165.9)	$ 6.6