UGI (UGI) 10-Q 6 Feb 20 2020 Q1 Quarterly report Financial data

Cover Page

Cover Page - shares	3 Months Ended
	Dec. 31, 2019	Jan. 31, 2020
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-11071
Entity Registrant Name	UGI CORPORATION
Entity Incorporation, State or Country Code	PA
Entity Tax Identification Number	23-2668356
Entity Address, Address Line One	460 North Gulph Road
Entity Address, City or Town	King of Prussia
Entity Address, State or Province	PA
Entity Address, Postal Zip Code	19406
City Area Code	610
Local Phone Number	337-1000
Title of 12(b) Security	Common Stock, without par value
Trading Symbol	UGI
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		208,548,324
Entity Central Index Key	0000884614
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--09-30

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 333.4	$ 447.1	$ 477.6
Restricted cash	95.8	63.7	17.4
Accounts receivable (less allowances for doubtful accounts of $35.6, $31.6 and $38.5, respectively)	1,011.1	640.7	1,144.3
Accrued utility revenues	80.2	14.6	64.7
Inventories	247.5	229.9	293.7
Utility regulatory assets	4.7	9.1	3.3
Derivative instruments	28.4	28.9	60.2
Prepaid expenses and other current assets	145.9	132.2	181
Total current assets	1,947	1,566.2	2,242.2
Property, plant and equipment, at cost (less accumulated depreciation of $3,490.1, $3,385.2 and $3,228.3, respectively)	6,783.6	6,687.8	5,855.1
Goodwill	3,482.9	3,456.4	3,154.8
Intangible assets, net	703.4	708.6	505.2
Utility regulatory assets	385.8	386.5	295.5
Derivative instruments	32	43.2	29.9
Other assets	951	497.9	285.6
Total assets	14,285.7	13,346.6	12,368.3
Current liabilities:
Current maturities of long-term debt	27.8	24.1	19.5
Short-term borrowings	869.7	796.3	676.3
Accounts payable	598.3	438.8	753.3
Derivative instruments	113.3	84.9	56.8
Other current liabilities	782.4	682.8	677.2
Total current liabilities	2,391.5	2,026.9	2,183.1
Long-term debt	5,827.6	5,779.9	4,150.7
Deferred income taxes	562.5	541.4	973.4
Derivative instruments	46.6	48.4	25
Other noncurrent liabilities	1,452.9	1,122.8	989.5
Total liabilities	10,281.1	9,519.4	8,321.7
Commitments and contingencies (Note 10)
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 209,310,342, 209,304,129 and 174,262,763 shares, respectively)	1,398.4	1,396.9	1,206.5
Retained earnings	2,797.5	2,653.1	2,620.8
Accumulated other comprehensive loss	(163.1)	(216.6)	(133.1)
Treasury stock, at cost	(37.4)	(15.9)	(24.8)
Total UGI Corporation stockholders’ equity	3,995.4	3,817.5	3,669.4
Noncontrolling interests	9.2	9.7	377.2
Total equity	4,004.6	3,827.2	4,046.6
Total liabilities and equity	$ 14,285.7	$ 13,346.6	$ 12,368.3

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 35.6	$ 31.6	$ 38.5
Accumulated depreciation	$ 3,490.1	$ 3,385.2	$ 3,228.3
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)	209,310,342	209,304,129	174,262,763

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Statement [Abstract]
Revenues	$ 2,006.6	$ 2,200.2
Costs and expenses:
Cost of sales (excluding depreciation and amortization shown below)	1,008	1,425
Operating and administrative expenses	511.2	503.2
Depreciation and amortization	119.4	111.2
Other operating income, net	(9.2)	(6.9)
Total cost and expenses	1,629.4	2,032.5
Operating income	377.2	167.7
Income from equity investees	6.5	1.5
Loss on extinguishments of debt	0	(6.1)
Other non-operating (expense) income, net	(11.5)	9
Interest expense	(84.1)	(60.2)
Income before income taxes	288.1	111.9
Income tax expense	(76.1)	(23.4)
Net income including noncontrolling interests	212	88.5
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners	0	(24.3)
Net income attributable to UGI Corporation	$ 212	$ 64.2
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in USD per share)	$ 1.01	$ 0.37
Diluted (in USD per share)	$ 1	$ 0.36
Weighted-average common shares outstanding (thousands):
Basic (in shares)	209,439	174,413
Diluted (in shares)	211,258	177,566

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net income including noncontrolling interests	$ 212	$ 88.5
Other comprehensive income (loss):
Net gains (losses) on derivative instruments (net of tax of $(2.2) and $0.4, respectively)	5.6
Net gains (losses) on derivative instruments (net of tax of $(2.2) and $0.4, respectively)		(1.5)
Reclassifications of net losses on derivative instruments (net of tax of $(0.3) and $(0.3), respectively)	0.7
Reclassifications of net losses on derivative instruments (net of tax of $(0.3) and $(0.3), respectively)		0.7
Foreign currency adjustments (net of tax of $7.2 and $2.8, respectively)	47	(15.6)
Benefit plans (net of tax of $(0.1) and $(0.1), respectively)	0.2	0.3
Other comprehensive income (loss)	53.5	(16.1)
Comprehensive income including noncontrolling interests	265.5	72.4
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	0	(24.3)
Comprehensive income attributable to UGI Corporation	$ 265.5	$ 48.1

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Tax on (loss) gain on derivative instruments	$ (2.2)
Tax on (loss) gain on derivative instruments		$ 0.4
Tax on reclassification on derivative instruments	(0.3)
Tax on reclassification on derivative instruments		(0.3)
Tax on benefit plans	(0.1)	(0.1)
Foreign currency adjustments, tax	$ 7.2	$ 2.8

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income including noncontrolling interests	$ 212	$ 88.5
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization	119.4	111.2
Deferred income tax expense (benefit), net	5	(20.7)
Provision for uncollectible accounts	7.8	10.3
Changes in unrealized gains and losses on derivative instruments	27.3	165.9
Loss on extinguishments of debt	0	6.1
Income from equity investees	(6.5)	(1.5)
Other, net	(9.4)	12.4
Net change in:
Accounts receivable and accrued utility revenues	(431.6)	(457.6)
Inventories	(15.6)	23
Utility deferred fuel and power costs, net of changes in unsettled derivatives	4.8	(12.5)
Accounts payable	182.6	217.4
Derivative instruments collateral deposits received (paid)	20.4	(22.2)
Other current assets	(8)	(11.4)
Other current liabilities	10.2	(12.3)
Net cash provided by operating activities	118.4	96.6
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(182)	(183.3)
Acquisitions of businesses and assets, net of cash and restricted cash acquired	0	(15)
Other, net	6.1	4.3
Net cash used by investing activities	(175.9)	(194)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(67.9)	(45.3)
Distributions on AmeriGas Partners publicly held Common Units	0	(65.7)
Issuances of long-term debt, net of issuance costs	15	728.9
Repayments of long-term debt	(31.1)	(721.1)
Increase in short-term borrowings	51.4	243.4
Receivables Facility net borrowings	22	8
Issuances of UGI Common Stock	0.6	6.9
Repurchases of UGI Common Stock	(22.6)	(16.9)
Other, net	0	(4.2)
Net cash (used) provided by financing activities	(32.6)	134
Effect of exchange rate changes on cash, cash equivalents and restricted cash	8.5	(3.8)
Cash, cash equivalents and restricted cash (decrease) increase	(81.6)	32.8
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Cash, cash equivalents and restricted cash at end of period	429.2	495
Cash, cash equivalents and restricted cash at beginning of period	510.8	462.2
Cash, cash equivalents and restricted cash (decrease) increase	$ (81.6)	$ 32.8

CONDENSED CONSOLIDATED STATEM_5

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Millions	Total	Common stock, without par value	Retained earnings	Accumulated other comprehensive income (loss)	Treasury stock	Total UGI stockholders’ equity	Noncontrolling interests
Increase (Decrease) in Stockholders' Equity
Cumulative effect of change in accounting principle - ASC 606			$ (7.1)
Balance, beginning of period at Sep. 30, 2018		$ 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, net of tax withheld		3.7
Equity-based compensation expense		2
Reclassification of stranded income tax effects related to TCJA	$ (6.6)		6.6	(6.6)
Losses on common stock transactions in connection with employee and director plans			(8.3)
Net income (loss)	88.5		64.2				24.3
Cash dividends on UGI Common Stock ($0.325 and $0.260 per share, respectively)			(45.3)
Net gains (losses) on derivative instruments	(1.5)			(1.5)
Reclassification of net losses 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 UGI Common Stock					(16.9)
Reacquired UGI Common Stock - employee and director plans					(0.4)
Dividends and distributions							(65.7)
Balance, end of period at Dec. 31, 2018	4,046.6	1,206.5	2,620.8	(133.1)	(24.8)	$ 3,669.4	377.2
Balance, beginning of period at Sep. 30, 2019	3,827.2	1,396.9	2,653.1	(216.6)	(15.9)		9.7
Increase (Decrease) in Stockholders' Equity
Common Stock issued in connection with employee and director plans, net of tax withheld		0.3
Equity-based compensation expense		1.9
Losses on common stock transactions in connection with employee and director plans			(0.7)
Net income (loss)	212		212
Cash dividends on UGI Common Stock ($0.325 and $0.260 per share, respectively)			(67.9)
Net gains (losses) on derivative instruments	5.6			5.6
Reclassification of net losses on derivative instruments	0.7			0.7
Benefit plans	0.2			0.2
Foreign currency adjustments	47			47
Common Stock issued in connection with employee and director plans, net of tax withheld					1.1
Repurchases of UGI Common Stock					(22.6)
Other		(0.7)	1				(0.5)
Balance, end of period at Dec. 31, 2019	$ 4,004.6	$ 1,398.4	$ 2,797.5	$ (163.1)	$ (37.4)	$ 3,995.4	$ 9.2

CONDENSED CONSOLIDATED STATEM_6

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of Stockholders' Equity [Abstract]
Common stock, dividends, per share, cash paid (in dollars per share)	$ 0.325	$ 0.260

Nature of Operations

Nature of Operations	3 Months Ended
	Dec. 31, 2019
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 own and operate (1) a retail propane marketing and distribution business; (2) natural gas and electric distribution utilities; and (3) 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 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. On August 21, 2019, we completed the AmeriGas Merger pursuant to which we issued 34,612,847 shares of UGI Common Stock and paid $528.9 in cash to acquire all of the outstanding Common Units in AmeriGas Partners not already held by UGI or its subsidiaries, with the Partnership surviving as a wholly owned subsidiary of UGI. Prior to the AmeriGas Merger, UGI controlled the Partnership through its ownership of the General Partner, which held a 1% general partner interest (which included IDRs) and approximately 25.5% of the outstanding Common Units in AmeriGas Partners, and held an effective 27.0% ownership interest in AmeriGas OLP. The IDRs held by the General Partner prior to the AmeriGas Merger entitled it to receive distributions from AmeriGas Partners in excess of its general partner interest under certain circumstances. Incentive distributions received by the General Partner during the three months ended December 31, 2018 were $11.3 . UGI International, through subsidiaries and affiliates, 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 and processing, natural gas production, electricity generation and energy services businesses primarily in the Mid-Atlantic region of the U.S., eastern Ohio and the panhandle of West Virginia. UGID owns all or a portion of electricity generation facilities principally located in Pennsylvania. Energy Services and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation by the FERC. UGI Utilities directly owns and operates Gas Utility, a natural gas distribution utility business in eastern and central Pennsylvania and in a portion of one Maryland county. 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, 2019
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, 2019 , Condensed Consolidated Balance Sheet was derived from audited financial statements but does not include all footnote disclosures from the annual financial statements. These financial statements should be read in conjunction with the financial statements and related notes included in the Company’s 2019 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. Leases. Effective October 1, 2019, the Company adopted ASU No. 2016-02, "Leases," which, as amended, is included in ASC 842. This new accounting guidance supersedes previous lease accounting guidance in ASC 840 and requires entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on its balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. We adopted this new guidance using the modified retrospective transition method. Amounts and disclosures related to periods prior to October 1, 2019 have not been restated and continue to be reported in accordance with ASC 840. We elected to apply the following practical expedients in accordance with the guidance upon adoption: • Short-term leases: We did not recognize short-term leases (term of 12 months or less) on the balance sheet; • Easements: We did not re-evaluate existing land easements that were not previously accounted for as leases; and • Other: We did not reassess the classification of expired or existing contracts or determine whether they are or contain a lease. We also did not reassess whether initial direct costs qualify for capitalization under ASC 842. Upon adoption, we recorded ROU assets and lease liabilities of $451.9 related to our operating leases. Our accounting for finance leases remained substantially unchanged. There were no cumulative effect adjustments made to opening retained earnings as of October 1, 2019. The adoption did not, and is not expected to, have a significant impact on our condensed consolidated statements of income or cash flows. See Note 9 for additional disclosures regarding our leases. Equity Method Investments. We account for privately held equity securities of entities without readily determinable fair values in which we do not have control, but have significant influence over operating and financial policies, under the equity method. Our equity method investments are primarily comprised of PennEast and Pennant. UGI PennEast, LLC and four other members comprising wholly owned subsidiaries of Southern Company, New Jersey Resources, South Jersey Industries, and Enbridge, Inc., each hold a 20% membership interest in PennEast. In September 2019, a panel of the U.S. Court of Appeals for the Third Circuit ruled that New Jersey’s Eleventh Amendment immunity barred PennEast from bringing an eminent domain lawsuit in federal court, under the Natural Gas Act, against New Jersey or its agencies. The Third Circuit subsequently denied PennEast’s petition for rehearing en banc. In addition, in October 2019, in reliance on the Third Circuit ruling, the New Jersey Department of Environmental Protection rejected PennEast’s application for certain project permits. Following the Third Circuit denial of petition for rehearing, PennEast filed a petition for declaratory order with the FERC regarding interpretation of the Natural Gas Act; the FERC issued an order favorable to PennEast’s position on January 30, 2020. PennEast also expects to file a petition for a writ of certiorari to seek U.S. Supreme Court review of the Third Circuit decision. The ultimate outcome of these matters cannot be determined at this time, and could result in delays, additional costs, or the inability to move forward with the project, resulting in an impairment of all or a portion of our investment in PennEast. Restricted Cash. Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. 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, 2019 December 31, 2018 September 30, 2019 September 30, 2018 Cash and cash equivalents $ 333.4 $ 477.6 $ 447.1 $ 452.6 Restricted cash 95.8 17.4 63.7 9.6 Cash, cash equivalents and restricted cash $ 429.2 $ 495.0 $ 510.8 $ 462.2 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 2019 2018 Denominator (thousands of shares): Weighted-average common shares outstanding — basic (a) 209,439 174,413 Incremental shares issuable for stock options and awards (b) 1,819 3,153 Weighted-average common shares outstanding — diluted 211,258 177,566 (a) The three months ended December 31, 2019 , reflects the August 2019 issuance of 34,613 shares of UGI Common Stock in connection with the AmeriGas Merger. (b) For the three months ended December 31, 2019 and 2018 , there were 3,499 and 30 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, 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 component of AOCI until such foreign net investment is sold or liquidated. Cash flows from derivative instruments, other than certain cross-currency swaps and net investment hedges, if any, are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges, if any, are included in cash flows from operating activities while cash flows from the currency portion of such hedges, if any, are included in cash flows from financing activities. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows. For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 13 . Business Combination Purchase Price Allocations. From time to time, the Company enters into material business combinations. In accordance with accounting guidance associated with business combinations, the purchase price is allocated to the various assets acquired and liabilities assumed at their estimated fair value as of the acquisition date. Fair values of assets acquired and liabilities assumed are based upon available information. Estimating fair values is generally subject to significant judgment and assumptions and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, under certain circumstances, up to one year from the acquisition date to finalize the purchase price allocation. Other non-operating (expense) income, net . Included in “ Other non-operating (expense) income, 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. 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 prior-period amounts have been reclassified to conform to the current-period presentation.

Accounting Changes

Accounting Changes	3 Months Ended
	Dec. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Changes	Note 3 — Accounting Changes New Accounting Standards Adopted in Fiscal 2020 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. For cash flow and net investment hedges as of the adoption date, the guidance required a modified retrospective approach. The amended presentation and disclosure guidance was required prospectively. The Company adopted the new guidance effective October 1, 2019. The adoption did not have a material impact on our consolidated financial statements. Leases. Effective October 1, 2019, the Company adopted new accounting guidance for leases in accordance with ASC 842. See Notes 2 and 9 for a detailed description of the impact of the new guidance and related disclosures. Accounting Standards Not Yet Adopted Credit Losses. In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments. ” This ASU, as subsequently amended, requires entities to estimate lifetime expected credit losses for financial instruments not measured at fair value through net income, including trade and other receivables, net investments in leases, financial receivables, debt securities, and other financial instruments, which may result in earlier recognition of credit losses. Further, the new current expected credit loss model may affect how entities estimate their allowance for losses related to receivables that are current with respect to their payment terms. ASU 2016-13 is effective for the Company for interim and annual periods beginning October 1, 2020 (Fiscal 2021). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Income Taxes. In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” This ASU simplifies the accounting for income taxes by eliminating certain exceptions within the existing guidance for recognizing deferred taxes for equity method investments, performing intraperiod allocations and calculating income taxes in interim periods. Further, this ASU clarifies existing guidance related to, among other things, recognizing deferred taxes for goodwill and allocated taxes to members of a consolidated group. ASU 2019-12 is effective for the Company for interim and annual periods beginning October 1, 2021 (Fiscal 2022). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	3 Months Ended
	Dec. 31, 2019
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. See Note 4 in the Company’s 2019 Annual Report for information on our revenues from contracts with customers. Revenue Disaggregation The following tables present our disaggregated revenues by reportable segment for the three months ended December 31, 2019 and 2018 : Three Months Ended December 31, 2019 Total Eliminations AmeriGas Propane UGI International Midstream & Marketing (a) UGI Utilities (a) Corporate & Other Revenues from contracts with customers: Utility: Core Market: Residential $ 184.1 $ — $ — $ — $ — $ 184.1 $ — Commercial & Industrial 67.9 — — — — 67.9 — Large delivery service 41.3 — — — — 41.3 — Off-system sales and capacity releases 16.4 (14.1 ) — — — 30.5 — Other 4.4 (0.6 ) — — — 5.0 — Total Utility 314.1 (14.7 ) — — — 328.8 — Non-Utility: LPG: Retail 1,094.4 — 631.2 463.2 — — — Wholesale 65.8 — 22.0 43.8 — — — Energy Marketing 362.9 (25.6 ) — 123.9 264.6 — — Midstream: Pipeline 43.2 — — — 43.2 — — Peaking 3.9 (37.7 ) — — 41.6 — — Other 1.8 — — — 1.8 — — Electricity Generation 8.8 — — — 8.8 — — Other 80.9 (0.9 ) 59.2 12.3 10.3 — — Total Non-Utility 1,661.7 (64.2 ) 712.4 643.2 370.3 — — Total revenues from contracts with customers 1,975.8 (78.9 ) 712.4 643.2 370.3 328.8 — Other revenues (b) 30.8 (0.8 ) 18.0 8.2 2.2 0.5 2.7 Total revenues $ 2,006.6 $ (79.7 ) $ 730.4 $ 651.4 $ 372.5 $ 329.3 $ 2.7 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 (c) 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 (b) 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) 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, none of which are within the scope of ASC 606 and are accounted for in accordance with other GAAP. (c) UGI Utilities includes an unallocated negative surcharge revenue reduction of $(4.1) for the three months ended December 31, 2018 as a result of a PAPUC Order issued May 17, 2018, related to the TCJA. 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 for all periods presented. 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 balances of contract liabilities were $93.1 , $114.1 and $94.0 at December 31, 2019 , September 30, 2019 and December 31, 2018 , respectively, and are included in “Other current liabilities” and “Other noncurrent liabilities” on the Condensed Consolidated Balance Sheets. Revenue recognized for the three months ended December 31, 2019 and 2018 , from the amount included in contract liabilities at September 30, 2019 and 2018 , was $61.0 and $58.1 , respectively. 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, 2019 , Midstream & Marketing and UGI Utilities expect to record approximately $2.0 billion and $0.2 billion of revenues, respectively, related to the minimum future performance obligations over the remaining terms of the related contracts.

CMG Acquisitions

CMG Acquisitions	3 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
CMG Acquisitions	Note 5 — CMG Acquisition On August 1, 2019, UGI through its wholly owned indirect subsidiary, Energy Services, completed the CMG Acquisition in which Energy Services acquired all of the equity interests in CMG and CMG’s approximately 47% interest in Pennant, for total cash consideration of $1,284.4 , subject to final working capital and other adjustments. The CMG Acquisition was consummated pursuant to the CMG Acquisition Agreements. CMG and Pennant provide natural gas gathering and processing services through five discrete systems located in western Pennsylvania, eastern Ohio and the panhandle of West Virginia. The CMG Acquisition is consistent with our growth strategies, including expanding our midstream natural gas gathering and processing assets within the Marcellus and Utica Shale production regions. The CMG Acquisition was funded with cash from borrowings under the Energy Services Term Loan and the UGI Corporation Senior Credit Facility and cash on hand. The Company has accounted for the CMG Acquisition using the acquisition method. At December 31, 2019, the allocation of the purchase price is substantially complete but remains preliminary pending the completion of our third-party valuation report and with regard to the identification and resolution of certain pre-acquisition contingencies and disputes. These amounts are preliminary pending the receipt of additional information. The purchase price allocation will be finalized once these items have been resolved. Accordingly, the fair value estimates presented below relating to these items are subject to change within the measurement period not to exceed one year from the date of acquisition. The components of the preliminary CMG purchase price allocations are as follows: Assets acquired: Cash $ 0.3 Accounts receivable 11.3 Prepaid expenses and other current assets 1.1 Property, plant and equipment 613.2 Investment in Pennant 88.0 Intangible assets (a) 250.0 Total assets acquired $ 963.9 Liabilities assumed: Accounts payable 3.3 Other noncurrent liabilities 0.1 Total liabilities assumed $ 3.4 Goodwill 323.9 Net consideration transferred (including preliminary working capital adjustments) $ 1,284.4 (a) Represents customer relationships having an average amortization period of 35 years . We allocated the purchase price of the acquisition to identifiable intangible assets and property, plant and equipment based on estimated fair values as follows: • Customer relationships were valued using a multi-period, excess earnings method. Key assumptions used in this method include discount rates, growth rates and cash flow projections. These assumptions are most sensitive and susceptible to change as they require significant management judgment; and • Property, plant and equipment were valued based on estimated fair values primarily using depreciated replacement cost and market value methods. The excess of the purchase price for the CMG Acquisition over the preliminary fair values of the assets acquired and liabilities assumed has been reflected as goodwill, assigned to the Midstream & Marketing reportable segment, and results principally from anticipated future capital investment opportunities and value creation resulting from new natural gas processing assets in the Marcellus and Utica Shale production regions. The goodwill recognized from the CMG Acquisition is deductible for income tax purposes. The impact of the CMG Acquisition on a pro forma basis as if the CMG Acquisition had occurred on October 1, 2018 was not material to the Company’s consolidated results for the three months ended December 31, 2018.

Inventories

Inventories	3 Months Ended
	Dec. 31, 2019
Inventory Disclosure [Abstract]
Inventories	Note 6 — Inventories Inventories comprise the following: December 31, September 30, December 31, Non-utility LPG and natural gas $ 163.7 $ 150.2 $ 206.7 Gas Utility natural gas 24.3 26.6 34.9 Materials, supplies and other 59.5 53.1 52.1 Total inventories $ 247.5 $ 229.9 $ 293.7 At December 31, 2019 , UGI Utilities was party to three principal SCAAs with terms of up to three years . Pursuant to the SCAAs, UGI Utilities has, among other things, released certain natural gas storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated natural gas 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, 2019 and September 30, 2019 , all of UGI Utilities’ SCAAs were with Energy Services, the effects of which are eliminated in consolidation. The carrying value of gas storage inventories released under the SCAAs with non-affiliates at December 31, 2018 comprising 1.9 bcf of natural gas was $4.6

Goodwill and Intangible Assets

Goodwill and Intangible Assets	3 Months Ended
	Dec. 31, 2019
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 $ 3,482.9 $ 3,456.4 $ 3,154.8 Intangible assets: Customer relationships $ 1,054.9 $ 1,038.4 $ 795.4 Trademarks and tradenames 16.4 16.2 7.9 Noncompete agreements and other 54.8 46.4 57.6 Accumulated amortization (473.5 ) (441.8 ) (405.4 ) Intangible assets, net (definite-lived) 652.6 659.2 455.5 Trademarks and tradenames (indefinite-lived) 50.8 49.4 49.7 Total intangible assets, net $ 703.4 $ 708.6 $ 505.2 The change in goodwill since September 30, 2019 is primarily due to the effects of foreign currency translation. Amortization expense of intangible assets was $16.8 and $14.6 for the three months ended December 31, 2019 and 2018 , 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 2020 and for the next four fiscal years is as follows: remainder of Fiscal 2020 — $48.7 ; Fiscal 2021 — $61.8 ; Fiscal 2022 — $58.8 ; Fiscal 2023 — $57.3 ; Fiscal 2024 — $56.1 .

Utility Regulatory Assets and L

Utility Regulatory Assets and Liabilities and Regulatory Matters	3 Months Ended
	Dec. 31, 2019
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 9 in the Company’s 2019 Annual Report. Other than removal costs, UGI Utilities currently does not recover a rate of return on its regulatory assets listed below. The following regulatory assets and liabilities associated with UGI Utilities are included on the Condensed Consolidated Balance Sheets: December 31, September 30, December 31, Regulatory assets: Income taxes recoverable $ 121.2 $ 115.2 $ 115.2 Underfunded pension and postretirement plans 175.2 178.6 85.3 Environmental costs 57.5 59.5 58.5 Removal costs, net 26.7 28.3 31.3 Other 9.9 14.0 8.5 Total regulatory assets $ 390.5 $ 395.6 $ 298.8 Regulatory liabilities (a): Postretirement benefit overcollections $ 14.1 $ 14.5 $ 17.3 Deferred fuel and power refunds 6.3 6.1 22.2 State tax benefits — distribution system repairs 26.3 25.0 23.5 PAPUC Temporary Rates Order 25.0 31.3 24.8 Excess federal deferred income taxes 278.1 279.5 280.9 Other 1.4 2.4 4.8 Total regulatory liabilities $ 351.2 $ 358.8 $ 373.5 (a) Regulatory liabilities are included 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. These 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 and power costs or refunds. Net unrealized (losses) gains on such contracts at December 31, 2019 , September 30, 2019 and December 31, 2018 were $(2.9) , $(2.2) and $0.8 , respectively. Other Regulatory Matters Base Rate Filings. On January 28, 2020, Gas Utility filed a request with the PAPUC to increase its base operating revenues for residential, commercial and industrial customers by $ 74.6 annually. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service and to continue funding programs designed to promote and reward customers’ efforts to increase efficient use of natural gas. Gas Utility requested that the new gas rates become effective March 28, 2020. 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 28, 2019, Gas Utility filed a rate request with the PAPUC to increase the base operating revenues for residential, commercial, and industrial customers throughout its Pennsylvania service territory by an aggregate $71.1 . On October 4, 2019, the PAPUC issued a final Order approving a settlement that permits Gas Utility, effective October 11, 2019, to increase its base distribution revenues by $30.0 under a single consolidated tariff, approved a plan for uniform class rates, and permits Gas Utility to extend its Energy Efficiency and Conservation and Growth Extension Tariff programs by an additional term of five years . The PAPUC’s final Order approved a negative surcharge, to return to customers $24.0 of tax benefits experienced by Gas Utility over the period January 1, 2018 to June 30, 2018, plus applicable interest, in accordance with the May 17, 2018 PAPUC Order, which became effective for a twelve-month period beginning on October 11, 2019, the effective date of Gas Utility’s new base rates. 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 PAPUC 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 UGI Utilities’ use of a fully projected future test year and handling of consolidated federal income tax benefits. On January 15, 2020, the Pennsylvania Commonwealth Court affirmed the PAPUC Order adopting UGI Utilities’ position on both issues. The Office of Consumer Advocate has the right to seek an appeal of the Pennsylvania Commonwealth Court Order to the Pennsylvania Supreme Court.

Leases

Leases	3 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	Note 9 — Leases Lessee We lease various buildings and other facilities, real estate, vehicles, rail cars and other equipment, the majority of which are operating leases. We determine if a contract is or contains a lease by evaluating whether the contract explicitly or implicitly identifies an asset, whether we have the right to obtain substantially all of the economic benefits of the identified leased asset and to direct its use. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize ROU assets at the lease commencement date at the value of the lease liability adjusted for any prepayments, lease incentives received, and initial direct costs incurred. Lease liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. These payments are discounted using the discount rate implicit in the lease, when available. We apply an incremental borrowing rate, which is developed utilizing a credit notching approach based on information available at the lease commencement date, to substantially all of our leases as the implicit rate is often not available. Lease expense is recognized on a straight-line basis over the expected lease term. Renewal and termination options are not included in the lease term unless we are reasonably certain that such options will be exercised. Leases with an original lease term of one year or less, including consideration of any renewal options assumed to be exercised, are not included in the Condensed Consolidated Balance Sheets. Certain lease arrangements, primarily fleet vehicle leases with lease terms of one to ten years , contain purchase options. The Company generally excludes purchase options in evaluating its leases unless it is reasonably certain that such options will be exercised. Additionally, leases of fleet vehicles often contain residual value guarantees that are due at the end of the lease. Such amounts are included in the determination of lease liabilities when we are reasonably certain that they will be owed. Certain leasing arrangements require variable payments that are dependent on asset usage or are based on changes in index rates, such as the Consumer Price Index. The variable payments component of such leases cannot be determined at lease commencement and is not recognized in the measurement of ROU assets or lease liabilities, but is recognized in earnings in the period in which the obligation occurs. ROU assets and lease liabilities recorded in the Condensed Consolidated Balance Sheet are as follows: December 31, 2019 Location on the Balance Sheet ROU assets: Operating lease ROU assets $ 429.6 Other assets Finance lease ROU assets 55.3 Property, plant and equipment Total ROU assets $ 484.9 Lease liabilities: Operating lease liabilities - current $ 85.5 Other current liabilities Operating lease liabilities - noncurrent 344.1 Other noncurrent liabilities Finance lease liabilities - current 6.4 Current maturities of long-term debt Finance lease liabilities - noncurrent 42.2 Long-term debt Total lease liabilities $ 478.2 The components of lease cost are as follows: Three Months Ended December 31, 2019 Operating lease cost $ 25.6 Finance lease cost: Amortization of ROU assets 1.6 Interest on lease liabilities 0.5 Variable lease cost 1.4 Short-term lease cost 1.0 Total lease cost $ 30.1 The following table presents the cash and non-cash activity related to lease liabilities included in the Condensed Consolidated Statement of Cash Flows occurring during the period: Three Months Ended December 31, 2019 Cash paid related to lease liabilities: Operating cash flows from operating leases $ 25.5 Operating cash flows from finance leases $ 0.5 Financing cash flows from finance leases $ 1.0 Non-cash lease liability activities: ROU assets obtained in exchange for operating lease liabilities $ 451.9 ROU assets obtained in exchange for finance lease liabilities $ 21.5 The following table presents the weighted-average remaining lease term and weighted-average discount rate as of December 31, 2019: Weighted-average remaining lease term In years Operating leases 6.3 Finance leases 2.5 Weighted-average discount rate % Operating leases 3.9% Finance leases 2.0% Expected annual lease payments based on maturities of operating and finance leases, as well as a reconciliation to the lease liabilities on the Condensed Consolidated Balance Sheet, as of December 31, 2019, were as follows: Remainder of Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2024 After Fiscal 2024 Total Lease Payments Imputed Interest Lease Liabilities Operating leases: $ 75.4 $ 89.8 $ 74.6 $ 66.3 $ 56.1 $ 126.5 $ 488.7 $ (59.1 ) $ 429.6 Finance leases: $ 4.6 $ 5.1 $ 4.1 $ 3.4 $ 3.1 $ 85.9 $ 106.2 $ (57.6 ) $ 48.6 Approximately 85% of the operating lease liabilities presented above relates to AmeriGas Propane. At December 31, 2019, operating and finance leases that had not yet commenced were insignificant. Disclosures related to periods prior to adoption of ASC 842 As discussed above, the Company adopted ASC 842 effective October 1, 2019, using a modified retrospective approach. As required, the following disclosure is provided for periods prior to adoption. The Company’s future minimum payments under non-cancelable operating leases at September 30, 2019 , which were accounted for under ASC 840, were as follows: Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2024 After Fiscal 2024 Total $ 100.4 $ 85.9 $ 71.0 $ 61.7 $ 53.6 $ 139.2 Lessor We enter into lessor arrangements for the purposes of storing, gathering or distributing natural gas and propane. AmeriGas Propane and UGI International have lessor arrangements that grant customers the right to use small, medium and large storage tanks, which we classify as operating leases. These agreements contain renewal options for periods up to nine years
Leases	Note 9 — Leases Lessee We lease various buildings and other facilities, real estate, vehicles, rail cars and other equipment, the majority of which are operating leases. We determine if a contract is or contains a lease by evaluating whether the contract explicitly or implicitly identifies an asset, whether we have the right to obtain substantially all of the economic benefits of the identified leased asset and to direct its use. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize ROU assets at the lease commencement date at the value of the lease liability adjusted for any prepayments, lease incentives received, and initial direct costs incurred. Lease liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. These payments are discounted using the discount rate implicit in the lease, when available. We apply an incremental borrowing rate, which is developed utilizing a credit notching approach based on information available at the lease commencement date, to substantially all of our leases as the implicit rate is often not available. Lease expense is recognized on a straight-line basis over the expected lease term. Renewal and termination options are not included in the lease term unless we are reasonably certain that such options will be exercised. Leases with an original lease term of one year or less, including consideration of any renewal options assumed to be exercised, are not included in the Condensed Consolidated Balance Sheets. Certain lease arrangements, primarily fleet vehicle leases with lease terms of one to ten years , contain purchase options. The Company generally excludes purchase options in evaluating its leases unless it is reasonably certain that such options will be exercised. Additionally, leases of fleet vehicles often contain residual value guarantees that are due at the end of the lease. Such amounts are included in the determination of lease liabilities when we are reasonably certain that they will be owed. Certain leasing arrangements require variable payments that are dependent on asset usage or are based on changes in index rates, such as the Consumer Price Index. The variable payments component of such leases cannot be determined at lease commencement and is not recognized in the measurement of ROU assets or lease liabilities, but is recognized in earnings in the period in which the obligation occurs. ROU assets and lease liabilities recorded in the Condensed Consolidated Balance Sheet are as follows: December 31, 2019 Location on the Balance Sheet ROU assets: Operating lease ROU assets $ 429.6 Other assets Finance lease ROU assets 55.3 Property, plant and equipment Total ROU assets $ 484.9 Lease liabilities: Operating lease liabilities - current $ 85.5 Other current liabilities Operating lease liabilities - noncurrent 344.1 Other noncurrent liabilities Finance lease liabilities - current 6.4 Current maturities of long-term debt Finance lease liabilities - noncurrent 42.2 Long-term debt Total lease liabilities $ 478.2 The components of lease cost are as follows: Three Months Ended December 31, 2019 Operating lease cost $ 25.6 Finance lease cost: Amortization of ROU assets 1.6 Interest on lease liabilities 0.5 Variable lease cost 1.4 Short-term lease cost 1.0 Total lease cost $ 30.1 The following table presents the cash and non-cash activity related to lease liabilities included in the Condensed Consolidated Statement of Cash Flows occurring during the period: Three Months Ended December 31, 2019 Cash paid related to lease liabilities: Operating cash flows from operating leases $ 25.5 Operating cash flows from finance leases $ 0.5 Financing cash flows from finance leases $ 1.0 Non-cash lease liability activities: ROU assets obtained in exchange for operating lease liabilities $ 451.9 ROU assets obtained in exchange for finance lease liabilities $ 21.5 The following table presents the weighted-average remaining lease term and weighted-average discount rate as of December 31, 2019: Weighted-average remaining lease term In years Operating leases 6.3 Finance leases 2.5 Weighted-average discount rate % Operating leases 3.9% Finance leases 2.0% Expected annual lease payments based on maturities of operating and finance leases, as well as a reconciliation to the lease liabilities on the Condensed Consolidated Balance Sheet, as of December 31, 2019, were as follows: Remainder of Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2024 After Fiscal 2024 Total Lease Payments Imputed Interest Lease Liabilities Operating leases: $ 75.4 $ 89.8 $ 74.6 $ 66.3 $ 56.1 $ 126.5 $ 488.7 $ (59.1 ) $ 429.6 Finance leases: $ 4.6 $ 5.1 $ 4.1 $ 3.4 $ 3.1 $ 85.9 $ 106.2 $ (57.6 ) $ 48.6 Approximately 85% of the operating lease liabilities presented above relates to AmeriGas Propane. At December 31, 2019, operating and finance leases that had not yet commenced were insignificant. Disclosures related to periods prior to adoption of ASC 842 As discussed above, the Company adopted ASC 842 effective October 1, 2019, using a modified retrospective approach. As required, the following disclosure is provided for periods prior to adoption. The Company’s future minimum payments under non-cancelable operating leases at September 30, 2019 , which were accounted for under ASC 840, were as follows: Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2024 After Fiscal 2024 Total $ 100.4 $ 85.9 $ 71.0 $ 61.7 $ 53.6 $ 139.2 Lessor We enter into lessor arrangements for the purposes of storing, gathering or distributing natural gas and propane. AmeriGas Propane and UGI International have lessor arrangements that grant customers the right to use small, medium and large storage tanks, which we classify as operating leases. These agreements contain renewal options for periods up to nine years
Leases	Note 9 — Leases Lessee We lease various buildings and other facilities, real estate, vehicles, rail cars and other equipment, the majority of which are operating leases. We determine if a contract is or contains a lease by evaluating whether the contract explicitly or implicitly identifies an asset, whether we have the right to obtain substantially all of the economic benefits of the identified leased asset and to direct its use. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize ROU assets at the lease commencement date at the value of the lease liability adjusted for any prepayments, lease incentives received, and initial direct costs incurred. Lease liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. These payments are discounted using the discount rate implicit in the lease, when available. We apply an incremental borrowing rate, which is developed utilizing a credit notching approach based on information available at the lease commencement date, to substantially all of our leases as the implicit rate is often not available. Lease expense is recognized on a straight-line basis over the expected lease term. Renewal and termination options are not included in the lease term unless we are reasonably certain that such options will be exercised. Leases with an original lease term of one year or less, including consideration of any renewal options assumed to be exercised, are not included in the Condensed Consolidated Balance Sheets. Certain lease arrangements, primarily fleet vehicle leases with lease terms of one to ten years , contain purchase options. The Company generally excludes purchase options in evaluating its leases unless it is reasonably certain that such options will be exercised. Additionally, leases of fleet vehicles often contain residual value guarantees that are due at the end of the lease. Such amounts are included in the determination of lease liabilities when we are reasonably certain that they will be owed. Certain leasing arrangements require variable payments that are dependent on asset usage or are based on changes in index rates, such as the Consumer Price Index. The variable payments component of such leases cannot be determined at lease commencement and is not recognized in the measurement of ROU assets or lease liabilities, but is recognized in earnings in the period in which the obligation occurs. ROU assets and lease liabilities recorded in the Condensed Consolidated Balance Sheet are as follows: December 31, 2019 Location on the Balance Sheet ROU assets: Operating lease ROU assets $ 429.6 Other assets Finance lease ROU assets 55.3 Property, plant and equipment Total ROU assets $ 484.9 Lease liabilities: Operating lease liabilities - current $ 85.5 Other current liabilities Operating lease liabilities - noncurrent 344.1 Other noncurrent liabilities Finance lease liabilities - current 6.4 Current maturities of long-term debt Finance lease liabilities - noncurrent 42.2 Long-term debt Total lease liabilities $ 478.2 The components of lease cost are as follows: Three Months Ended December 31, 2019 Operating lease cost $ 25.6 Finance lease cost: Amortization of ROU assets 1.6 Interest on lease liabilities 0.5 Variable lease cost 1.4 Short-term lease cost 1.0 Total lease cost $ 30.1 The following table presents the cash and non-cash activity related to lease liabilities included in the Condensed Consolidated Statement of Cash Flows occurring during the period: Three Months Ended December 31, 2019 Cash paid related to lease liabilities: Operating cash flows from operating leases $ 25.5 Operating cash flows from finance leases $ 0.5 Financing cash flows from finance leases $ 1.0 Non-cash lease liability activities: ROU assets obtained in exchange for operating lease liabilities $ 451.9 ROU assets obtained in exchange for finance lease liabilities $ 21.5 The following table presents the weighted-average remaining lease term and weighted-average discount rate as of December 31, 2019: Weighted-average remaining lease term In years Operating leases 6.3 Finance leases 2.5 Weighted-average discount rate % Operating leases 3.9% Finance leases 2.0% Expected annual lease payments based on maturities of operating and finance leases, as well as a reconciliation to the lease liabilities on the Condensed Consolidated Balance Sheet, as of December 31, 2019, were as follows: Remainder of Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2024 After Fiscal 2024 Total Lease Payments Imputed Interest Lease Liabilities Operating leases: $ 75.4 $ 89.8 $ 74.6 $ 66.3 $ 56.1 $ 126.5 $ 488.7 $ (59.1 ) $ 429.6 Finance leases: $ 4.6 $ 5.1 $ 4.1 $ 3.4 $ 3.1 $ 85.9 $ 106.2 $ (57.6 ) $ 48.6 Approximately 85% of the operating lease liabilities presented above relates to AmeriGas Propane. At December 31, 2019, operating and finance leases that had not yet commenced were insignificant. Disclosures related to periods prior to adoption of ASC 842 As discussed above, the Company adopted ASC 842 effective October 1, 2019, using a modified retrospective approach. As required, the following disclosure is provided for periods prior to adoption. The Company’s future minimum payments under non-cancelable operating leases at September 30, 2019 , which were accounted for under ASC 840, were as follows: Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2024 After Fiscal 2024 Total $ 100.4 $ 85.9 $ 71.0 $ 61.7 $ 53.6 $ 139.2 Lessor We enter into lessor arrangements for the purposes of storing, gathering or distributing natural gas and propane. AmeriGas Propane and UGI International have lessor arrangements that grant customers the right to use small, medium and large storage tanks, which we classify as operating leases. These agreements contain renewal options for periods up to nine years

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 10 — Commitments and Contingencies Environmental Matters UGI Utilities From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain gas and electric operations. Beginning in 2006 and 2008, UGI Utilities also owned and operated two acquired subsidiaries (CPG and PNG), 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 (i.e. minimum expenditure threshold). 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, 2019 , September 30, 2019 and December 31, 2018 , our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $49.5 , $50.4 and $50.5 , respectively. 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. As such, UGI Utilities has recorded an associated regulatory asset for these costs because recovery of these costs from customers is probable (see Note 8 ). 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. Neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania was material for all periods presented. 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 OLP 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 as of December 31, 2019 , the Partnership has an undiscounted environmental remediation liability of $7.5 related to the site. Our share of the actual remediation costs could be significantly more or less than the accrued amount. Other Matters Purported Class Action Lawsuits. Between May and October of 2014, 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. On April 15, 2019, the Western Missouri District Court ruled that it has jurisdiction over the indirect purchasers’ state law claims and that the indirect customer plaintiffs have standing to pursue those claims. On August 21, 2019, the District Court partially granted the Company’s motion for judgment on the pleadings and dismissed the claims of indirect customer plaintiffs from ten states and the District of Columbia. On October 2, 2019, the Company reached an agreement to resolve the claims of the direct purchaser class of plaintiffs, subject to court approval. 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. 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, 2019
Retirement Benefits [Abstract]
Defined Benefit Pension and Other Postretirement Plans	Note 11 — 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, 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 certain U.S. active and retired employees. In addition, certain UGI International employees in France, Belgium and the Netherlands are covered by defined benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related to the UGI International plans, such amounts are not material. The service cost component of our pension and other postretirement plans, net of amounts capitalized, is reflected in “ Operating and administrative expenses ” on the Condensed Consolidated Statements of Income. The non-service cost component, net of amounts capitalized by UGI Utilities as a regulatory asset, are reflected in “ Other non-operating (expense) income, net ” on the Condensed Consolidated Statements of Income. Net periodic pension cost and other postretirement benefit cost include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended December 31, 2019 2018 2019 2018 Service cost $ 2.8 $ 2.5 $ 0.1 $ — Interest cost 5.8 6.8 0.2 0.2 Expected return on assets (9.4 ) (9.0 ) (0.2 ) (0.2 ) Amortization of: Prior service cost (benefit) 0.1 0.1 (0.1 ) (0.1 ) Actuarial loss 3.7 1.9 — — Net benefit cost (benefit) 3.0 2.3 — (0.1 ) Change in associated regulatory liabilities — — (0.3 ) (0.3 ) Net benefit cost (benefit) after change in regulatory liabilities $ 3.0 $ 2.3 $ (0.3 ) $ (0.4 ) 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, 2019 , the Company made cash contributions to the U.S. Pension Plan of $3.2 . During the three months ended December 31, 2018 , the Company made no cash contributions to the U.S. Pension Plan. The Company expects to make additional cash contributions of approximately $9.5 to the U.S. Pension Plan during the remainder of Fiscal 2020 . 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, determined under GAAP. There were no required contributions to the VEBA during the three months ended December 31, 2019 and 2018 . 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, 2019 and 2018 , were not material.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 12 — Fair Value Measurements Recurring Fair Value Measurements The following table presents, on a gross basis, our financial assets and liabilities, including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy: Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2019: Derivative instruments: Assets: Commodity contracts $ 26.6 $ 20.5 $ — $ 47.1 Foreign currency contracts $ — $ 39.9 $ — $ 39.9 Interest rate contracts $ — $ 2.7 $ — $ 2.7 Liabilities: Commodity contracts $ (76.6 ) $ (110.2 ) $ — $ (186.8 ) Foreign currency contracts $ — $ (4.4 ) $ — $ (4.4 ) Interest rate contracts $ — $ (6.9 ) $ — $ (6.9 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 42.1 $ — $ — $ 42.1 September 30, 2019: Derivative instruments: Assets: Commodity contracts $ 32.0 $ 10.1 $ — $ 42.1 Foreign currency contracts $ — $ 59.0 $ — $ 59.0 Liabilities: Commodity contracts $ (62.3 ) $ (112.7 ) $ — $ (175.0 ) Foreign currency contracts $ — $ (4.3 ) $ — $ (4.3 ) Interest rate contracts $ — $ (12.3 ) $ — $ (12.3 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 39.7 $ — $ — $ 39.7 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 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 11 ). 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 and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. 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) were as follows: December 31, 2019 September 30, 2019 December 31, 2018 Carrying amount $ 5,905.8 $ 5,856.6 $ 4,211.0 Estimated fair value $ 6,248.9 $ 6,189.3 $ 3,970.8 Financial instruments other than derivative instruments, such as short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. The credit risk arising from concentrations of trade accounts receivable is limited because we have a large customer base that extends across many different U.S. markets and a number of foreign countries. For information regarding concentrations of credit risk associated with our derivative instruments, see Note 13

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	3 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 13 — Derivative Instruments and Hedging Activities We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk; (2) interest rate risk; and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies, which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Although our commodity derivative instruments extend over a number of years, a significant portion of our commodity derivative instruments economically hedge commodity price risk during the next twelve months. For additional 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. All Electric Utility forward electricity purchase contracts were subject to the NPNS exception for all periods presented. 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, the Partnership, 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 physical natural gas, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and over-the-counter and ICE natural gas basis swap contracts. In addition, Midstream & Marketing uses NYMEX and over-the-counter futures and options contracts to economically hedge price volatility associated with the gross margin derived from the purchase and anticipated later near-term sale of natural gas storage inventories. Outside of the financial market, Midstream & Marketing also uses ICE and over-the-counter forward physical contracts. 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. 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 Certain of our long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. In order to fix the underlying short-term market interest rates, we may enter into pay-fixed, receive-variable interest rate swap agreements and designate such swaps as cash flow hedges. The remainder of our 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. There were no unsettled IRPAs during any of the periods presented. At December 31, 2019 , the amount of pre-tax 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 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. We layer in these foreign currency exchange contracts over a multi-year period to eventually equal approximately 90% of anticipated UGI International local currency earnings before income taxes. 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 (expense) income, net ,” on the Condensed Consolidated Statements of Income. In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, we previously 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. The last such contracts expired in September 2019. We accounted for these foreign currency exchange contracts as cash flow hedges. 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 component of AOCI. Certain euro-denominated long-term debt issued under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes in October 2018 have been designated as net investment hedges of a portion of our UGI International euro-denominated net investment. During the three months ended December 31, 2019 and 2018, we recognized pre-tax losses associated with these net investment hedges of $20.4 and $6.1 , respectively, in the cumulative translation adjustment component of AOCI. 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, 2019 , September 30, 2019 and December 31, 2018 , and the final settlement date of the Company's open derivative transactions as of December 31, 2019 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through December 31, 2019 September 30, 2019 December 31, 2018 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms October 2020 14.5 23.3 14.7 Non-utility Operations LPG swaps Gallons December 2021 772.0 800.4 450.4 Natural gas futures, forward and pipeline contracts Dekatherms December 2024 201.4 196.1 188.0 Natural gas basis swap contracts Dekatherms December 2024 154.7 131.1 81.2 NYMEX natural gas storage futures contracts Dekatherms March 2020 0.4 0.3 0.7 NYMEX natural gas option contracts Dekatherms March 2020 2.0 2.4 — NYMEX propane storage futures contracts Gallons April 2020 0.1 0.5 0.3 Electricity long forward and futures contracts Kilowatt hours April 2024 4,145.1 3,098.1 3,974.7 Electricity short forward and futures contracts Kilowatt hours April 2024 555.8 366.7 366.7 Interest Rate Risk: Interest rate swaps Euro October 2022 € 300.0 € 300.0 € 300.0 Interest rate swaps USD July 2024 $ 1,354.0 $ 1,357.3 $ 114.1 Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2022 $ 431.2 $ 516.0 $ 408.6 Net investment hedge forward foreign exchange contracts Euro October 2024 € 172.8 € 172.8 € 172.8 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. At December 31, 2019 , September 30, 2019 and December 31, 2018 , the Company pledged net cash collateral of $8.9 , $29.3 , and $10.0 , respectively. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2019 , September 30, 2019 and December 31, 2018 , restricted cash in brokerage accounts totaled $95.8 , $63.7 and $17.4 , 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, 2019 . 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, 2019 , 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: December 31, September 30, December 31, Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 13.9 $ 17.4 $ 2.3 Interest rate contracts 2.7 — — 16.6 17.4 2.3 Derivatives subject to PGC and DS mechanisms: Commodity contracts 0.2 1.4 1.3 Derivatives not designated as hedging instruments: Commodity contracts 46.9 40.7 98.7 Foreign currency contracts 26.0 41.6 22.1 72.9 82.3 120.8 Total derivative assets — gross 89.7 101.1 124.4 Gross amounts offset in the balance sheet (27.2 ) (29.0 ) (34.3 ) Cash collateral received (2.1 ) — — Total derivative assets — net $ 60.4 $ 72.1 $ 90.1 Derivative liabilities: Derivatives designated as hedging instruments: Interest rate contracts $ (6.9 ) $ (12.3 ) $ (3.7 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (3.2 ) (3.7 ) (0.5 ) Derivatives not designated as hedging instruments: Commodity contracts (183.6 ) (171.3 ) (113.1 ) Foreign currency contracts (4.4 ) (4.3 ) (8.8 ) (188.0 ) (175.6 ) (121.9 ) Total derivative liabilities — gross (198.1 ) (191.6 ) (126.1 ) Gross amounts offset in the balance sheet 27.2 29.0 34.3 Cash collateral pledged 11.0 29.3 10.0 Total derivative liabilities — net $ (159.9 ) $ (133.3 ) $ (81.8 ) 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, 2019 and 2018 : Three Months Ended December 31,: Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Cash Flow Hedges: 2019 2018 2019 2018 Foreign currency contracts $ — $ 1.0 $ — $ 0.8 Cost of sales Cross-currency contracts — (0.1 ) — (0.3 ) Interest expense/other operating income, net Interest rate contracts 7.8 (2.8 ) (1.0 ) (1.5 ) Interest expense Total $ 7.8 $ (1.9 ) $ (1.0 ) $ (1.0 ) Net Investment Hedges: Foreign currency contracts $ (3.5 ) $ 0.9 Gain (Loss) Location of Gain (Loss) Derivatives Not Designated as Hedging Instruments: 2019 2018 Commodity contracts $ (33.1 ) $ (159.7 ) Cost of sales Commodity contracts 2.5 (2.8 ) Revenues Commodity contracts 0.1 (0.4 ) Operating and administrative expenses Foreign currency contracts (11.3 ) 8.9 Other non-operating (expense) income, net Total $ (41.8 ) $ (154.0 ) We are also a party to a number of other contracts that have elements of a derivative instrument. However, 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. 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.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	3 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Note 14 — Accumulated Other Comprehensive Income (Loss) The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2019 and 2018 : Three Months Ended December 31, 2019 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — September 30, 2019 $ (25.7 ) $ (25.4 ) $ (165.5 ) $ (216.6 ) Other comprehensive income before reclassification adjustments (after-tax) — 5.6 47.0 52.6 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.3 1.0 — 1.3 Reclassification adjustments tax benefit (0.1 ) (0.3 ) — (0.4 ) Reclassification adjustments (after-tax) 0.2 0.7 — 0.9 Other comprehensive income attributable to UGI 0.2 6.3 47.0 53.5 AOCI — December 31, 2019 $ (25.5 ) $ (19.1 ) $ (118.5 ) $ (163.1 ) 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 benefit (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 ) For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 13 .

Segment Information

Segment Information	3 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Segment Information	Note 15 — Segment Information Our operations comprise four reportable segments generally based upon products or services sold, geographic location and regulatory environment: (1) AmeriGas Propane; (2) UGI International; (3) Midstream & Marketing; and (4) UGI Utilities. During the fourth quarter of Fiscal 2019, the measurement of segment profit used by our CODM was revised to exclude certain items that are now included in Corporate & Other (in addition to net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions, which had previously been excluded). The revision to our segment profit measures aligns with the financial information utilized by our CODM in evaluating our reportable segments’ performance and allocating resources. Prior period amounts have been recast to reflect the change in segment measure of profit. Also during the fourth quarter of Fiscal 2019, principally as a result of the AmeriGas Merger and the CMG Acquisition and related transactions, our CODM began evaluating the performance of all of our reportable segments based upon earnings before interest expense and income taxes, excluding the items noted above. In addition to the items described above, Corporate & Other includes the net expenses of UGI’s captive general liability insurance company, UGI’s corporate headquarters facility and UGI’s unallocated corporate and general expenses as well as interest expense on UGI debt that is not allocated. 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 2019 Annual Report. Three Months Ended December 31, 2019 Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues from external customers $ 2,006.6 $ — $ 730.4 $ 651.4 $ 308.3 $ 314.6 $ 1.9 Intersegment revenues $ — $ (79.7 ) (b) $ — $ — $ 64.2 $ 14.7 $ 0.8 Cost of sales $ 1,008.0 $ (79.1 ) (b) $ 289.2 $ 368.4 $ 264.2 $ 151.6 $ 13.7 Operating income (loss) $ 377.2 $ 0.3 $ 165.3 $ 95.8 (c) $ 55.1 $ 91.8 $ (31.1 ) Income from equity investees 6.5 — — — 6.5 (d) — — Other non-operating (expense) income, net (11.5 ) — — 4.4 — (0.2 ) (15.7 ) Earnings (loss) before interest expense and income taxes 372.2 0.3 165.3 100.2 61.6 91.6 (46.8 ) Interest expense (84.1 ) — (42.5 ) (7.6 ) (11.5 ) (13.6 ) (8.9 ) Income (loss) before income taxes $ 288.1 $ 0.3 $ 122.8 $ 92.6 $ 50.1 $ 78.0 $ (55.7 ) Depreciation and amortization $ 119.4 $ — $ 43.9 $ 31.2 $ 18.4 $ 25.7 $ 0.2 Capital expenditures (including the effects of accruals) $ 151.8 $ — $ 38.5 $ 20.3 $ 22.5 $ 70.5 $ — As of December 31, 2019 Total assets $ 14,285.7 $ (365.5 ) $ 4,609.4 $ 3,243.3 $ 2,859.6 $ 3,710.9 $ 228.0 Short-term borrowings $ 869.7 $ — $ 321.0 $ 181.3 $ 88.4 $ 279.0 $ — Goodwill $ 3,482.9 $ — $ 2,003.0 $ 956.8 $ 341.0 $ 182.1 $ — Three Months Ended December 31, 2018 (e) Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues from external customers $ 2,200.2 $ — $ 820.2 $ 710.7 $ 372.5 $ 299.1 $ (2.3 ) Intersegment revenues $ — $ (111.6 ) (b) $ — $ — $ 86.9 $ 23.6 $ 1.1 Cost of sales $ 1,425.0 $ (110.8 ) (b) $ 378.5 $ 448.6 $ 377.5 $ 159.5 $ 171.7 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, net 9.0 — — 0.7 — 0.4 7.9 Earnings (loss) before interest expense and income taxes 172.1 0.4 166.6 59.0 42.6 77.4 (173.9 ) 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 $ 53.6 $ 42.1 $ 65.7 $ (174.1 ) 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 $ — (a) Corporate & Other includes specific items attributable to our reportable segments that are not included in the segment profit measures used by our CODM in assessing our reportable segments’ performance or allocating resources. The following table presents such pre-tax gains (losses) which have been included in Corporate & Other, and the reportable segments to which they relate, for the three months ended December 31, 2019 and 2018 : Three Months Ended December 31, 2019 Location on Income Statement AmeriGas Propane UGI International Midstream & Marketing Net gains (losses) on commodity derivative instruments not associated with current-period transactions Revenues / Cost of sales $ 9.4 $ (13.5 ) $ (7.5 ) Unrealized losses on foreign currency derivative instruments Other non-operating (expense) income, net $ — $ (15.7 ) $ — Acquisition and integration expenses associated with the CMG Acquisition Operating and administrative expenses $ — $ — $ (0.7 ) LPG business transformation expenses Operating and administrative expenses $ (11.2 ) $ (5.5 ) $ — Three Months Ended December 31, 2018 Location on Income Statement AmeriGas Propane UGI International Midstream & Marketing Net (losses) gains on commodity derivative instruments not associated with current-period transactions Revenues / Cost of sales $ (78.5 ) $ (97.3 ) $ 1.8 Unrealized gains on foreign currency derivative instruments Other non-operating (expense) income, net $ — $ 8.1 $ — Loss on extinguishments of debt Loss on extinguishment of debt $ — $ (6.1 ) $ — (b) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (c) Beginning October 1, 2019, UGI International is allocated a portion of indirect corporate expenses. Prior to October 1, 2019, these expenses were billed to Enterprises, which is included in Corporate & Other. (d) Includes AFUDC associated with PennEast. The three months ended December 31, 2019 also includes equity income from Pennant (see Note 5 ). (e) Segment information recast to reflect the changes adopted during the fourth quarter of Fiscal 2019 in the segment measure of profit used by our CODM to evaluate the performance of our reportable segments.

Global LPG Business Transformat

Global LPG Business Transformation Initiatives	3 Months Ended
	Dec. 31, 2019
Restructuring and Related Activities [Abstract]
Global LPG Business Transformation Initiatives	Note 16 — Global LPG Business Transformation Initiatives During the fourth quarter of Fiscal 2019, we began executing on multi-year business transformation initiatives at our AmeriGas Propane and UGI International business segments. These initiatives are designed to improve long-term operational performance by, among other things, reducing costs and improving efficiency in the areas of sales and marketing, supply and logistics, operations, purchasing, and administration. In addition, these business transformation initiatives focus on enhancing the customer experience through, among other things, enhanced customer relationship management and an improved digital customer experience. In connection with these initiatives, during the three months ended December 31, 2019 , we recognized $16.7 of expenses principally comprising consulting, advisory and employee-related costs. These expenses are reflected in “ Operating and administrative expenses ” on the Condensed Consolidated Statement of Income.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Leases	Leases. Effective October 1, 2019, the Company adopted ASU No. 2016-02, "Leases," which, as amended, is included in ASC 842. This new accounting guidance supersedes previous lease accounting guidance in ASC 840 and requires entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on its balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. We adopted this new guidance using the modified retrospective transition method. Amounts and disclosures related to periods prior to October 1, 2019 have not been restated and continue to be reported in accordance with ASC 840. We elected to apply the following practical expedients in accordance with the guidance upon adoption: • Short-term leases: We did not recognize short-term leases (term of 12 months or less) on the balance sheet; • Easements: We did not re-evaluate existing land easements that were not previously accounted for as leases; and • Other: We did not reassess the classification of expired or existing contracts or determine whether they are or contain a lease. We also did not reassess whether initial direct costs qualify for capitalization under ASC 842. Upon adoption, we recorded ROU assets and lease liabilities of $451.9
Restricted Cash	Restricted Cash.
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, 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 component of AOCI until such foreign net investment is sold or liquidated. 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.
Business Combination Purchase Price Allocations	Business Combination Purchase Price Allocations. From time to time, the Company enters into material business combinations. In accordance with accounting guidance associated with business combinations, the purchase price is allocated to the various assets acquired and liabilities assumed at their estimated fair value as of the acquisition date. Fair values of assets acquired and liabilities assumed are based upon available information. Estimating fair values is generally subject to significant judgment and assumptions and most commonly impacts property, plant and equipment and intangible assets, including those with indefinite lives. Generally, we have, under certain circumstances, up to one year from the acquisition date to finalize the purchase price allocation.
Other non-operating income (expense), net	. Included in “ Other non-operating (expense) income, 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.
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 prior-period amounts have been reclassified to conform to the current-period presentation.
New Accounting Standards Adopted in Fiscal 2020	New Accounting Standards Adopted in Fiscal 2020 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. For cash flow and net investment hedges as of the adoption date, the guidance required a modified retrospective approach. The amended presentation and disclosure guidance was required prospectively. The Company adopted the new guidance effective October 1, 2019. The adoption did not have a material impact on our consolidated financial statements. Leases. Effective October 1, 2019, the Company adopted new accounting guidance for leases in accordance with ASC 842. See Notes 2 and 9 for a detailed description of the impact of the new guidance and related disclosures. Accounting Standards Not Yet Adopted Credit Losses. In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments. ” This ASU, as subsequently amended, requires entities to estimate lifetime expected credit losses for financial instruments not measured at fair value through net income, including trade and other receivables, net investments in leases, financial receivables, debt securities, and other financial instruments, which may result in earlier recognition of credit losses. Further, the new current expected credit loss model may affect how entities estimate their allowance for losses related to receivables that are current with respect to their payment terms. ASU 2016-13 is effective for the Company for interim and annual periods beginning October 1, 2020 (Fiscal 2021). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Income Taxes. In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes.” This ASU simplifies the accounting for income taxes by eliminating certain exceptions within the existing guidance for recognizing deferred taxes for equity method investments, performing intraperiod allocations and calculating income taxes in interim periods. Further, this ASU clarifies existing guidance related to, among other things, recognizing deferred taxes for goodwill and allocated taxes to members of a consolidated group. ASU 2019-12 is effective for the Company for interim and annual periods beginning October 1, 2021 (Fiscal 2022). Early adoption is permitted. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance and determining the period in which the new guidance will be adopted.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Dec. 31, 2019
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, 2019 December 31, 2018 September 30, 2019 September 30, 2018 Cash and cash equivalents $ 333.4 $ 477.6 $ 447.1 $ 452.6 Restricted cash 95.8 17.4 63.7 9.6 Cash, cash equivalents and restricted cash $ 429.2 $ 495.0 $ 510.8 $ 462.2
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, 2019 December 31, 2018 September 30, 2019 September 30, 2018 Cash and cash equivalents $ 333.4 $ 477.6 $ 447.1 $ 452.6 Restricted cash 95.8 17.4 63.7 9.6 Cash, cash equivalents and restricted cash $ 429.2 $ 495.0 $ 510.8 $ 462.2
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 2019 2018 Denominator (thousands of shares): Weighted-average common shares outstanding — basic (a) 209,439 174,413 Incremental shares issuable for stock options and awards (b) 1,819 3,153 Weighted-average common shares outstanding — diluted 211,258 177,566 (a) The three months ended December 31, 2019 , reflects the August 2019 issuance of 34,613 shares of UGI Common Stock in connection with the AmeriGas Merger. (b) For the three months ended December 31, 2019 and 2018 , there were 3,499 and 30 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, 2019
Revenue from Contract with Customer [Abstract]
Summary of Disaggregation of Revenue	The following tables present our disaggregated revenues by reportable segment for the three months ended December 31, 2019 and 2018 : Three Months Ended December 31, 2019 Total Eliminations AmeriGas Propane UGI International Midstream & Marketing (a) UGI Utilities (a) Corporate & Other Revenues from contracts with customers: Utility: Core Market: Residential $ 184.1 $ — $ — $ — $ — $ 184.1 $ — Commercial & Industrial 67.9 — — — — 67.9 — Large delivery service 41.3 — — — — 41.3 — Off-system sales and capacity releases 16.4 (14.1 ) — — — 30.5 — Other 4.4 (0.6 ) — — — 5.0 — Total Utility 314.1 (14.7 ) — — — 328.8 — Non-Utility: LPG: Retail 1,094.4 — 631.2 463.2 — — — Wholesale 65.8 — 22.0 43.8 — — — Energy Marketing 362.9 (25.6 ) — 123.9 264.6 — — Midstream: Pipeline 43.2 — — — 43.2 — — Peaking 3.9 (37.7 ) — — 41.6 — — Other 1.8 — — — 1.8 — — Electricity Generation 8.8 — — — 8.8 — — Other 80.9 (0.9 ) 59.2 12.3 10.3 — — Total Non-Utility 1,661.7 (64.2 ) 712.4 643.2 370.3 — — Total revenues from contracts with customers 1,975.8 (78.9 ) 712.4 643.2 370.3 328.8 — Other revenues (b) 30.8 (0.8 ) 18.0 8.2 2.2 0.5 2.7 Total revenues $ 2,006.6 $ (79.7 ) $ 730.4 $ 651.4 $ 372.5 $ 329.3 $ 2.7 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 (c) 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 (b) 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) 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, none of which are within the scope of ASC 606 and are accounted for in accordance with other GAAP. (c) UGI Utilities includes an unallocated negative surcharge revenue reduction of $(4.1) for the three months ended December 31, 2018 as a result of a PAPUC Order issued May 17, 2018, related to the TCJA.

CMG Acquisitions (Tables)

CMG Acquisitions (Tables)	3 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Components of Preliminary Purchase Price Allocation	The components of the preliminary CMG purchase price allocations are as follows: Assets acquired: Cash $ 0.3 Accounts receivable 11.3 Prepaid expenses and other current assets 1.1 Property, plant and equipment 613.2 Investment in Pennant 88.0 Intangible assets (a) 250.0 Total assets acquired $ 963.9 Liabilities assumed: Accounts payable 3.3 Other noncurrent liabilities 0.1 Total liabilities assumed $ 3.4 Goodwill 323.9 Net consideration transferred (including preliminary working capital adjustments) $ 1,284.4 (a) Represents customer relationships having an average amortization period of 35 years .

Inventories (Tables)

Inventories (Tables)	3 Months Ended
	Dec. 31, 2019
Inventory Disclosure [Abstract]
Components of Inventories	Inventories comprise the following: December 31, September 30, December 31, Non-utility LPG and natural gas $ 163.7 $ 150.2 $ 206.7 Gas Utility natural gas 24.3 26.6 34.9 Materials, supplies and other 59.5 53.1 52.1 Total inventories $ 247.5 $ 229.9 $ 293.7

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	3 Months Ended
	Dec. 31, 2019
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 $ 3,482.9 $ 3,456.4 $ 3,154.8 Intangible assets: Customer relationships $ 1,054.9 $ 1,038.4 $ 795.4 Trademarks and tradenames 16.4 16.2 7.9 Noncompete agreements and other 54.8 46.4 57.6 Accumulated amortization (473.5 ) (441.8 ) (405.4 ) Intangible assets, net (definite-lived) 652.6 659.2 455.5 Trademarks and tradenames (indefinite-lived) 50.8 49.4 49.7 Total intangible assets, net $ 703.4 $ 708.6 $ 505.2

Utility Regulatory Assets and_2

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)	3 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Schedule of Regulatory Assets	The following regulatory assets and liabilities associated with UGI Utilities are included on the Condensed Consolidated Balance Sheets: December 31, September 30, December 31, Regulatory assets: Income taxes recoverable $ 121.2 $ 115.2 $ 115.2 Underfunded pension and postretirement plans 175.2 178.6 85.3 Environmental costs 57.5 59.5 58.5 Removal costs, net 26.7 28.3 31.3 Other 9.9 14.0 8.5 Total regulatory assets $ 390.5 $ 395.6 $ 298.8 Regulatory liabilities (a): Postretirement benefit overcollections $ 14.1 $ 14.5 $ 17.3 Deferred fuel and power refunds 6.3 6.1 22.2 State tax benefits — distribution system repairs 26.3 25.0 23.5 PAPUC Temporary Rates Order 25.0 31.3 24.8 Excess federal deferred income taxes 278.1 279.5 280.9 Other 1.4 2.4 4.8 Total regulatory liabilities $ 351.2 $ 358.8 $ 373.5 (a) Regulatory liabilities are included 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 on the Condensed Consolidated Balance Sheets: December 31, September 30, December 31, Regulatory assets: Income taxes recoverable $ 121.2 $ 115.2 $ 115.2 Underfunded pension and postretirement plans 175.2 178.6 85.3 Environmental costs 57.5 59.5 58.5 Removal costs, net 26.7 28.3 31.3 Other 9.9 14.0 8.5 Total regulatory assets $ 390.5 $ 395.6 $ 298.8 Regulatory liabilities (a): Postretirement benefit overcollections $ 14.1 $ 14.5 $ 17.3 Deferred fuel and power refunds 6.3 6.1 22.2 State tax benefits — distribution system repairs 26.3 25.0 23.5 PAPUC Temporary Rates Order 25.0 31.3 24.8 Excess federal deferred income taxes 278.1 279.5 280.9 Other 1.4 2.4 4.8 Total regulatory liabilities $ 351.2 $ 358.8 $ 373.5 (a) Regulatory liabilities are included in “ Other current liabilities ” and “ Other noncurrent liabilities ” on the Condensed Consolidated Balance Sheets.

Leases (Tables)

Leases (Tables)	3 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Right of Use Assets and Lease Liabilities	ROU assets and lease liabilities recorded in the Condensed Consolidated Balance Sheet are as follows: December 31, 2019 Location on the Balance Sheet ROU assets: Operating lease ROU assets $ 429.6 Other assets Finance lease ROU assets 55.3 Property, plant and equipment Total ROU assets $ 484.9 Lease liabilities: Operating lease liabilities - current $ 85.5 Other current liabilities Operating lease liabilities - noncurrent 344.1 Other noncurrent liabilities Finance lease liabilities - current 6.4 Current maturities of long-term debt Finance lease liabilities - noncurrent 42.2 Long-term debt Total lease liabilities $ 478.2
Components of Lease Expense, Lease Terms and Discount Rate, and Supplemental Cash Flow Information	The components of lease cost are as follows: Three Months Ended December 31, 2019 Operating lease cost $ 25.6 Finance lease cost: Amortization of ROU assets 1.6 Interest on lease liabilities 0.5 Variable lease cost 1.4 Short-term lease cost 1.0 Total lease cost $ 30.1 The following table presents the cash and non-cash activity related to lease liabilities included in the Condensed Consolidated Statement of Cash Flows occurring during the period: Three Months Ended December 31, 2019 Cash paid related to lease liabilities: Operating cash flows from operating leases $ 25.5 Operating cash flows from finance leases $ 0.5 Financing cash flows from finance leases $ 1.0 Non-cash lease liability activities: ROU assets obtained in exchange for operating lease liabilities $ 451.9 ROU assets obtained in exchange for finance lease liabilities $ 21.5 The following table presents the weighted-average remaining lease term and weighted-average discount rate as of December 31, 2019: Weighted-average remaining lease term In years Operating leases 6.3 Finance leases 2.5 Weighted-average discount rate % Operating leases 3.9% Finance leases 2.0%
Maturities of Lease Liabilities, Operating Leases	Expected annual lease payments based on maturities of operating and finance leases, as well as a reconciliation to the lease liabilities on the Condensed Consolidated Balance Sheet, as of December 31, 2019, were as follows: Remainder of Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2024 After Fiscal 2024 Total Lease Payments Imputed Interest Lease Liabilities Operating leases: $ 75.4 $ 89.8 $ 74.6 $ 66.3 $ 56.1 $ 126.5 $ 488.7 $ (59.1 ) $ 429.6 Finance leases: $ 4.6 $ 5.1 $ 4.1 $ 3.4 $ 3.1 $ 85.9 $ 106.2 $ (57.6 ) $ 48.6
Maturities of Lease Liabilities, Finance Leases	Expected annual lease payments based on maturities of operating and finance leases, as well as a reconciliation to the lease liabilities on the Condensed Consolidated Balance Sheet, as of December 31, 2019, were as follows: Remainder of Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2024 After Fiscal 2024 Total Lease Payments Imputed Interest Lease Liabilities Operating leases: $ 75.4 $ 89.8 $ 74.6 $ 66.3 $ 56.1 $ 126.5 $ 488.7 $ (59.1 ) $ 429.6 Finance leases: $ 4.6 $ 5.1 $ 4.1 $ 3.4 $ 3.1 $ 85.9 $ 106.2 $ (57.6 ) $ 48.6
Schedule of Non-Cancelable Operating Leases	The Company’s future minimum payments under non-cancelable operating leases at September 30, 2019 , which were accounted for under ASC 840, were as follows: Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2024 After Fiscal 2024 Total $ 100.4 $ 85.9 $ 71.0 $ 61.7 $ 53.6 $ 139.2

Defined Benefit Pension and O_2

Defined Benefit Pension and Other Postretirement Plans (Tables)	3 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs	Net periodic pension cost and other postretirement benefit cost include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended December 31, 2019 2018 2019 2018 Service cost $ 2.8 $ 2.5 $ 0.1 $ — Interest cost 5.8 6.8 0.2 0.2 Expected return on assets (9.4 ) (9.0 ) (0.2 ) (0.2 ) Amortization of: Prior service cost (benefit) 0.1 0.1 (0.1 ) (0.1 ) Actuarial loss 3.7 1.9 — — Net benefit cost (benefit) 3.0 2.3 — (0.1 ) Change in associated regulatory liabilities — — (0.3 ) (0.3 ) Net benefit cost (benefit) after change in regulatory liabilities $ 3.0 $ 2.3 $ (0.3 ) $ (0.4 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Dec. 31, 2019
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: Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2019: Derivative instruments: Assets: Commodity contracts $ 26.6 $ 20.5 $ — $ 47.1 Foreign currency contracts $ — $ 39.9 $ — $ 39.9 Interest rate contracts $ — $ 2.7 $ — $ 2.7 Liabilities: Commodity contracts $ (76.6 ) $ (110.2 ) $ — $ (186.8 ) Foreign currency contracts $ — $ (4.4 ) $ — $ (4.4 ) Interest rate contracts $ — $ (6.9 ) $ — $ (6.9 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 42.1 $ — $ — $ 42.1 September 30, 2019: Derivative instruments: Assets: Commodity contracts $ 32.0 $ 10.1 $ — $ 42.1 Foreign currency contracts $ — $ 59.0 $ — $ 59.0 Liabilities: Commodity contracts $ (62.3 ) $ (112.7 ) $ — $ (175.0 ) Foreign currency contracts $ — $ (4.3 ) $ — $ (4.3 ) Interest rate contracts $ — $ (12.3 ) $ — $ (12.3 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 39.7 $ — $ — $ 39.7 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 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 11
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) were as follows: December 31, 2019 September 30, 2019 December 31, 2018 Carrying amount $ 5,905.8 $ 5,856.6 $ 4,211.0 Estimated fair value $ 6,248.9 $ 6,189.3 $ 3,970.8

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Dec. 31, 2019
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, 2019 , September 30, 2019 and December 31, 2018 , and the final settlement date of the Company's open derivative transactions as of December 31, 2019 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through December 31, 2019 September 30, 2019 December 31, 2018 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms October 2020 14.5 23.3 14.7 Non-utility Operations LPG swaps Gallons December 2021 772.0 800.4 450.4 Natural gas futures, forward and pipeline contracts Dekatherms December 2024 201.4 196.1 188.0 Natural gas basis swap contracts Dekatherms December 2024 154.7 131.1 81.2 NYMEX natural gas storage futures contracts Dekatherms March 2020 0.4 0.3 0.7 NYMEX natural gas option contracts Dekatherms March 2020 2.0 2.4 — NYMEX propane storage futures contracts Gallons April 2020 0.1 0.5 0.3 Electricity long forward and futures contracts Kilowatt hours April 2024 4,145.1 3,098.1 3,974.7 Electricity short forward and futures contracts Kilowatt hours April 2024 555.8 366.7 366.7 Interest Rate Risk: Interest rate swaps Euro October 2022 € 300.0 € 300.0 € 300.0 Interest rate swaps USD July 2024 $ 1,354.0 $ 1,357.3 $ 114.1 Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2022 $ 431.2 $ 516.0 $ 408.6 Net investment hedge forward foreign exchange contracts Euro October 2024 € 172.8 € 172.8 € 172.8
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: December 31, September 30, December 31, Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 13.9 $ 17.4 $ 2.3 Interest rate contracts 2.7 — — 16.6 17.4 2.3 Derivatives subject to PGC and DS mechanisms: Commodity contracts 0.2 1.4 1.3 Derivatives not designated as hedging instruments: Commodity contracts 46.9 40.7 98.7 Foreign currency contracts 26.0 41.6 22.1 72.9 82.3 120.8 Total derivative assets — gross 89.7 101.1 124.4 Gross amounts offset in the balance sheet (27.2 ) (29.0 ) (34.3 ) Cash collateral received (2.1 ) — — Total derivative assets — net $ 60.4 $ 72.1 $ 90.1 Derivative liabilities: Derivatives designated as hedging instruments: Interest rate contracts $ (6.9 ) $ (12.3 ) $ (3.7 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (3.2 ) (3.7 ) (0.5 ) Derivatives not designated as hedging instruments: Commodity contracts (183.6 ) (171.3 ) (113.1 ) Foreign currency contracts (4.4 ) (4.3 ) (8.8 ) (188.0 ) (175.6 ) (121.9 ) Total derivative liabilities — gross (198.1 ) (191.6 ) (126.1 ) Gross amounts offset in the balance sheet 27.2 29.0 34.3 Cash collateral pledged 11.0 29.3 10.0 Total derivative liabilities — net $ (159.9 ) $ (133.3 ) $ (81.8 )
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, 2019 and 2018 : Three Months Ended December 31,: Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Cash Flow Hedges: 2019 2018 2019 2018 Foreign currency contracts $ — $ 1.0 $ — $ 0.8 Cost of sales Cross-currency contracts — (0.1 ) — (0.3 ) Interest expense/other operating income, net Interest rate contracts 7.8 (2.8 ) (1.0 ) (1.5 ) Interest expense Total $ 7.8 $ (1.9 ) $ (1.0 ) $ (1.0 ) Net Investment Hedges: Foreign currency contracts $ (3.5 ) $ 0.9 Gain (Loss) Location of Gain (Loss) Derivatives Not Designated as Hedging Instruments: 2019 2018 Commodity contracts $ (33.1 ) $ (159.7 ) Cost of sales Commodity contracts 2.5 (2.8 ) Revenues Commodity contracts 0.1 (0.4 ) Operating and administrative expenses Foreign currency contracts (11.3 ) 8.9 Other non-operating (expense) income, net Total $ (41.8 ) $ (154.0 )

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	3 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	The tables below present changes in AOCI, net of tax, during the three months ended December 31, 2019 and 2018 : Three Months Ended December 31, 2019 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI — September 30, 2019 $ (25.7 ) $ (25.4 ) $ (165.5 ) $ (216.6 ) Other comprehensive income before reclassification adjustments (after-tax) — 5.6 47.0 52.6 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.3 1.0 — 1.3 Reclassification adjustments tax benefit (0.1 ) (0.3 ) — (0.4 ) Reclassification adjustments (after-tax) 0.2 0.7 — 0.9 Other comprehensive income attributable to UGI 0.2 6.3 47.0 53.5 AOCI — December 31, 2019 $ (25.5 ) $ (19.1 ) $ (118.5 ) $ (163.1 ) 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 benefit (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 )

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Schedule of Segment Reporting Information	Three Months Ended December 31, 2019 Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues from external customers $ 2,006.6 $ — $ 730.4 $ 651.4 $ 308.3 $ 314.6 $ 1.9 Intersegment revenues $ — $ (79.7 ) (b) $ — $ — $ 64.2 $ 14.7 $ 0.8 Cost of sales $ 1,008.0 $ (79.1 ) (b) $ 289.2 $ 368.4 $ 264.2 $ 151.6 $ 13.7 Operating income (loss) $ 377.2 $ 0.3 $ 165.3 $ 95.8 (c) $ 55.1 $ 91.8 $ (31.1 ) Income from equity investees 6.5 — — — 6.5 (d) — — Other non-operating (expense) income, net (11.5 ) — — 4.4 — (0.2 ) (15.7 ) Earnings (loss) before interest expense and income taxes 372.2 0.3 165.3 100.2 61.6 91.6 (46.8 ) Interest expense (84.1 ) — (42.5 ) (7.6 ) (11.5 ) (13.6 ) (8.9 ) Income (loss) before income taxes $ 288.1 $ 0.3 $ 122.8 $ 92.6 $ 50.1 $ 78.0 $ (55.7 ) Depreciation and amortization $ 119.4 $ — $ 43.9 $ 31.2 $ 18.4 $ 25.7 $ 0.2 Capital expenditures (including the effects of accruals) $ 151.8 $ — $ 38.5 $ 20.3 $ 22.5 $ 70.5 $ — As of December 31, 2019 Total assets $ 14,285.7 $ (365.5 ) $ 4,609.4 $ 3,243.3 $ 2,859.6 $ 3,710.9 $ 228.0 Short-term borrowings $ 869.7 $ — $ 321.0 $ 181.3 $ 88.4 $ 279.0 $ — Goodwill $ 3,482.9 $ — $ 2,003.0 $ 956.8 $ 341.0 $ 182.1 $ — Three Months Ended December 31, 2018 (e) Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues from external customers $ 2,200.2 $ — $ 820.2 $ 710.7 $ 372.5 $ 299.1 $ (2.3 ) Intersegment revenues $ — $ (111.6 ) (b) $ — $ — $ 86.9 $ 23.6 $ 1.1 Cost of sales $ 1,425.0 $ (110.8 ) (b) $ 378.5 $ 448.6 $ 377.5 $ 159.5 $ 171.7 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, net 9.0 — — 0.7 — 0.4 7.9 Earnings (loss) before interest expense and income taxes 172.1 0.4 166.6 59.0 42.6 77.4 (173.9 ) 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 $ 53.6 $ 42.1 $ 65.7 $ (174.1 ) 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 $ — (a) Corporate & Other includes specific items attributable to our reportable segments that are not included in the segment profit measures used by our CODM in assessing our reportable segments’ performance or allocating resources. The following table presents such pre-tax gains (losses) which have been included in Corporate & Other, and the reportable segments to which they relate, for the three months ended December 31, 2019 and 2018 : Three Months Ended December 31, 2019 Location on Income Statement AmeriGas Propane UGI International Midstream & Marketing Net gains (losses) on commodity derivative instruments not associated with current-period transactions Revenues / Cost of sales $ 9.4 $ (13.5 ) $ (7.5 ) Unrealized losses on foreign currency derivative instruments Other non-operating (expense) income, net $ — $ (15.7 ) $ — Acquisition and integration expenses associated with the CMG Acquisition Operating and administrative expenses $ — $ — $ (0.7 ) LPG business transformation expenses Operating and administrative expenses $ (11.2 ) $ (5.5 ) $ — Three Months Ended December 31, 2018 Location on Income Statement AmeriGas Propane UGI International Midstream & Marketing Net (losses) gains on commodity derivative instruments not associated with current-period transactions Revenues / Cost of sales $ (78.5 ) $ (97.3 ) $ 1.8 Unrealized gains on foreign currency derivative instruments Other non-operating (expense) income, net $ — $ 8.1 $ — Loss on extinguishments of debt Loss on extinguishment of debt $ — $ (6.1 ) $ — (b) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (c) Beginning October 1, 2019, UGI International is allocated a portion of indirect corporate expenses. Prior to October 1, 2019, these expenses were billed to Enterprises, which is included in Corporate & Other. (d) Includes AFUDC associated with PennEast. The three months ended December 31, 2019 also includes equity income from Pennant (see Note 5 ). (e) Segment information recast to reflect the changes adopted during the fourth quarter of Fiscal 2019 in the segment measure of profit used by our CODM to evaluate the performance of our reportable segments.

Nature of Operations (Details)

Nature of Operations (Details) $ in Millions	Aug. 21, 2019USD ($)shares	Aug. 20, 2019	Aug. 31, 2019shares	Dec. 31, 2019county	Dec. 31, 2018USD ($)
Investment [Line Items]
General Partner incentive distribution					$ 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		1.00%
Percentage of limited partnership interest in AmeriGas Partners		25.50%
AmeriGas Propane | AmeriGas OLP
Investment [Line Items]
Effective ownership interest in AmeriGas OLP		27.00%
Merger Sub
Investment [Line Items]
Common stock paid in cash to acquire all outstanding common units	$ 528.9
Common Stock | Merger Sub
Investment [Line Items]
Shares issued in business acquisition (in shares) | shares	34,612,847		34,613,000

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - (Narrative) (Details) $ in Millions	Dec. 31, 2019USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease ROU assets	$ 429.6
Lease Liabilities	429.6
ASU 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease ROU assets	451.9
Lease Liabilities	$ 451.9
Southern Company | PennEast Pipeline Company, LLC
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity method investment ownership percent	20.00%
New Jersey Resources | PennEast Pipeline Company, LLC
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity method investment ownership percent	20.00%
South Jersey Industries | PennEast Pipeline Company, LLC
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity method investment ownership percent	20.00%
Enbridge Inc | PennEast Pipeline Company, LLC
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity method investment ownership percent	20.00%
Affiliated Entity | UGI PennEast, LLC | PennEast Pipeline Company, LLC
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Equity method investment ownership percent	20.00%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Schedule of Cash and Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018	Sep. 30, 2018
Accounting Policies [Abstract]
Cash and cash equivalents	$ 333.4	$ 447.1	$ 477.6	$ 452.6
Restricted cash	95.8	63.7	17.4	9.6
Cash, cash equivalents and restricted cash	$ 429.2	$ 510.8	$ 495	$ 462.2

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details) - shares	Aug. 21, 2019	Aug. 31, 2019	Dec. 31, 2019	Dec. 31, 2018
Denominator:
Weighted-average common shares outstanding - basic (in shares)			209,439,000	174,413,000
Incremental shares issuable for stock options and awards (in shares)			1,819,000	3,153,000
Weighted-average common shares outstanding - diluted (in shares)			211,258,000	177,566,000
Business Acquisition [Line Items]
Antidilutive shares excluded from calculation of earnings per share (in shares)			3,499,000	30,000
Merger Sub | Common Stock
Business Acquisition [Line Items]
Shares issued in business acquisition (in shares)	34,612,847	34,613,000

Revenue from Contracts with C_3

Revenue from Contracts with Customers - Disaggregation (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	$ 1,975.8	$ 2,175.2
Other revenue	30.8	25
Total revenues	2,006.6	2,200.2
Negative surcharge		4.1
Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	184.1	175.7
Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	67.9	67.6
Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	41.3	39.5
Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	16.4	15.2
Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	4.4	0.5
Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	314.1	298.5
Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1,094.4	1,229.7
Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	65.8	60
Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	362.9	468.9
Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	43.2	19.4
Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	3.9	2
Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1.8	1
Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	8.8	11.7
Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	80.9	84
Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1,661.7	1,876.7
Eliminations
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	(78.9)	(110.5)
Other revenue	(0.8)	(1.1)
Total revenues	(79.7)	(111.6)
Eliminations | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Eliminations | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Eliminations | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Eliminations | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	(14.1)	(22.9)
Eliminations | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	(0.6)	(0.7)
Eliminations | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	(14.7)	(23.6)
Eliminations | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Eliminations | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Eliminations | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	(25.6)	(47.5)
Eliminations | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Eliminations | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	(37.7)	(38.7)
Eliminations | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Eliminations | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Eliminations | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	(0.9)	(0.7)
Eliminations | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	(64.2)	(86.9)
Eliminations | AmeriGas Propane
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Eliminations | UGI International
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Eliminations | Midstream and Marketing
Disaggregation of Revenue [Line Items]
Total revenues	64.2	86.9
Eliminations | UGI Utilities
Disaggregation of Revenue [Line Items]
Total revenues	14.7	23.6
Operating Segments | AmeriGas Propane
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	712.4	803.5
Other revenue	18	16.7
Total revenues	730.4	820.2
Operating Segments | AmeriGas Propane | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | AmeriGas Propane | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | AmeriGas Propane | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | AmeriGas Propane | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | AmeriGas Propane | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | AmeriGas Propane | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | AmeriGas Propane | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	631.2	721.9
Operating Segments | AmeriGas Propane | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	22	21
Operating Segments | AmeriGas Propane | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | AmeriGas Propane | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | AmeriGas Propane | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | AmeriGas Propane | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | AmeriGas Propane | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | AmeriGas Propane | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	59.2	60.6
Operating Segments | AmeriGas Propane | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	712.4	803.5
Operating Segments | UGI International
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	643.2	702.3
Other revenue	8.2	8.4
Total revenues	651.4	710.7
Operating Segments | UGI International | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI International | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI International | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI International | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI International | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI International | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI International | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	463.2	507.8
Operating Segments | UGI International | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	43.8	39
Operating Segments | UGI International | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	123.9	143.1
Operating Segments | UGI International | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI International | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI International | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI International | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI International | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	12.3	12.4
Operating Segments | UGI International | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	643.2	702.3
Operating Segments | Midstream and Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	370.3	457.8
Other revenue	2.2	1.6
Total revenues	372.5	459.4
Operating Segments | Midstream and Marketing | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | Midstream and Marketing | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | Midstream and Marketing | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | Midstream and Marketing | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | Midstream and Marketing | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | Midstream and Marketing | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | Midstream and Marketing | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | Midstream and Marketing | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | Midstream and Marketing | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	264.6	373.3
Operating Segments | Midstream and Marketing | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	43.2	19.4
Operating Segments | Midstream and Marketing | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	41.6	40.7
Operating Segments | Midstream and Marketing | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1.8	1
Operating Segments | Midstream and Marketing | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	8.8	11.7
Operating Segments | Midstream and Marketing | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	10.3	11.7
Operating Segments | Midstream and Marketing | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	370.3	457.8
Operating Segments | UGI Utilities
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	328.8	322.1
Other revenue	0.5	0.6
Total revenues	329.3	322.7
Operating Segments | UGI Utilities | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	184.1	175.7
Operating Segments | UGI Utilities | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	67.9	67.6
Operating Segments | UGI Utilities | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	41.3	39.5
Operating Segments | UGI Utilities | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	30.5	38.1
Operating Segments | UGI Utilities | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	5	1.2
Operating Segments | UGI Utilities | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	328.8	322.1
Operating Segments | UGI Utilities | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI Utilities | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI Utilities | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI Utilities | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI Utilities | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI Utilities | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI Utilities | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI Utilities | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Operating Segments | UGI Utilities | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Other revenue	2.7	(1.2)
Total revenues	2.7	(1.2)
Corporate & Other | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0
Corporate & Other | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	$ 0	$ 0

Revenue from Contracts with C_4

Revenue from Contracts with Customers - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Sep. 30, 2019
Disaggregation of Revenue [Line Items]
Contract with customer, liability, current	$ 93.1	$ 94	$ 114.1
Contract with customer, liability, revenue recognized	61	$ 58.1
Midstream and Marketing
Disaggregation of Revenue [Line Items]
Revenue, remaining performance obligation	2,000
UGI Utilities
Disaggregation of Revenue [Line Items]
Revenue, remaining performance obligation	$ 200

CMG Acquisitions - Narrative (D

CMG Acquisitions - Narrative (Details) $ in Millions	Aug. 01, 2019USD ($)
CMG
Business Acquisition [Line Items]
Total cash paid	$ 1,284.4
Affiliated Entity | CMG | Pennant
Business Acquisition [Line Items]
Percentage of voting interests acquired	47.00%

CMG Acquisitions - Components o

CMG Acquisitions - Components of Final Purchase Price Allocation (Details) - USD ($) $ in Millions	Aug. 01, 2019	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Goodwill		$ 3,482.9	$ 3,456.4	$ 3,154.8
CMG
Business Acquisition [Line Items]
Cash		0.3
Accounts receivable		11.3
Prepaid expenses and other current assets		1.1
Property, plant and equipment		613.2
Investment in Pennant		88
Intangible assets		250
Total assets acquired		963.9
Accounts payable		3.3
Other noncurrent liabilities		0.1
Total liabilities assumed		3.4
Goodwill		323.9
Net consideration transferred (including preliminary working capital adjustments)		$ 1,284.4
CMG | Customer Relationships
Business Acquisition [Line Items]
Average intangible amortization period	35 years

Inventories - Components of Inv

Inventories - Components of Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Inventory
Total inventories	$ 247.5	$ 229.9	$ 293.7
Non-utility LPG and natural gas
Inventory
Total inventories	163.7	150.2	206.7
Gas Utility natural gas
Inventory
Total inventories	24.3	26.6	34.9
Materials, supplies and other
Inventory
Total inventories	$ 59.5	$ 53.1	$ 52.1

Inventories - Narrative (Detai

Inventories - Narrative (Details) - UGI Utilities $ in Millions	3 Months Ended
	Dec. 31, 2019storage_agreement	Dec. 31, 2018USD ($)Bcf
Inventory
Number of storage agreements | storage_agreement	3
SCAA contract term (up to)	3 years
Volume of gas storage inventories released under SCAAs with non-affiliates (in bcf) | Bcf		1.9
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $		$ 4.6

Goodwill and Intangible Asset_2

Goodwill and Intangible Assets - Components of Company's Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	$ 3,482.9	$ 3,456.4	$ 3,154.8
Intangible assets:
Customer relationships	1,054.9	1,038.4	795.4
Trademarks and tradenames	16.4	16.2	7.9
Noncompete agreements and other	54.8	46.4	57.6
Accumulated amortization	(473.5)	(441.8)	(405.4)
Intangible assets, net (definite-lived)	652.6	659.2	455.5
Trademarks and tradenames (indefinite-lived)	50.8	49.4	49.7
Total intangible assets, net	$ 703.4	$ 708.6	$ 505.2

Goodwill and Intangible Asset_3

Goodwill and Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense of intangible assets	$ 16.8	$ 14.6
Remainder of Fiscal 2020	48.7
Fiscal 2021	61.8
Fiscal 2022	58.8
Fiscal 2023	57.3
Fiscal 2024	$ 56.1

Utility Regulatory Assets and_3

Utility Regulatory Assets and Liabilities and Regulatory Matters Schedule of Regulatory Assets and Liabilities (Details) - UGI Utilities - USD ($) $ in Millions	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Regulatory Assets
Regulatory assets	$ 390.5	$ 395.6	$ 298.8
Regulatory Liabilities
Regulatory liabilities	351.2	358.8	373.5
Postretirement benefit overcollections
Regulatory Liabilities
Regulatory liabilities	14.1	14.5	17.3
Deferred fuel and power refunds
Regulatory Liabilities
Regulatory liabilities	6.3	6.1	22.2
State tax benefits — distribution system repairs
Regulatory Liabilities
Regulatory liabilities	26.3	25	23.5
PAPUC Temporary Rates Order
Regulatory Liabilities
Regulatory liabilities	25	31.3	24.8
Excess federal deferred income taxes
Regulatory Liabilities
Regulatory liabilities	278.1	279.5	280.9
Other
Regulatory Liabilities
Regulatory liabilities	1.4	2.4	4.8
Income taxes recoverable
Regulatory Assets
Regulatory assets	121.2	115.2	115.2
Underfunded pension and postretirement plans
Regulatory Assets
Regulatory assets	175.2	178.6	85.3
Environmental costs
Regulatory Assets
Regulatory assets	57.5	59.5	58.5
Removal costs, net
Regulatory Assets
Regulatory assets	26.7	28.3	31.3
Other
Regulatory Assets
Regulatory assets	$ 9.9	$ 14	$ 8.5

Utility Regulatory Assets and_4

Utility Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) - USD ($) $ in Millions	Jan. 28, 2020	Oct. 11, 2019	Jan. 28, 2019	Oct. 27, 2018	Oct. 25, 2018	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Pennsylvania Public Utility Commission | UGI Gas
Regulatory Assets
Public utilities, requested rate increase (decrease), amount			$ 71.1
Public utilities, approved rate increase (decrease), amount		$ 30
Tax benefit to be returned			$ 24
Energy Efficiency and Conservation and Growth extension tariff, extension term		5 years
Pennsylvania Public Utility Commission | Electric Utility
Regulatory Assets
Public utilities, requested rate increase (decrease), amount					$ 3.2
Public utilities, customer billing credit				$ 0.2
Gas Utility
Regulatory Assets
Fair value of unrealized gains (losses)						$ (2.9)	$ (2.2)	$ 0.8
Subsequent Event | Pennsylvania Public Utility Commission | UGI Gas
Regulatory Assets
Public utilities, requested rate increase (decrease), amount	$ 74.6

Leases - Narrative (Details)

Leases - Narrative (Details)	3 Months Ended
	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Renewal term (up to)	9 years
Vehicles | Minimum
Lessee, Lease, Description [Line Items]
Operating lease remaining lease term	1 year
Vehicles | Maximum
Lessee, Lease, Description [Line Items]
Operating lease remaining lease term	10 years
AmeriGas Propane | Subsidiary Concentration Risk | Lease Liability Total
Lessee, Lease, Description [Line Items]
Risk percent	85.00%

Leases - ROU Assets and Lease L

Leases - ROU Assets and Lease Liabilities (Details) $ in Millions	Dec. 31, 2019USD ($)
ROU assets:
Operating lease ROU assets	$ 429.6
Finance lease ROU assets	55.3
Total ROU assets	484.9
Lease liabilities:
Operating lease liabilities - current	85.5
Operating lease liabilities - noncurrent	344.1
Finance lease liabilities - current	6.4
Finance lease liabilities - noncurrent	42.2
Liabilities	$ 478.2

Leases - Components of Lease Ex

Leases - Components of Lease Expense (Details) $ in Millions	3 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating lease cost	$ 25.6
Finance lease cost:
Amortization of ROU assets	1.6
Interest on lease liabilities	0.5
Variable lease cost	1.4
Short-term lease cost	1
Total lease cost	30.1
Cash paid related to lease liabilities:
Operating cash flows from operating leases	25.5
Operating cash flows from finance leases	0.5
Financing cash flows from finance leases	1
Non-cash lease liability activities:
ROU assets obtained in exchange for operating lease liabilities	451.9
ROU assets obtained in exchange for finance lease liabilities	$ 21.5
Weighted-average remaining lease term
Operating leases	6 years 3 months 18 days
Finance leases	2 years 6 months
Weighted-average discount rate
Operating leases	3.90%
Finance leases	2.00%

Leases - Maturities of Lease Li

Leases - Maturities of Lease Liabilities (Details) $ in Millions	Dec. 31, 2019USD ($)
Operating leases:
Remainder of 2020	$ 75.4
2021	89.8
2022	74.6
2023	66.3
2024	56.1
After 2024	126.5
Total Lease Payments	488.7
Imputed Interest	(59.1)
Lease Liabilities	429.6
Finance leases:
Remainder of 2020	4.6
2021	5.1
2022	4.1
2023	3.4
2024	3.1
After 2024	85.9
Total Lease Payments	106.2
Imputed Interest	(57.6)
Lease Liabilities	$ 48.6

Leases - Future Minimum Payment

Leases - Future Minimum Payments Under Non-Cancelable Operating Leases (Details) $ in Millions	Sep. 30, 2019USD ($)
Total
2020	$ 100.4
2021	85.9
2022	71
2023	61.7
2024	53.6
After Fiscal 2024	$ 139.2

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017record_of_decision	Dec. 31, 2008lb	Dec. 31, 2007lb	Dec. 31, 2019USD ($)subsidiary	Sep. 30, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2017USD ($)
Loss Contingencies
Environmental expenditures cap during calendar year				$ 5.4
Amount of propane in cylinders before reduction (in pounds) | lb			17
Amount of propane in cylinders after reduction (in pounds) | lb		15
CPG, PNG and UGI Gas COAs
Loss Contingencies
Accrual for environmental loss contingencies				$ 49.5	$ 50.4	$ 50.5
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				$ 7.5
Loss contingency, number of remediation plans | record_of_decision	3
Estimated remediation plan cost							$ 27.7

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, 2019	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 2.8	$ 2.5
Interest cost	5.8	6.8
Expected return on assets	(9.4)	(9)
Amortization of:
Prior service cost (benefit)	0.1	0.1
Actuarial loss (gain)	3.7	1.9
Net benefit cost (benefit)	3	2.3
Change in associated regulatory liabilities	0	0
Net benefit cost (benefit) after change in regulatory liabilities	3	2.3
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	0.1	0
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 (gain)	0	0
Net benefit cost (benefit)	0	(0.1)
Change in associated regulatory liabilities	(0.3)	(0.3)
Net benefit cost (benefit) after change in regulatory liabilities	$ (0.3)	$ (0.4)

Defined Benefit Pension and O_4

Defined Benefit Pension and Other Postretirement Plans - Narrative (Details) - USD ($)	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans
Contribution made to pension and post-retirement plans	$ 3,200,000	$ 0
Expected contribution to pension plan during remainder of fiscal year		9,500,000
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)	0	(100,000)
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, 2019	Sep. 30, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, Assets	$ 89.7	$ 101.1	$ 124.4
Derivative instruments, Liabilities	(198.1)	(191.6)	(126.1)
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-qualified supplemental postretirement grantor trust investments	42.1	39.7	38
Fair Value, Measurements, Recurring | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, Assets	47.1	42.1	100
Derivative instruments, Liabilities	(186.8)	(175)	(113.6)
Fair Value, Measurements, Recurring | Forward foreign currency exchange contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, Assets	39.9	59	24.4
Derivative instruments, Liabilities	(4.4)	(4.3)	(8.8)
Fair Value, Measurements, Recurring | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, Assets	2.7
Derivative instruments, Liabilities	(6.9)	(12.3)	(3.7)
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-qualified supplemental postretirement grantor trust investments	42.1	39.7	38
Fair Value, Measurements, Recurring | Level 1 | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, Assets	26.6	32	72.1
Derivative instruments, Liabilities	(76.6)	(62.3)	(35.6)
Fair Value, Measurements, Recurring | Level 1 | Forward foreign currency exchange contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, Assets	0	0	0
Derivative 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 [Line Items]
Derivative instruments, Assets	0
Derivative instruments, Liabilities	0	0	0
Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
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 [Line Items]
Derivative instruments, Assets	20.5	10.1	27.9
Derivative instruments, Liabilities	(110.2)	(112.7)	(78)
Fair Value, Measurements, Recurring | Level 2 | Forward foreign currency exchange contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, Assets	39.9	59	24.4
Derivative instruments, Liabilities	(4.4)	(4.3)	(8.8)
Fair Value, Measurements, Recurring | Level 2 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, Assets	2.7
Derivative instruments, Liabilities	(6.9)	(12.3)	(3.7)
Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
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 [Line Items]
Derivative instruments, Assets	0	0	0
Derivative instruments, Liabilities	0	0	0
Fair Value, Measurements, Recurring | Level 3 | Forward foreign currency exchange contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, Assets	0	0	0
Derivative 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 [Line Items]
Derivative instruments, Assets	0
Derivative instruments, Liabilities	$ 0	$ 0	$ 0

Fair Value Measurements - (Deta

Fair Value Measurements - (Details) - USD ($) $ in Millions	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Carrying amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 5,905.8	$ 5,856.6	$ 4,211
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 6,248.9	$ 6,189.3	$ 3,970.8

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Narrative (Details) - USD ($)	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Sep. 30, 2019	Oct. 25, 2018	Sep. 30, 2018
Derivative [Line Items]
Potential exposure coverage, percent	$ 3,500,000
Pre-tax losses associated with net investment hedges	20,400,000	$ 6,100,000
Derivative collateral, right to reclaim cash	8,900,000	10,000,000	$ 29,300,000
Restricted cash	95,800,000	17,400,000	63,700,000		$ 9,600,000
Interest Rate Protection Agreements
Derivative [Line Items]
Notional amount	$ 0	$ 0	$ 0
Foreign Exchange Forward
Derivative [Line Items]
International local currency earnings before income taxes	90.00%
UGI International LLC | 3.25% Senior Unsecured Notes Due November 2025 | Senior Notes
Derivative [Line Items]
Stated interest rate				3.25%

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, 2019USD ($)DTHgalkWh	Dec. 31, 2019EUR (€)DTHgalkWh	Sep. 30, 2019USD ($)DTHgalkWh	Sep. 30, 2019EUR (€)DTHgalkWh	Dec. 31, 2018USD ($)DTHgalkWh	Dec. 31, 2018EUR (€)DTHgalkWh
Commodity contracts | Propane
Derivative [Line Items]
Notional amount (in units) | gal	772	772	800.4	800.4	450.4	450.4
Commodity contracts | Electricity | Long
Derivative [Line Items]
Notional amount (in units) | kWh	4,145.1	4,145.1	3,098.1	3,098.1	3,974.7	3,974.7
Commodity contracts | Electricity | Short
Derivative [Line Items]
Notional amount (in units) | kWh	555.8	555.8	366.7	366.7	366.7	366.7
Natural gas futures, forward and pipeline contracts (in dekatherms) | Natural Gas
Derivative [Line Items]
Notional amount (in units)	201.4	201.4	196.1	196.1	188	188
Natural gas basis swap contracts (in dekatherms) | Natural Gas
Derivative [Line Items]
Notional amount (in units)	154.7	154.7	131.1	131.1	81.2	81.2
NYMEX natural gas storage futures contracts (in dekatherms) | Natural Gas
Derivative [Line Items]
Notional amount (in units)	0.4	0.4	0.3	0.3	0.7	0.7
NYMEX natural gas option contracts (in dekatherms) | Natural Gas
Derivative [Line Items]
Notional amount (in units)	2	2	2.4	2.4	0	0
NYMEX propane storage futures contracts (in gallons) | Propane
Derivative [Line Items]
Notional amount (in units) | gal	0.1	0.1	0.5	0.5	0.3	0.3
Interest rate swaps
Derivative [Line Items]
Notional amount	$ 1,354	€ 300	$ 1,357.3	€ 300	$ 114.1	€ 300
Forward foreign currency exchange contracts
Derivative [Line Items]
Notional amount	$ 431.2	€ 172.8	$ 516	€ 172.8	$ 408.6	€ 172.8
Regulated Utility Operations | Commodity contracts | Natural Gas
Derivative [Line Items]
Notional amount (in units)	14.5	14.5	23.3	23.3	14.7	14.7

Derivative Instruments and He_5

Derivative Instruments and Hedging Activities - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Derivative assets:
Total derivative assets — gross	$ 89.7	$ 101.1	$ 124.4
Gross amounts offset in the balance sheet	(27.2)	(29)	(34.3)
Cash collateral received	(2.1)	0	0
Total derivative assets — net	60.4	72.1	90.1
Derivative liabilities:
Total derivative liabilities — gross	(198.1)	(191.6)	(126.1)
Gross amounts offset in the balance sheet	27.2	29	34.3
Cash collateral pledged	11	29.3	10
Total derivative liabilities — net	(159.9)	(133.3)	(81.8)
Derivatives subject to PGC and DS mechanisms:
Derivative assets:
Total derivative assets — gross	0.2	1.4	1.3
Derivative liabilities:
Total derivative liabilities — gross	(3.2)	(3.7)	(0.5)
Derivatives designated as hedging instruments:
Derivative assets:
Total derivative assets — gross	16.6	17.4	2.3
Derivatives designated as hedging instruments: | Foreign currency contracts
Derivative assets:
Total derivative assets — gross	13.9	17.4	2.3
Derivatives designated as hedging instruments: | Interest rate contracts
Derivative assets:
Total derivative assets — gross	2.7	0	0
Derivative liabilities:
Total derivative liabilities — gross	(6.9)	(12.3)	(3.7)
Derivatives not designated as hedging instruments:
Derivative assets:
Total derivative assets — gross	72.9	82.3	120.8
Derivative liabilities:
Total derivative liabilities — gross	(188)	(175.6)	(121.9)
Derivatives not designated as hedging instruments: | Foreign currency contracts
Derivative assets:
Total derivative assets — gross	26	41.6	22.1
Derivative liabilities:
Total derivative liabilities — gross	(4.4)	(4.3)	(8.8)
Derivatives not designated as hedging instruments: | Commodity contracts
Derivative assets:
Total derivative assets — gross	46.9	40.7	98.7
Derivative liabilities:
Total derivative liabilities — gross	$ (183.6)	$ (171.3)	$ (113.1)

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, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	$ 7.8
Gain (Loss) Reclassified from AOCI into Income	(1)
Derivatives Not Designated as Hedging Instruments
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(41.8)	$ (154)
Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI		(1.9)
Gain (Loss) Reclassified from AOCI into Income		(1)
Forward foreign currency exchange contracts
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	0
Foreign currency contracts	(3.5)
Forward foreign currency exchange contracts | Cost of sales
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	0
Forward foreign currency exchange contracts | Derivatives Not Designated as Hedging Instruments | Other non-operating (expense) income, net
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(11.3)	8.9
Forward foreign currency exchange contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI		1
Forward foreign currency exchange contracts | Cash Flow Hedges | Cost of sales
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income		0.8
Forward foreign currency exchange contracts | Net Investment Hedges
Derivative Instruments, Gain (Loss)
Foreign currency contracts		0.9
Cross Currency Interest Rate Contract
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	0
Cross Currency Interest Rate Contract | Interest expense/other operating income, net
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	0
Cross Currency Interest Rate Contract | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI		(0.1)
Cross Currency Interest Rate Contract | Cash Flow Hedges | Interest expense/other operating income, net
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income		(0.3)
Interest rate contracts
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	7.8
Interest rate contracts | Interest expense
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	(1)
Interest rate contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI		(2.8)
Interest rate contracts | Cash Flow Hedges | Interest expense
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income		(1.5)
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Cost of sales
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(33.1)	(159.7)
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Revenues
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	2.5	(2.8)
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Operating and administrative expenses
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	$ 0.1	$ (0.4)

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	$ 3,827.2
Other comprehensive income (loss) before reclassification adjustments (after-tax)	52.6	$ (17.1)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	1.3	1.4
Reclassification adjustments tax benefit	(0.4)	(0.4)
Reclassification adjustments (after-tax)	0.9	1
Other comprehensive income (loss) attributable to UGI	53.5	(16.1)
Reclassification of stranded income tax effects related to TCJA		(6.6)
Balance, end of period	4,004.6	4,046.6
Postretirement Benefit Plans
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(25.7)	(11)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	0	0
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	0.3	0.4
Reclassification adjustments tax benefit	(0.1)	(0.1)
Reclassification adjustments (after-tax)	0.2	0.3
Other comprehensive income (loss) attributable to UGI	0.2	0.3
Reclassification of stranded income tax effects related to TCJA		(2.9)
Balance, end of period	(25.5)	(13.6)
Derivative Instruments
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(25.4)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	5.6
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	1
Reclassification adjustments tax benefit	(0.3)
Reclassification adjustments (after-tax)	0.7
Other comprehensive income (loss) attributable to UGI	6.3
Balance, end of period	(19.1)
Derivative Instruments
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period		(16.1)
Other comprehensive income (loss) before reclassification adjustments (after-tax)		(1.5)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)		1
Reclassification adjustments tax benefit		(0.3)
Reclassification adjustments (after-tax)		0.7
Other comprehensive income (loss) attributable to UGI		(0.8)
Reclassification of stranded income tax effects related to TCJA		(3.7)
Balance, end of period		(20.6)
Foreign Currency
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(165.5)	(83.3)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	47	(15.6)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	0	0
Reclassification adjustments tax benefit	0	0
Reclassification adjustments (after-tax)	0	0
Other comprehensive income (loss) attributable to UGI	47	(15.6)
Reclassification of stranded income tax effects related to TCJA		0
Balance, end of period	(118.5)	(98.9)
Total
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(216.6)	(110.4)
Amounts reclassified from AOCI:
Reclassification of stranded income tax effects related to TCJA		(6.6)
Balance, end of period	$ (163.1)	$ (133.1)

Segment Information - Narrative

Segment Information - Narrative (Details)	3 Months Ended
	Dec. 31, 2019segment
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, 2019	Dec. 31, 2018	Sep. 30, 2019
Segment Reporting Information [Line Items]
Revenues	$ 2,006.6	$ 2,200.2
Cost of sales	1,008	1,425
Operating income (loss)	377.2	167.7
Income from equity investees	6.5	1.5
Loss on extinguishments of debt	0	(6.1)
Other non-operating (expense) income, net	(11.5)	9
Earnings (loss) before interest expense and income taxes	372.2	172.1
Interest expense	(84.1)	(60.2)
Income before income taxes	288.1	111.9
Noncontrolling interests’ net income (loss)	0	24.3
Depreciation and amortization	119.4	111.2
Capital expenditures (including the effects of accruals)	151.8	161.8
Total assets	14,285.7	12,368.3	$ 13,346.6
Short-term borrowings	869.7	676.3	796.3
Goodwill	3,482.9	3,154.8	$ 3,456.4
Eliminations
Segment Reporting Information [Line Items]
Revenues	(79.7)	(111.6)
Cost of sales	(79.1)	(110.8)
Operating income (loss)	0.3	0.4
Income from equity investees	0	0
Loss on extinguishments of debt		0
Other non-operating (expense) income, net	0	0
Earnings (loss) before interest expense and income taxes	0.3	0.4
Interest expense	0	0
Income before income taxes	0.3	0.4
Noncontrolling interests’ net income (loss)		0
Depreciation and amortization	0	0
Capital expenditures (including the effects of accruals)	0	0
Total assets	(365.5)	(144.3)
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	64.2	86.9
Eliminations | UGI Utilities
Segment Reporting Information [Line Items]
Revenues	14.7	23.6
Corporate, Intersegment Eliminations & Other
Segment Reporting Information [Line Items]
Revenues	0.8	1.1
Operating Segments | AmeriGas Propane
Segment Reporting Information [Line Items]
Revenues	730.4	820.2
Cost of sales	289.2	378.5
Operating income (loss)	165.3	166.6
Income from equity investees	0	0
Loss on extinguishments of debt		0
Other non-operating (expense) income, net	0	0
Earnings (loss) before interest expense and income taxes	165.3	166.6
Interest expense	(42.5)	(42.4)
Income before income taxes	122.8	124.2
Noncontrolling interests’ net income (loss)		81.5
Depreciation and amortization	43.9	45.7
Capital expenditures (including the effects of accruals)	38.5	31
Total assets	4,609.4	4,020.6
Short-term borrowings	321	368.5
Goodwill	2,003	2,003
Operating Segments | UGI International
Segment Reporting Information [Line Items]
Revenues	651.4	710.7
Cost of sales	368.4	448.6
Operating income (loss)	95.8	58.3
Income from equity investees	0	0
Loss on extinguishments of debt		0
Other non-operating (expense) income, net	4.4	0.7
Earnings (loss) before interest expense and income taxes	100.2	59
Interest expense	(7.6)	(5.4)
Income before income taxes	92.6	53.6
Noncontrolling interests’ net income (loss)		0.1
Depreciation and amortization	31.2	31.4
Capital expenditures (including the effects of accruals)	20.3	27.8
Total assets	3,243.3	3,287.5
Short-term borrowings	181.3	1.8
Goodwill	956.8	951.9
Operating Segments | Midstream & Marketing
Segment Reporting Information [Line Items]
Revenues	372.5	459.4
Revenues	308.3	372.5
Cost of sales	264.2	377.5
Operating income (loss)	55.1	41.1
Income from equity investees	6.5	1.5
Loss on extinguishments of debt		0
Other non-operating (expense) income, net	0	0
Earnings (loss) before interest expense and income taxes	61.6	42.6
Interest expense	(11.5)	(0.5)
Income before income taxes	50.1	42.1
Noncontrolling interests’ net income (loss)		0
Depreciation and amortization	18.4	11.5
Capital expenditures (including the effects of accruals)	22.5	25.1
Total assets	2,859.6	1,504.9
Short-term borrowings	88.4	10
Goodwill	341	17.8
Operating Segments | UGI Utilities
Segment Reporting Information [Line Items]
Revenues	329.3	322.7
Revenues	314.6	299.1
Cost of sales	151.6	159.5
Operating income (loss)	91.8	77
Income from equity investees	0	0
Loss on extinguishments of debt		0
Other non-operating (expense) income, net	(0.2)	0.4
Earnings (loss) before interest expense and income taxes	91.6	77.4
Interest expense	(13.6)	(11.7)
Income before income taxes	78	65.7
Noncontrolling interests’ net income (loss)		0
Depreciation and amortization	25.7	22.5
Capital expenditures (including the effects of accruals)	70.5	77.3
Total assets	3,710.9	3,424.8
Short-term borrowings	279	296
Goodwill	182.1	182.1
Corporate & Other
Segment Reporting Information [Line Items]
Revenues	1.9	(2.3)
Cost of sales	13.7	171.7
Operating income (loss)	(31.1)	(175.7)
Income from equity investees	0	0
Loss on extinguishments of debt		(6.1)
Other non-operating (expense) income, net	(15.7)	7.9
Earnings (loss) before interest expense and income taxes	(46.8)	(173.9)
Interest expense	(8.9)	(0.2)
Income before income taxes	(55.7)	(174.1)
Noncontrolling interests’ net income (loss)		(57.3)
Depreciation and amortization	0.2	0.1
Capital expenditures (including the effects of accruals)	0	0.6
Total assets	228	274.8
Short-term borrowings	0	0
Goodwill	$ 0	0
Corporate & Other | AmeriGas Propane
Segment Reporting Information [Line Items]
Loss on extinguishments of debt		0
Corporate & Other | UGI International
Segment Reporting Information [Line Items]
Loss on extinguishments of debt		(6.1)
Corporate & Other | Midstream & Marketing
Segment Reporting Information [Line Items]
Loss on extinguishments of debt		$ 0

Segment Information - Corporate

Segment Information - Corporate and Other segment information (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Loss on extinguishments of debt	$ 0	$ (6.1)
Corporate & Other
Segment Reporting Information [Line Items]
Loss on extinguishments of debt		(6.1)
Corporate & Other | AmeriGas Propane
Segment Reporting Information [Line Items]
LPG business transformation expenses	(11.2)
Loss on extinguishments of debt		0
Corporate & Other | UGI International
Segment Reporting Information [Line Items]
LPG business transformation expenses	(5.5)
Loss on extinguishments of debt		(6.1)
Corporate & Other | Midstream & Marketing
Segment Reporting Information [Line Items]
LPG business transformation expenses	0
Loss on extinguishments of debt		0
Commodity contracts | Corporate & Other | AmeriGas Propane
Segment Reporting Information [Line Items]
Net gains (losses) on commodity derivative instruments not associated with current-period transactions	9.4	(78.5)
Commodity contracts | Corporate & Other | UGI International
Segment Reporting Information [Line Items]
Net gains (losses) on commodity derivative instruments not associated with current-period transactions	(13.5)	(97.3)
Commodity contracts | Corporate & Other | Midstream & Marketing
Segment Reporting Information [Line Items]
Net gains (losses) on commodity derivative instruments not associated with current-period transactions	(7.5)	1.8
Forward foreign currency exchange contracts | Corporate & Other | AmeriGas Propane
Segment Reporting Information [Line Items]
Net gains (losses) on commodity derivative instruments not associated with current-period transactions	0	0
Forward foreign currency exchange contracts | Corporate & Other | UGI International
Segment Reporting Information [Line Items]
Net gains (losses) on commodity derivative instruments not associated with current-period transactions	(15.7)	8.1
Forward foreign currency exchange contracts | Corporate & Other | Midstream & Marketing
Segment Reporting Information [Line Items]
Net gains (losses) on commodity derivative instruments not associated with current-period transactions	0	$ 0
Affiliated Entity | CMG | Pennant | Corporate & Other | AmeriGas Propane
Segment Reporting Information [Line Items]
Acquisition and integration expenses associated with the CMG Acquisition	0
Affiliated Entity | CMG | Pennant | Corporate & Other | UGI International
Segment Reporting Information [Line Items]
Acquisition and integration expenses associated with the CMG Acquisition	0
Affiliated Entity | CMG | Pennant | Corporate & Other | Midstream & Marketing
Segment Reporting Information [Line Items]
Acquisition and integration expenses associated with the CMG Acquisition	$ (0.7)

Global LPG Business Transform_2

Global LPG Business Transformation Initiatives (Details) $ in Millions	3 Months Ended
	Dec. 31, 2019USD ($)
Restructuring and Related Activities [Abstract]
Costs principally comprising consulting, advisory and employee-related costs	$ 16.7