UGI (UGI) 10-K 26 Nov 19 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Sep. 30, 2019	Nov. 19, 2019	Mar. 31, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Sep. 30, 2019
Document Transition Report	false
Entity File Number	1-11071
Entity Registrant Name	UGI CORP
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 Well-Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
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 Public Float			$ 9,601,543,818
Entity Common Stock, Shares Outstanding		209,011,039
Entity Central Index Key	0000884614
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--09-30

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018
Current assets
Cash and cash equivalents	$ 447.1	$ 452.6
Restricted cash	63.7	9.6
Accounts receivable (less allowances for doubtful accounts of $31.6 and $35.1, respectively)	640.7	751.9
Accrued utility revenues	14.6	14
Inventories	229.9	318.2
Utility regulatory assets	9.1	7.5
Derivative instruments	28.9	142.5
Prepaid expenses	72.2	130.2
Other current assets	60	61.6
Total current assets	1,566.2	1,888.1
Property, plant and equipment
Non-utility	6,134.9	5,345.8
Utility	3,938.1	3,616.3
Total property, plant and equipment	10,073	8,962.1
Accumulated depreciation	(3,385.2)	(3,153.9)
Net property, plant, and equipment	6,687.8	5,808.2
Goodwill	3,456.4	3,160.4
Intangible assets, net	708.6	513.6
Utility regulatory assets	386.5	293.5
Derivative instruments	43.2	43.5
Other assets	497.9	273.6
Total assets	13,346.6	11,980.9
Current liabilities
Current maturities of long-term debt	24.1	18.8
Short-term borrowings	796.3	424.9
Accounts payable	438.8	561.8
Employee compensation and benefits accrued	133	132.1
Deposits and advances	167.6	191.2
Derivative instruments	84.9	11.7
Accrued interest	62.9	60.7
Other current liabilities	319.3	330.9
Total current liabilities	2,026.9	1,732.1
Noncurrent liabilities
Long-term debt	5,779.9	4,146.5
Deferred income taxes	541.4	991.9
Derivative instruments	48.4	12.8
Other noncurrent liabilities	1,122.8	997.6
Total liabilities	9,519.4	7,880.9
Commitments and contingencies (Note 16)
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized – 450,000,000 shares; issued – 209,304,129 and 174,142,997 shares, respectively)	1,396.9	1,200.8
Retained earnings	2,653.1	2,610.7
Accumulated other comprehensive loss	(216.6)	(110.4)
Treasury stock, at cost	(15.9)	(19.7)
Total UGI Corporation stockholders’ equity	3,817.5	3,681.4
Noncontrolling interests	9.7	418.6
Total equity	3,827.2	4,100
Total liabilities and equity	$ 13,346.6	$ 11,980.9

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 31.6	$ 35.1
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	209,304,129	174,142,997

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Millions	3 Months Ended								12 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Income Statement [Abstract]
Revenues	$ 1,150.4	$ 1,363.7	$ 2,606.1	$ 2,200.2	$ 1,273.1	$ 1,440.9	$ 2,812	$ 2,125.2	$ 7,320.4	$ 7,651.2	$ 6,120.7
Costs and expenses:
Cost of sales (excluding depreciation and amortization shown below)									4,323.1	4,074.9	2,837.3
Operating and administrative expenses									1,963.2	2,012.8	1,867.6
Impairment of Partnership tradenames and trademarks									0	75	0
Depreciation and amortization									448.1	455.1	416.3
Other operating income, net									(31.1)	(31.3)	(10.5)
Total costs and expenses									6,703.3	6,586.5	5,110.7
Operating income	(99)	9.6	538.8	167.7	49.2	29.5	591	395	617.1	1,064.7	1,010
Income from equity investees									9.1	4.3	4.3
Loss on extinguishments of debt				(4.2)					(6.1)	0	(59.7)
Other non-operating income (expense), net									38.2	15.6	(29.7)
Interest expense									(257.8)	(230.1)	(223.5)
Income before income taxes									400.5	854.5	701.4
Income tax expense									(92.6)	(32.1)	(177.6)
Net income including noncontrolling interests	(130.8)	(46.5)	396.7	88.5	(7.8)	(11.7)	407.7	434.2	307.9	822.4	523.8
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners									(51.7)	(103.7)	(87.2)
Net income attributable to UGI Corporation	$ (51.5)	$ (1.9)	$ 245.4	$ 64.2	$ 24.4	$ 52.4	$ 276	$ 365.9	$ 256.2	$ 718.7	$ 436.6
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)	$ (0.27)	$ (0.01)	$ 1.41	$ 0.37	$ 0.14	$ 0.30	$ 1.59	$ 2.11	$ 1.44	$ 4.13	$ 2.51
Diluted (in dollars per share)	$ (0.27)	$ (0.01)	$ 1.38	$ 0.36	$ 0.14	$ 0.30	$ 1.57	$ 2.07	$ 1.41	$ 4.06	$ 2.46
Weighted-average common shares outstanding:
Basic (in shares)	189,905	174,759	174,501	174,413	174,391	173,991	173,570	173,670	178,417	173,908	173,662
Diluted (in shares)	189,905	174,759	177,318	177,566	177,506	176,807	176,350	176,948	181,111	176,905	177,159
Dividends declared per common share (in dollars per share)									$ 1.145	$ 1.02	$ 0.975

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income including noncontrolling interests	$ 307.9	$ 822.4	$ 523.8
Net (losses) gains on derivative instruments (net of tax of $3.2, $(0.8), and $(0.5), respectively)	(7.3)	1	1.7
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(0.7), $(2.6), and $4.1, respectively)	1.7	4.3	(9.7)
Foreign currency translation adjustments (net of tax of $(13.3), $(0.5), and $(0.6), respectively)	(23.2)	(21.4)	34.6
Foreign currency (losses) gains on long-term intra-company transactions	(59)	(9.1)	24.8
Benefit plans, principally actuarial (losses) gains net of tax of $5.4, $(5.2), and $(3.8), respectively)	(13)	10.4	6.5
Reclassifications of benefit plans actuarial losses and net prior service benefit (net of tax of $(0.5), $1.1, and $(2.1), respectively)	1.2	(2.2)	3.4
Other comprehensive (loss) income	(99.6)	(17)	61.3
Comprehensive income including noncontrolling interests	208.3	805.4	585.1
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	(51.7)	(103.7)	(87.2)
Comprehensive income attributable to UGI Corporation	$ 156.6	$ 701.7	$ 497.9

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net (losses) gains on derivative instruments, tax	$ 3.2	$ (0.8)	$ (0.5)
Reclassifications of net losses (gains) on derivative instruments, tax	(0.7)	(2.6)	4.1
Foreign currency translation adjustments, tax	(13.3)	(0.5)	(0.6)
Benefit plans, principally actuarial (losses) gains, tax	5.4	(5.2)	(3.8)
Reclassifications of benefit plans actuarial losses and net prior service benefit, tax	$ (0.5)	$ 1.1	$ (2.1)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income including noncontrolling interests	$ 307.9	$ 822.4	$ 523.8
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization	448.1	455.1	416.3
Deferred income tax (benefit) expense, net	(42.7)	(68.8)	110.1
Provision for uncollectible accounts	28.6	35.6	30.7
Changes in unrealized gains and losses on derivative instruments	258.1	(132.8)	(82)
Impairment of Partnership tradenames and trademarks	0	75	0
Equity-based compensation expense	18.1	22.5	19.3
Loss on extinguishments of debt	6.1	0	59.7
Income from equity investees	(9.1)	(4.3)	(4.3)
Loss on private equity partnership investment	1.5	0	11
Other, net	9.1	11.1	40.4
Net change in:
Accounts receivable and accrued utility revenues	83.3	(147.6)	(103.6)
Inventories	84.1	(37.4)	(64.7)
Utility deferred fuel costs, net of changes in unsettled derivatives	(29.5)	31.1	(15.4)
Accounts payable	(97.2)	65.1	49.9
Derivative instruments collateral (paid) received	(41.5)	3.9	8
Other current assets	44.6	(26.6)	(37.5)
Other current liabilities	8.6	(19)	2.7
Net cash provided by operating activities	1,078.1	1,085.3	964.4
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(704.6)	(574.4)	(638.9)
Acquisitions of businesses and assets, net of cash and restricted cash acquired	(1,362.2)	(187.2)	(100.8)
Other, net	11.5	13	(29)
Net cash used by investing activities	(2,055.3)	(748.6)	(768.7)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(199.5)	(176.9)	(168.9)
Distributions on AmeriGas Partners publicly held Common Units	(263.1)	(263)	(261.6)
Issuances of debt, net of issuance costs	2,411.7	124.4	1,307.1
Repayments of debt, including redemption premiums	(737.8)	(149.1)	(1,064.8)
Receivables Facility net borrowings (repayments)	44.4	(37)	13.5
Increase in short-term borrowings	327	93.5	61.2
Issuances of UGI Common Stock	16.8	34.9	11
Repurchases of UGI Common Stock	(16.9)	(59.8)	(43.3)
Cash paid for AmeriGas Merger	(528.9)	0	0
Other	(11.5)	(5.2)	(0.8)
Net cash provided (used) by financing activities	1,042.2	(438.2)	(146.6)
Effect of exchange rate changes on cash, cash equivalents and restricted cash	(16.4)	(5)	1.2
Cash, cash equivalents and restricted cash increase (decrease)	48.6	(106.5)	50.3
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Cash, cash equivalents and restricted cash at end of period	510.8	462.2	568.7
Cash, cash equivalents and restricted cash at beginning of period	462.2	568.7	518.4
Cash, cash equivalents and restricted cash increase (decrease)	48.6	(106.5)	50.3
Cash paid for:
Interest	248.4	221.7	202.1
Income taxes	$ 74.1	$ 118	$ 98

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Millions	Total	Total UGI Corporation stockholders’ equity	Common stock, without par value	Retained earnings	Accumulated other comprehensive income (loss)	Treasury stock	Noncontrolling interests
Balance, beginning of year at Sep. 30, 2016			$ 1,201.6	$ 1,834.1	$ (154.7)	$ (36.9)	$ 750.9
Common stock issued:
Employee and director plans (including losses on treasury stock transactions), net of tax withheld			(28.2)
Employee and director plans, net of tax withheld						49.6
Equity-based compensation expense			13.2
Net income including noncontrolling interests	$ 523.8			436.6			87.2
Cash dividends on common stock ($1.145, $1.02, and $0.975 per share, respectively)				(168.9)
Reclassification of stranded income tax effects related to TCJA				0	0
Losses on treasury stock transactions in connection with employee and director plans				0
Net (losses) gains on derivative instruments	1.7				1.7
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(0.7), $(2.6), and $4.1, respectively)	(9.7)				(9.7)
Benefit plans, principally actuarial (losses) gains	6.5				6.5
Reclassification of benefit plans actuarial losses and net prior service benefits	3.4				3.4
Foreign currency (losses) gains on long-term intra-company transactions	24.8				24.8
Foreign currency translation adjustments	34.6				34.6
Repurchases of common stock						(43.3)
Reacquired common stock – employee and director plans						(8.2)
Sale of treasury stock			2			0.2
Dividends and distributions							(261.6)
AmeriGas Merger-related adjustments			0				0
Other							1.1
Balance, end of year at Sep. 30, 2017	3,740.9	$ 3,163.3	1,188.6	2,106.7	(93.4)	(38.6)	577.6
Common stock issued:
Employee and director plans (including losses on treasury stock transactions), net of tax withheld			(1.5)
Employee and director plans, net of tax withheld						86.5
Equity-based compensation expense			13.7
Net income including noncontrolling interests	822.4			718.7			103.7
Cash dividends on common stock ($1.145, $1.02, and $0.975 per share, respectively)				(176.9)
Reclassification of stranded income tax effects related to TCJA				0	0
Losses on treasury stock transactions in connection with employee and director plans				(37.8)
Net (losses) gains on derivative instruments	1				1
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(0.7), $(2.6), and $4.1, respectively)	4.3				4.3
Benefit plans, principally actuarial (losses) gains	10.4				10.4
Reclassification of benefit plans actuarial losses and net prior service benefits	(2.2)				(2.2)
Foreign currency (losses) gains on long-term intra-company transactions	(9.1)				(9.1)
Foreign currency translation adjustments	(21.4)				(21.4)
Repurchases of common stock						(59.8)
Reacquired common stock – employee and director plans						(7.8)
Sale of treasury stock			0			0
Dividends and distributions							(263.3)
AmeriGas Merger-related adjustments			0				0
Other							0.6
Balance, end of year at Sep. 30, 2018	4,100	3,681.4	1,200.8	2,610.7	(110.4)	(19.7)	418.6
Balance, beginning of year at Sep. 30, 2018	4,100	3,681.4	1,200.8	2,610.7	(110.4)	(19.7)	418.6
Common stock issued:
Employee and director plans (including losses on treasury stock transactions), net of tax withheld			11.2
Employee and director plans, net of tax withheld						23.5
Equity-based compensation expense			14.6
Net income including noncontrolling interests	307.9			256.2			51.7
Cash dividends on common stock ($1.145, $1.02, and $0.975 per share, respectively)				(199.5)
Reclassification of stranded income tax effects related to TCJA				6.6	(6.6)
Losses on treasury stock transactions in connection with employee and director plans				(13.8)
Net (losses) gains on derivative instruments	(7.3)				(7.3)
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(0.7), $(2.6), and $4.1, respectively)	1.7				1.7
Benefit plans, principally actuarial (losses) gains	(13)				(13)
Reclassification of benefit plans actuarial losses and net prior service benefits	1.2				1.2
Foreign currency (losses) gains on long-term intra-company transactions	(59)				(59)
Foreign currency translation adjustments	(23.2)				(23.2)
Repurchases of common stock						(16.9)
Reacquired common stock – employee and director plans						(2.8)
Sale of treasury stock			0			0
Dividends and distributions							(263.1)
AmeriGas Merger-related adjustments			170.3				(198.7)
Other							1.2
Balance, end of year at Sep. 30, 2019	$ 3,827.2	$ 3,817.5	$ 1,396.9	2,653.1	$ (216.6)	$ (15.9)	$ 9.7
Common stock issued:
Cumulative effect of change in accounting | ASC 606				(7.1)
Cumulative effect of change in accounting | Employee share-based payments				$ 0

CONSOLIDATED STATEMENTS OF CH_2

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Statement of Stockholders' Equity [Abstract]
Cash dividends on common stock (in dollars per share)	$ 1.145	$ 1.02	$ 0.975

Nature of Operations

Nature of Operations	12 Months Ended
	Sep. 30, 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 other 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 April 1, 2019, we entered into the Merger Agreement pursuant to which we agreed to merge the Partnership with and into Merger Sub, an indirect wholly owned subsidiary of UGI, with the Partnership as the surviving entity. On August 21, 2019, the AmeriGas Merger was completed and we issued 34.6 million shares of UGI Common Stock and paid $528.9 in cash to acquire all of the outstanding AmeriGas Partners Common Units representing limited partnership interests in AmeriGas Partners not already held by UGI or its subsidiaries. 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, and held an effective 27% 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 (see Note 15 ). For additional information on the AmeriGas Merger, see Note 5. 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. 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. On August 1, 2019, Energy Services completed the CMG Acquisition in which it acquired all of the equity interests in CMG and CMG’s approximately 47% interest in Pennant. CMG and its direct and indirect subsidiaries provide natural gas gathering and processing services through five discrete gathering systems located in western Pennsylvania, eastern Ohio and the panhandle of West Virginia (see Note 5 ). 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. Prior to the Utility Merger on October 1, 2018, Gas Utility also conducted operations through PNG and CPG. UGI Utilities also owns and operates Electric Utility, an electric distribution utility in northeastern Pennsylvania. Gas Utility is subject to regulation by the PAPUC and, with respect to a small service territory in one Maryland county, the MDPSC. Electric Utility is subject to regulation by the PAPUC and the FERC.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Sep. 30, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2 — Summary of Significant Accounting Policies Basis of Presentation Our consolidated financial statements are prepared in accordance with GAAP. 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. Certain prior-year amounts have been reclassified to conform to the current-year presentation. Principles of Consolidation The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which are majority owned. We report outside ownership interests in other consolidated but less than 100% -owned subsidiaries, as noncontrolling interests. Prior to the AmeriGas Merger, we also reported the public’s interest in the Partnership as a noncontrolling interest. We eliminate intercompany accounts and transactions when we consolidate. 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. Investments in equity securities related to such entities in which we do not have significant influence over operating and financial policies are valued at their cost less impairment (if any). Our investments in such entities totaled $242.4 and $147.2 at September 30, 2019 and 2018 , respectively, and are included in “ Other assets ” on the Consolidated Balance Sheets. On August 1, 2019, Energy Services completed the CMG Acquisition including CMG’s approximately 47% interest in Pennant. Pennant is considered to be an equity method investment as we have the ability to exercise significant influence, but not control, over Pennant. Our investment in Pennant at September 30, 2019 totaled $90.8 . For additional information regarding the CMG Acquisition, see Note 5 . An indirect wholly owned subsidiary of UGI, 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. PennEast was formed to construct an approximate 120 -mile natural gas pipeline from Luzerne County, Pennsylvania to the Trenton-Woodbury interconnection in New Jersey. Affiliates of all members plan to be customers of the pipeline under 15 -year contracts. PennEast is considered to be an equity method investment as we have the ability to exercise significant influence, but not control, over PennEast. We are obligated to provide capital contributions based upon our ownership percentage. Our investment in PennEast at September 30, 2019 and 2018 totaled $84.7 and $72.6 , respectively. 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. PennEast has filed a petition for declaratory order with the FERC regarding interpretation of the Natural Gas Act. 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. Effects of Regulation UGI Utilities accounts for the financial effects of regulation in accordance with the FASB’s guidance in ASC 980, “Regulated Operations.” In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered through rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator. For additional information regarding the effects of rate regulation on our utility operations, see Note 9 . Fair Value Measurements The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements performed on a recurring basis principally relate to derivative instruments and investments held in supplemental executive retirement plan grantor trusts. GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels: • Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. • Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. • Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments. Derivative Instruments Derivative instruments are reported on the 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 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 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 18 . 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. Foreign Currency Translation Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income. Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise with the impact of subsequent changes in such rates reflected in the income statement. The functional currency of a significant portion of our international operations is the euro. Revenue Recognition Effective October 1, 2018, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers,” which, as amended, is included in ASC 606. This new accounting guidance supersedes previous revenue recognition requirements in ASC 605. ASC 606 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We adopted this new accounting guidance using the modified retrospective transition method to those contracts which were not completed as of October 1, 2018. Periods prior to October 1, 2018, have not been restated and continue to be reported in accordance with ASC 605. The Company recorded a $7.1 reduction to opening retained earnings as of October 1, 2018, to reflect the cumulative effect of ASC 606 on certain contracts not complete as of the date of adoption. The adoption of ASC 606 did not, and is not expected to, have a material impact on the amount or timing of our revenue recognition and on our consolidated net income, cash flows or financial position. Certain revenues such as revenue from leases, financial instruments and other revenues are not within the scope of ASC 606 because they are not from contracts with customers. Such revenues are accounted for in accordance with other GAAP. Revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, are not included in revenues. Gross receipts taxes at Midstream & Marketing and Electric Utility are presented on a gross basis. The Company has elected to use the practical expedient to expense the costs to obtain contracts when incurred for contracts that have a term less than one year . The costs incurred to obtain contracts that have durations of longer than one year are not material. See Note 4 for additional disclosures regarding the Company’s revenue from contracts with customers. Accounts Receivable Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible. LPG Delivery Expenses Expenses associated with the delivery of LPG to customers of the Partnership and our UGI International operations (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as “ Operating and administrative expenses ” on the Consolidated Statements of Income. Depreciation expense associated with the Partnership and UGI International delivery vehicles is classified in “ Depreciation and amortization ” on the Consolidated Statements of Income. Income Taxes AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss and (2) the differences between the book and tax basis of our investment in the Partnership. AmeriGas OLP has subsidiaries which operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation. For additional information regarding the tax effects of the AmeriGas Merger, see Note 7 . UGI Utilities records deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax depreciation methods based upon amounts recognized for ratemaking purposes. UGI Utilities also records a deferred income tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and records a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse. We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. At September 30, 2019 and 2018 , such deferred investment tax credits totaled $2.3 and $ 2.6 , respectively. We record interest on underpayments and overpayments of income taxes, and income tax penalties, in “ Income tax expense ” on the Consolidated Statements of Income. For Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , interest income or expense recognized in “ Income tax expense ” on the Consolidated Statements of Income was not material. The TCJA was enacted on December 22, 2017, and included a broad range of tax reform provisions affecting the Company, including, among other things, changes in the U.S. corporate income tax rate. The TCJA reduced the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. We were subject to a 24.5% blended U.S. federal income tax rate for Fiscal 2018 because our fiscal year contained the effective date of the rate change from 35% to 21% . In accordance with GAAP, at the date of enactment of the TCJA our federal deferred income taxes, including deferred income taxes related to items included in AOCI, were remeasured based upon the new corporate income tax rate. For our non-utility businesses, existing deferred income tax assets or liabilities were adjusted for the reduction in the corporate income tax rate and the adjustment recorded in the provision for income taxes. Our utility businesses were also required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, because it was probable that the effect of the change in income tax rates on deferred income tax balances would be recovered or refunded in future rates, our rate-regulated utility businesses recorded a regulatory asset or liability associated with these deferred income tax assets and liabilities. For additional information regarding the impact of the TCJA and associated regulatory effects, see Notes 7 and 9 . Other Non-Operating Income (Expense), Net Included in “ Other non-operating income (expense), net ,” on the Consolidated Statements of Income are net gains (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. Other non-operating income (expense), net comprises the following: 2019 2018 2017 Gains (losses) on foreign currency contracts, net $ 37.7 $ 16.2 $ (23.9 ) Pension and other postretirement plans non-service income (expense), net 0.5 (0.6 ) (5.8 ) Total other non-operating income (expense), net $ 38.2 $ 15.6 $ (29.7 ) Earnings Per Common Share Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2019 , Fiscal 2018 and Fiscal 2017 : (Thousands of shares) 2019 2018 2017 Weighted-average common shares outstanding for basic computation (a) 178,417 173,908 173,662 Incremental shares issuable for stock options and common stock awards (b) 2,694 2,997 3,497 Weighted-average common shares outstanding for diluted computation 181,111 176,905 177,159 (a) Fiscal 2019 includes the partial-year impact from the August 2019 issuance of 34,613 shares of UGI Common Stock in connection with the AmeriGas Merger (see Note 5 ). (b) For Fiscal 2019 and Fiscal 2017 , there were 1,162 shares and 146 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive. Cash, Cash Equivalents and Restricted Cash Cash and cash equivalents include cash on hand, cash in banks and highly liquid investments with maturities of three months or less when purchased. 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 Consolidated Balance Sheets to the corresponding amounts reported on the Consolidated Statements of Cash Flows. Cash, Cash Equivalents and Restricted Cash September 30, 2019 September 30, 2018 September 30, 2017 September 30, 2016 Cash and cash equivalents $ 447.1 $ 452.6 $ 558.4 $ 502.8 Restricted cash 63.7 9.6 10.3 15.6 Cash, cash equivalents and restricted cash $ 510.8 $ 462.2 $ 568.7 $ 518.4 Inventories Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for non-utility LPG and natural gas and Gas Utility natural gas; specific identification for appliances; and the FIFO method for all other inventories. Property, Plant and Equipment and Related Depreciation We record property, plant and equipment at the lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs, and for certain operations subject to cost-of-service rate regulation, AFUDC. We also include in property, plant and equipment costs associated with computer software we develop or obtain for use in our business. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition. When we retire or otherwise dispose of non-utility plant and equipment, we eliminate the associated cost and accumulated depreciation and recognize any resulting gain or loss in " Other operating income, net " on the Consolidated Statements of Income. We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives. At September 30, 2019 , estimated useful lives by asset type were as follows: Asset Type Minimum Estimated Useful Life (in years) Maximum Estimated Useful Life (in years) Buildings and improvements 10 40 Equipment, primarily cylinders and tanks 5 30 Electricity generation facilities 25 40 Pipeline and related assets 25 40 Transportation equipment and office furniture and fixtures 3 10 Computer software 1 10 We record depreciation expense for UGI Utilities’ plant and equipment on a straight-line basis based upon the projected service lives of the various classes of its depreciable property. The average composite depreciation rates at our Gas Utility and Electric Utility for Fiscal 2019 , Fiscal 2018 and Fiscal 2017 were as follows: 2019 2018 2017 Gas Utility 2.2 % 2.3 % 2.2 % Electric Utility 2.1 % 2.2 % 2.4 % UGI Utilities’ IT costs associated with major IT system installations, conversions and improvements, such as software training, data conversion, business process reengineering costs, preliminary project stage costs and cloud computing, are deferred as a regulatory asset and included as a component of property, plant and equipment. As of September 30, 2019 and 2018 , such costs deferred as a regulatory asset and not yet requested in a rate proceeding totaled $3.7 and $6.3 , respectively. UGI Utilities amortizes computer software and related IT system installation costs on a straight-line basis over expected periods of benefit not exceeding 15 years once the installed software is ready for its intended use. We classify amortization of computer software and related IT system installation costs included in property, plant and equipment as depreciation expense. Depreciation expense totaled $388.5 , $396.5 and $365.5 for Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , respectively. For property subject to cost of service rate regulation including substantially all of UGI Utilities depreciable utility plant and equipment, upon retirement we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets and amortized over five years , consistent with prior ratemaking treatment. No depreciation expense is included in cost of sales on the Consolidated Statements of Income. Goodwill and Intangible Assets Intangible Assets. We amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. No amortization expense of intangible assets is included in cost of sales on the Consolidated Statements of Income (see Note 12 ). Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships (other than customer relationships acquired in the CMG Acquisition), certain tradenames and noncompete agreements, generally do not exceed 15 years . The estimated useful lives of customer relationships acquired in the CMG Acquisition is 35 years (see Note 5 ). We review definite-lived intangible assets for impairment whenever events or changes in circumstances indicate that the associated carrying amounts may not be recoverable. Determining whether an impairment loss occurred requires comparing the carrying amount to the sum of undiscounted cash flows expected to be generated by the asset. Intangible assets with indefinite lives are not amortized but are tested for impairment annually (and more frequently if events or changes in circumstances between annual tests indicate that it is more likely than not that they are impaired) and written down to fair value, if impaired. During Fiscal 2018, the Partnership recorded a non-cash, pre-tax impairment charge of $75.0 which amount is reflected in “ Impairment of Partnership tradenames and trademarks ” on the Consolidated Statements of Income, and is amortizing the remaining fair value of these tradenames and trademarks of $7.9 over their estimated period of benefit of three years . For further information on these tradenames and trademarks, see Note 12 . Goodwill. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is an operating segment, or a business one level below an operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. Each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. For certain of our reporting units with goodwill, we assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. For our other reporting units with goodwill, we bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit. There were no accumulated goodwill impairment losses at September 30, 2019 and 2018 , and no provisions for goodwill impairments were recorded during Fiscal 2019 , Fiscal 2018 or Fiscal 2017 . For further information on our goodwill and intangible assets, see Note 12 . Impairment of Long-Lived Assets We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. If the undiscounted future cash flows indicate that the recorded amounts are not expected to be recoverable, such long-lived assets are reduced to their estimated fair values. No material provisions for impairments of long-lived assets were recorded during Fiscal 2019 , Fiscal 2018 or Fiscal 2017 . Debt Issuance Costs We defer and amortize debt issuance costs and debt premiums and discounts over the expected lives of the respective debt issues considering maturity dates. Deferred debt issuance costs associated with long-term debt are reflected as a direct deduction from the carrying amount of such debt. Deferred debt issuance costs associated with revolving credit facilities reflected as short-term borrowings are classified as “ Other assets ” on our Consolidated Balance Sheets. Amortization of debt issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt prior to their stated maturity are generally recognized and recorded in “Loss on extinguishments of debt” on the Consolidated Statements of Income. As permitted by regulatory authorities, gains or losses resulting from refinancings of UGI Utilities’ debt are deferred and amortized over the lives of the new issuances. Refundable Tank and Cylinder Deposits Included in “ Other noncurrent liabilities ” on our Consolidated Balance Sheets are customer paid deposits on tanks and cylinders primarily owned by subsidiaries of UGI France of $279.7 and $272.0 at September 30, 2019 and 2018 , respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms. Environmental Matters We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites. Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Amounts recorded as environmental liabilities on the Consolidated Balance Sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. These estimates are based upon a number of factors including whether the company will be responsible for such remediation, the scope and cost of the remediation work to be performed, the portion of costs that will be shared with other potentially responsible parties, the timing of the remediation and possible impact of changes in technology, and the regulations and requirements of local governmental authorities. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. Under GAAP, if the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, such liabilities are discounted to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Utilities receives ratemaking recognition of environmental investigation and r

Accounting Changes

Accounting Changes	12 Months Ended
	Sep. 30, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Changes	Note 3 — Accounting Changes New Accounting Standards Adopted in Fiscal 2019 Revenue Recognition. Effective October 1, 2018, the Company adopted new accounting guidance regarding revenue recognition. See Notes 2 and 4 for a detailed description of the impact of the new guidance and related disclosures. Cloud Computing Implementation Costs. In August 2018, the FASB issued ASU No. 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.” The new guidance requires a customer in a cloud computing arrangement that is a service contract to capitalize certain implementation costs as if the arrangement was an internal-use software project. These deferred implementation costs are expensed over the fixed, noncancelable term of the service arrangement plus any reasonably certain renewal periods. The new guidance also requires the entity to present the expense related to the capitalized implementation costs in the same income statement line as the hosting service fees; to classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments for hosting service fees; and to present the capitalized implementation costs in the balance sheet in the same line item in which prepaid hosting service fees are presented. We adopted this ASU effective October 1, 2018, and applied the guidance prospectively to all implementation costs associated with cloud computing arrangements that are service contracts incurred beginning October 1, 2018. As UGI Utilities receives rate recovery for cloud computing implementation costs, such costs will continue to be deferred as a regulatory asset and included as a component of property, plant, and equipment. The adoption of the new guidance did not have a material impact on our results of operations during Fiscal 2019. Stranded Tax Effects in Accumulated Other Comprehensive Income. In February 2018, the FASB issued ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU provides that the stranded tax effects in AOCI resulting from the remeasurement of deferred income taxes associated with items included in AOCI due to the enactment of the TCJA may be reclassified to retained earnings, at the election of the entity, in the period the ASU is adopted. We adopted this ASU effective October 1, 2018. In connection with the adoption of this guidance, we reclassified a benefit of $6.6 from AOCI to opening retained earnings as of October 1, 2018, to reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of AOCI. Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit cost and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization, when applicable. For entities subject to rate regulation, including UGI Utilities, the ASU recognized that in the event a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of a regulatory asset or liability. We adopted this ASU effective October 1, 2018, with retrospective adoption for the presentation of pension and postretirement expense on the income statement and a prospective adoption for capitalization, as required by the ASU. The adoption of the new standard did not have a material impact on our financial statements. Statement of Cash Flows - Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” The guidance in this ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, as well as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents are included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statement of cash flows. We adopted this ASU effective October 1, 2018 with retrospective adoption as required by the ASU. Pension and Other Postretirement Benefit Costs Disclosures. In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. We adopted this ASU during the fourth quarter of Fiscal 2019 and applied the new guidance retrospectively for all periods presented in the financial statements. The adoption of the new guidance did not have a material impact on the Company’s financial statement disclosures. Fair Value Measurements Disclosures. In August 2018, the FASB issued ASU No. 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. We adopted this ASU during the fourth quarter of Fiscal 2019. The guidance regarding removing and modifying disclosures was adopted on a retrospective basis and the guidance regarding new disclosures has been adopted on a prospective basis. The adoption of the new guidance did not have a material impact on the Company’s financial statement disclosures. New Accounting Standards Adopted Effective October 1, 2019 Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required prospectively. The Company adopted the new guidance effective October 1, 2019. We do not expect the adoption of this new guidance will have a material impact on our financial statements. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements unless an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption. We adopted this ASU, as updated, effective October 1, 2019, using the transition method which allows the Company to maintain historical presentation for periods before October 1, 2019. The Company elected to apply the following practical expedients: • Short-term leases: We have excluded short-term leases (term of 12 months or less) from balance sheet presentation. • Easements: We did not re-evaluate existing land easements that were not previously accounted for as leases. • 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 this new guidance. We enhanced controls and processes and implemented a new lease system that will enable the accumulation and presentation of financial information as required by the new standard. We continue to finalize our implementation efforts and estimate that the adoption will result in the recognition of approximately $400 to $600 of offsetting operating lease right-of-use assets and operating lease liabilities associated with operating leases in effect at the date of adoption. We do not expect the adoption to have a material impact on the consolidated statements of income or cash flows. Accounting Standard Not Yet Adopted Credit Losses. In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments. ” This ASU 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 loss for 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 and determining the period in which the new guidance will be adopted.

Revenue from Contract with Cust

Revenue from Contract with Customers	12 Months Ended
	Sep. 30, 2019
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer	Note 4 — Revenue from Contracts with Customers The Company recognizes revenue when control of promised goods or services is transferred to its customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The Company generally has the right to consideration from a customer in an amount that corresponds directly with the value to the customer for performance completed to date. As such, we have elected to recognize revenue in the amount to which we have a right to invoice except in the case of certain of UGI Utilities’ large delivery service customers and Midstream & Marketing’s peaking contracts for which we recognize revenue on a straight-line basis over the term of the contract, consistent with when the performance obligations are satisfied by the Company. We do not have a significant financing component in our contracts because we receive payment shortly before, at, or shortly after the transfer of control of the good or service. Because the period between the time the performance obligation is satisfied and payment is received is generally one year or less, the Company has elected to apply the significant financing component practical expedient and no amount of consideration has been allocated as a financing component. The Company’s revenues from contracts with customers are discussed below. Utility Revenues UGI Utilities supplies natural gas and electricity and provides distribution services of natural gas and electricity to residential, commercial, and industrial customers who are generally billed at standard regulated tariff rates approved by the PAPUC through the ratemaking process. Tariff rates include a component that provides for a reasonable opportunity to recover operating costs and expenses and to earn a return on net investment, and a component that provides for the recovery, subject to reasonableness reviews, of PGC and DS costs. Customers may choose to purchase their natural gas and electricity from Gas Utility or Electric Utility, or, alternatively, may contract separately with alternate suppliers. Accordingly, our contracts with customers comprise two promised goods or services: (1) delivery service of natural gas and electricity through the Company’s utility distribution systems and (2) the natural gas or electricity commodity itself for those customers who choose to purchase the natural gas or electricity directly from the Company. Revenue is not recorded for the sale of natural gas or electricity to customers who have contracted separately with alternate suppliers. For those customers who choose to purchase their natural gas or electricity from the Company, the performance obligation includes both the supply of the commodity and the delivery service. The terms of our core market customer contracts are generally considered day-to-day as customers can discontinue service at any time without penalty. Performance obligations are generally satisfied over time as the natural gas or electricity is delivered to customers, at which point the customers simultaneously receive and consume the benefits provided by the delivery service and, when applicable, the commodity. Amounts are billed to customers based upon the reading of a customer’s meter, which occurs on a cycle basis throughout each reporting period. An unbilled amount is recorded at the end of each reporting period based upon estimated amounts of natural gas or electricity delivered to customers since the date of the last meter reading. These unbilled estimates consider various factors such as historical customer usage patterns, customer rates and weather. UGI Utilities has certain fixed-term contracts with large commercial and industrial customers to provide natural gas delivery services at contracted rates and at volumes generally based on the customer’s needs. The performance obligation to provide the contracted delivery service for these large commercial and industrial customers is satisfied over time and revenue is generally recognized on a straight-line basis. UGI Utilities makes off-system sales whereby natural gas delivered to our system in excess of amounts needed to fulfill our distribution system needs is sold to other customers, primarily other distributors of natural gas, based on an agreed-upon price and volume between the Company and the counterparty. Gas Utility also sells excess capacity whereby interstate pipeline capacity in excess of amounts needed to meet our customer obligations is sold to other distributors of natural gas based upon an agreed-upon rate. Off-system sales and capacity releases are generally entered into one month at a time and comprise the sale of a specific volume of gas or pipeline capacity at a specific delivery point or points over a specific time. As such, performance obligations associated with off-system sales and capacity release customers are satisfied, and associated revenue is recorded, when the agreed upon volume of natural gas is delivered or capacity is provided, and title is transferred, in accordance with the contract terms. Electric Utility provides transmission services to PJM by allowing PJM to access Electric Utility’s electricity transmission facilities. In exchange for providing access, PJM pays Electric Utility consideration determined by a formula-based rate approved by FERC. The formula-based rate, which is updated annually, allows recovery of costs incurred to provide transmission services and return on transmission-related net investment. We recognize revenue over time as we provide transmission service. Other Utility revenues represent revenues from other ancillary services provided to customers and are generally recorded as the service is provided to customers. Non-Utility Revenues LPG . AmeriGas Propane and UGI International record revenue principally from the sale of LPG to retail and wholesale customers. The primary performance obligation associated with the sale of LPG is the delivery of propane to (1) the customer’s point of delivery for retail customers and (2) the customer’s specified location where LPG is picked up by wholesale customers, at which point control of the propane is transferred to the customer, the performance obligation is satisfied, and the associated revenue is recognized. For contracts with retail customers that consume LPG from a metered tank, we recognize revenue as LPG is consumed, at which point we have the right to invoice, and generally invoice monthly based on consumption. Contracts with customers comprise different types of contracts with varying length terms, fixed or variable prices, and fixed or variable quantities. Contracts with our residential customers, which comprise a substantial number of our customer contracts, are generally one year or less. Customer contracts for the sale of LPG include fixed-price, fixed-quantity contracts under which LPG is provided to customers at a fixed price and a fixed volume, and contracts that provide for the sale of propane at market prices at date of delivery with no fixed volumes. AmeriGas Propane offers contracts that permit customers to lock in a fixed price for their volumes for a fee and also provide customers with the option to pre-buy a fixed amount of propane at a fixed price. Amounts received under pre-buy arrangements are recorded as a contract liability when received and recorded as revenue when LPG is delivered and control is transferred to the customer. Fees associated with fixed-price contracts are recorded as contract liabilities and recorded ratably over the contract period. AmeriGas Propane and UGI International also distribute LPG to customers in portable cylinders. Under certain contracts, filled cylinders are delivered, and control is transferred, to a reseller. In such instances, the reseller is our customer and we record revenue upon delivery to the reseller. Under other contracts, filled cylinders are delivered to a reseller, but the Company retains control of the cylinders. In such instances, we record revenue at the time the reseller transfers control of the cylinder to the end user. Certain retail LPG customers for AmeriGas Propane receive credits which we account for as variable consideration. We estimate these credits based upon past practices and historical customer experience and we reduce our revenues recognized for these credits. Energy Marketing. Midstream & Marketing and UGI International operate energy marketing businesses that sell energy commodities, principally natural gas and electricity, to residential, commercial, industrial and wholesale customers. In addition, UGI International provides system balancing and procurement services to other energy marketers in the Netherlands. Midstream & Marketing and UGI International market natural gas and electricity on full-requirements or agreed-upon volume bases under contracts with varying length terms and at fixed or floating prices that are based on market indices adjusted for differences in price between the market location and delivery locations. Performance obligations associated with these contracts primarily comprise the delivery of the natural gas and electricity over a contractual period of time. Performance obligations also include other energy-related ancillary services provided to customers such as capacity. For performance obligations that are satisfied at a point in time such as the delivery of natural gas, revenue is recorded when customers take control of the natural gas. Revenue is recorded for performance obligations that qualify as a series, when customers consume the natural gas or electricity is delivered, which corresponds to the amount invoiced to the customer. For transactions where the price or volume is not fixed, the transaction price is not determined until delivery occurs. The billed amount, and the revenue recorded, is based upon consumption by the customer. In addition to providing natural gas and electricity to end-user customers, our energy marketing business in the Netherlands has contracts with third-party natural gas and electricity marketers to provide BRP services in the electricity and natural gas markets in the Netherlands. These contracts are typically multi-year agreements and include full BRP services that include, among other things, estimating, procuring and scheduling all energy requirements to meet third-party marketers’ needs, or provide more limited system procurement and balancing services. The amount of revenue recognized from our BRP customers is based upon the amount of energy delivered with respect to these agreements, and the level of BRP services provided. We typically receive payments from our BRP customers one month in advance of our performing the related services. Amounts received in advance are deferred on the balance sheet as contract liabilities. Based upon an evaluation of the terms and conditions of the BRP contracts and our ability to control the goods or services provided to the third-party marketers, in addition to other factors, we are considered a principal in these contracts and are required to record the revenue associated with the sale of energy to the third-party energy marketers on a gross basis. We record the associated revenue ratably over time, typically monthly, as the performance obligations are satisfied. Midstream. Midstream & Marketing provides natural gas pipeline transportation, natural gas gathering and natural gas underground storage services, which generally contain a performance obligation for the Company to have availability to transport or store a product. Additionally, the Company provides stand-ready services to sell supplemental energy products and related services, primarily LNG and propane-air mixtures during periods of high demand that typically result from cold weather. The Company also sells LNG to end-user customers for use by trucks, drilling rigs and other motored vehicles and equipment, and facilities that are located off the natural gas grid. Contracts for natural gas transportation and gathering services are typically long-term contracts with terms of up to 30 years , while contracts for storage are typically for one-year or multiple storage season periods. Contracts to provide natural gas during periods of high demand have terms of up to 15 years . Contracts to sell LNG for trucks, drilling rigs and other motor vehicles and facilities are typically short-term (less than one year). Depending on the type of services provided or goods sold, midstream revenues may consist of demand rates, commodity rates, and transportation rates and may include other fees for ancillary services. Pipeline transportation, natural gas gathering and storage services provided and services to stand ready to sell supplemental energy products and services each are considered to have a single performance obligation satisfied through the passage of time ratably based upon providing a stand-ready service on a monthly basis. Contracts to sell LNG to end-user customers contain performance obligations to deliver LNG over the term of the contract and revenue is recognized at a point in time when the control of the energy products is transferred to the customer. The price in the contract corresponds to our efforts to satisfy the performance obligation and reflects the consideration we expect to receive for the satisfied performance obligation, and, therefore, the revenue is recognized based on the volume delivered and the price within the contract. In cases where shipping and handling occurs prior to the LNG being delivered to the customer’s storage vessel, we have elected to treat this as a cost of fulfillment and not a separate performance obligation. Revenues are typically billed and payment received monthly. Advance fees received from customers for stand-ready services are deferred as contract liabilities and revenue is recognized ratably over time as the performance obligation is satisfied over a period less than one year. Electricity Generation. Midstream & Marketing sells power generated from electricity generation assets in the wholesale electricity markets administered by PJM regional transmission organization. Power contracts with PJM consist of the sale of power, capacity and ancillary services, all of which are considered a bundle of various services. Performance obligations are satisfied over time, generally on a daily basis, as electricity is delivered to and simultaneously consumed by the customer. As such, the Company has elected to recognize revenue in the amount to which we have a right to invoice which is based on market prices at the time of the delivery of the electricity to the customers. Other. Other revenues from contracts with customers are generated primarily from services and products provided by Midstream & Marketing’s HVAC business and AmeriGas Propane’s parts and services business. The performance obligations of these businesses include installation, repair and warranty agreements associated with HVAC equipment and installation services provided for combined heat and power and solar panel installations. For installation and repair goods and services, the performance obligations under these contracts are satisfied, and revenue is recognized, as control of the product is transferred or the services are rendered. For warranty services, revenue is recorded ratably over the warranty period. Other LPG revenues from contracts with customers are generated primarily from certain fees AmeriGas Partners and UGI International charge associated with the delivery of LPG, including hazmat safety compliance, inspection, metering, installation, fuel recovery and certain other services. Revenues from fees are typically recorded when the LPG is delivered to the customer or the associated service is completed. Contract Balances The timing of revenue recognition may differ from the timing of invoicing to customers or cash receipts. Contract assets represent our right to consideration after the performance obligations have been satisfied when such right is conditioned on something other than the passage of time. Contract assets were not material at September 30, 2019 . 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 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 $ 114.1 and $ 111.2 at September 30, 2019 and October 1, 2018, respectively, and are included in “Other current liabilities” and “Other noncurrent liabilities” on the Consolidated Balance Sheets. Revenue recognized during Fiscal 2019 from the amount included in contract liabilities at October 1, 2018 was $ 90.7 . Revenue Disaggregation The following table presents our disaggregated revenues by reportable segment during Fiscal 2019 : 2019 Total Eliminations AmeriGas Propane UGI International Midstream & Marketing (a) UGI Utilities (a) Corporate & Other Revenues from contracts with customers: Utility: Core Market: Residential $ 552.7 $ — $ — $ — $ — $ 552.7 $ — Commercial & Industrial 226.3 — — — — 226.3 — Large delivery service 138.0 — — — — 138.0 — Off-system sales and capacity releases 46.4 (64.8 ) — — — 111.2 — Other (b) 14.9 (3.1 ) — — — 18.0 — Total Utility 978.3 (67.9 ) — — — 1,046.2 — Non-Utility: LPG: Retail 4,007.9 — 2,340.9 1,667.0 — — — Wholesale 233.3 — 63.9 169.4 — — — Energy Marketing 1,520.7 (134.2 ) — 448.3 1,206.6 — — Midstream: Pipeline 94.5 — — — 94.5 — — Peaking 17.6 (96.8 ) — — 114.4 — — Other 1.9 — — — 1.9 — — Electricity Generation 43.2 — — — 43.2 — — Other 313.3 (3.3 ) 213.2 54.9 48.5 — — Total Non-Utility 6,232.4 (234.3 ) 2,618.0 2,339.6 1,509.1 — — Total revenues from contracts with customers 7,210.7 (302.2 ) 2,618.0 2,339.6 1,509.1 1,046.2 — Other revenues (c) 109.7 (3.2 ) 64.0 32.6 6.6 2.4 7.3 Total revenues $ 7,320.4 $ (305.4 ) $ 2,682.0 $ 2,372.2 $ 1,515.7 $ 1,048.6 $ 7.3 (a) Includes intersegment revenues principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (b) UGI Utilities includes an unallocated negative surcharge revenue reduction of $ (5.5) during Fiscal 2019 as a result of a PAPUC Order issued May 17, 2018, related to the TCJA (see Note 9 ). (c) Primarily represents revenues from tank rentals at AmeriGas Propane and UGI International, revenues from certain gathering assets at Midstream & Marketing, and gains and losses on commodity derivative instruments not associated with current-period transactions reflected in Corporate & Other, none of which are within the scope of ASC 606 and are accounted for in accordance with other GAAP. Remaining Performance Obligations The Company has elected to use practical expedients as allowed in ASC 606 to exclude disclosures related to the aggregate amount of the transaction price allocated to certain performance obligations that are unsatisfied as of the end of the reporting period because these contracts have an initial expected term of one year or less, or we have a right to bill the customer in an amount that corresponds directly with the value of services provided to the customer to date. Certain contracts with customers at Midstream & Marketing and UGI Utilities contain minimum future performance obligations through 2047 and 2053, respectively. At September 30, 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.

AmeriGas Merger and Acquisition

AmeriGas Merger and Acquisitions	12 Months Ended
	Sep. 30, 2019
Business Combinations [Abstract]
AmeriGas Merger and Acquisitions	Note 5 — AmeriGas Merger and Acquisitions AmeriGas Merger On August 21, 2019, the AmeriGas Merger was completed in accordance with the terms of the Merger Agreement entered into on April 1, 2019. Under the terms of the Merger Agreement, the Partnership was merged with and into Merger Sub, with the Partnership surviving as an indirect wholly owned subsidiary of UGI. Each outstanding Common Unit other than the Common Units owned by UGI was automatically converted at the effective time of the AmeriGas Merger into the right to receive, at the election of each holder of such Common Units, one of the following forms of merger consideration (subject to proration designed to ensure the number of shares of UGI Common Stock issued would equal approximately 34.6 million ): (i) 0.6378 shares of UGI Common Stock (the “Share Multiplier”); (ii) $7.63 in cash, without interest, and 0.500 shares of UGI Common Stock; or (iii) $35.325 in cash, without interest. Pursuant to the terms of the Merger Agreement, effective on August 21, 2019, we issued 34,612,847 shares of UGI Common Stock and paid $528.9 in cash to the holders of Common Units other than UGI, for a total implied consideration of $2,227.7 . In addition, the incentive distribution rights in the Partnership previously owned by the General Partner were canceled. After-tax transaction costs directly attributable to the transaction that were incurred by UGI totaling $7.7 were recorded as a reduction to UGI stockholders’ equity. Transaction costs incurred by the Partnership totaling $6.3 are reflected in “Operating and administrative expenses” on the 2019 Consolidated Statement of Income. The tax effects of the AmeriGas Merger resulting from the step-up in tax bases of the underlying assets resulted in the recording of a deferred tax asset in the amount of $512.3 . This deferred tax asset is included in “Deferred income taxes” on the September 30, 2019 Consolidated Balance Sheet. Effective upon completion of the AmeriGas Merger, Common Units are no longer publicly traded. Also pursuant to the Merger Agreement, Partnership equity-based awards were canceled and replaced with cash-settled restricted stock units relating to UGI Common Stock using the Share Multiplier ratio. For further information on the effects of the AmeriGas Merger on equity-based awards, see Note 14 . The AmeriGas Merger was accounted for in accordance with ASC 810, Consolidation - Overall-Changes in a Parent’s Ownership Interest in a Subsidiary. Because UGI controlled AmeriGas Partners before and after the merger, the changes in UGI’s ownership interest in the Partnership resulting from the merger were accounted for as an equity transaction. Accordingly, no gain or loss was recognized in UGI’s consolidated income statement and the carrying amounts of the Partnership assets and liabilities were not adjusted. The tax effects of the AmeriGas Merger were reported as adjustments to deferred income taxes and UGI stockholders’ equity. For additional information on the tax effects of the AmeriGas Merger, see Note 7 . 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 (See Note 6 ). The Company has accounted for the CMG Acquisition using the acquisition method. At September 30, 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 Company recognized $15.3 of direct transaction-related costs associated with the CMG Acquisition during Fiscal 2019, which costs are reflected in “Operating and administrative expenses” on the Consolidated Statements of Income. The CMG Acquisition did not have a material impact on the Company’s revenues or net income attributable to UGI for Fiscal 2019. In addition, the impact of the CMG Acquisition on a pro forma basis as if the CMG Acquisition had occurred on October 1, 2017 was not material to the Company’s consolidated results for Fiscal 2019 and Fiscal 2018. Other Acquisitions During Fiscal 2019, UGI International acquired several retail LPG distribution businesses, and Midstream & Marketing acquired a natural gas marketing business. During Fiscal 2018, UGI International acquired UniverGas, an LPG distribution business with operations in northern and central regions of Italy, and AmeriGas Propane acquired two retail propane distribution businesses. During Fiscal 2017, UGI International acquired DVEP, an energy marketing business with operations in the Netherlands, and an LPG distribution business with operations in Sweden, and AmeriGas Propane acquired several retail propane distribution businesses. Total cash paid and liabilities incurred in connection with these acquisitions were as follows: 2019 2018 2017 UGI International Midstream & Marketing AmeriGas Propane UGI International AmeriGas Propane UGI International Total cash paid $ 49.3 $ 15.0 $ 10.1 $ 121.9 $ 36.8 $ 99.7 Liabilities incurred (a) — — 2.7 — 10.8 20.6 Total purchase price $ 49.3 $ 15.0 $ 12.8 $ 121.9 $ 47.6 $ 120.3 (a) UGI International Fiscal 2017 amount includes note payable to seller. AmeriGas Propane amounts principally comprise amounts payable under noncompete agreements. Acquisitions of Assets During Fiscal 2019, Midstream & Marketing acquired 21 miles of natural gas gathering lines and related dehydration and compression equipment located in northern Pennsylvania for cash consideration of $20 . During Fiscal 2018, Midstream & Marketing acquired (1) 60 miles of natural gas gathering lines and related dehydration and compression equipment, and a smaller natural gas gathering system, both located in northern Pennsylvania and (2) a 44 -megawatt, natural gas-fired peaking turbine located on its Hunlock Station site in northeast Pennsylvania, for total cash consideration of $70.3 .

Debt

Debt	12 Months Ended
	Sep. 30, 2019
Debt Disclosure [Abstract]
Debt	Note 6 — Debt Significant Financing Activities AmeriGas Propane. In December 2017, AmeriGas Partners entered into the AmeriGas OLP Credit Agreement with a group of banks. The AmeriGas OLP Credit Agreement amends and restates a previous credit agreement. The AmeriGas OLP Credit Agreement provides for borrowings up to $600 (including a $150 sublimit for letters of credit) and expires in December 2022. The AmeriGas OLP Credit Agreement permits AmeriGas to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas OLP Credit Agreement, plus a margin. The applicable margin on base rate borrowings ranges from 0.50% to 1.75% , and the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.75% . The aforementioned margins on borrowings are dependent upon AmeriGas Partners’ ratio of debt to EBITDA (each as defined in the AmeriGas OLP Credit Agreement). During Fiscal 2017, AmeriGas Partners issued, in underwritten offerings, the AmeriGas 2017 Senior Notes, comprising $700 principal amount of 5.50% Senior Notes due May 2025 and $525 principal amount of 5.75% Senior Notes due May 2027. The AmeriGas 2017 Senior Notes rank equally with AmeriGas Partners’ existing outstanding senior notes. The net proceeds from the issuance of the AmeriGas 2017 Senior Notes were used (1) for the early repayment, pursuant to tender offers and notices of redemption, of all of AmeriGas Partners’ 7.00% Senior Notes, having an aggregate principal balance of $980.8 plus accrued and unpaid interest and early redemption premiums, and (2) for general corporate purposes. In connection with the early repayment of AmeriGas Partners’ 7.00% Senior Notes, during Fiscal 2017, the Partnership recognized pre-tax losses, which are reflected in “ Loss on extinguishments of debt ” on the Consolidated Statements of Income and comprise the following: 2017 Early redemption premiums $ 51.3 Write-off of unamortized debt issuance costs 8.4 Loss on extinguishments of debt $ 59.7 UGI International. On October 18, 2018, UGI International, LLC entered into the 2018 UGI International Credit Facilities Agreement, a five -year unsecured Senior Facilities Agreement with a consortium of banks consisting of (1) a €300 variable-rate term loan which was drawn on October 25, 2018, and (2) a €300 senior unsecured multicurrency revolving facility agreement. The 2018 UGI International Credit Facilities Agreement matures on October 18, 2023. Term loan borrowings bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate, which euribor rate has a floor of zero . The margin on term loan borrowings, which ranges from 1.55% to 3.20% , is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined. The initial margin on term loan borrowings was 1.70% . UGI International, LLC has entered into pay-fixed, receive-variable interest rate swap agreements to fix the underlying euribor rate on term loan borrowings at 0.34% through October 18, 2022. Under the multicurrency revolving credit facility agreement, UGI International, LLC may borrow in euros or U.S. dollars. Loans made in euros will bear interest at the associated euribor rate plus a margin ranging from 1.20% to 2.85% . Loans made in U.S. dollars will bear interest at the associated LIBOR rate plus a margin ranging from 1.45% to 3.10% . The margin on revolving facility borrowings is dependent upon a ratio of net consolidated indebtedness to consolidated EBITDA, as defined. On October 25, 2018, UGI International, LLC issued, in an underwritten private placement, €350 principal amount of UGI International 3.25% Senior Notes due November 1, 2025. The UGI International 3.25% Senior Notes rank equal in right of payment with indebtedness issued under the 2018 UGI International Credit Facilities Agreement. The net proceeds from the UGI International 3.25% Senior Notes and the 2018 UGI International Credit Facilities Agreement variable-rate term loan plus cash on hand were used on October 25, 2018 (1) to repay €540 outstanding principal of UGI France’s variable-rate term loan under its 2015 Senior Facilities Agreement; €45.8 outstanding principal of Flaga’s variable-rate term loan; and $49.9 outstanding principal of Flaga’s U.S. dollar variable-rate term loan, plus accrued and unpaid interest, and (2) for general corporate purposes. Because these outstanding term loans were refinanced on a long-term basis in October 2018, we classified €60 of such debt due in April 2019 as long-term debt on the September 30, 2018 Consolidated Balance Sheet. Upon entering into the 2018 UGI International Credit Facilities Agreement, we terminated (1) the 2017 UGI International Credit Agreement; (2) UGI France’s revolving credit facility under the 2015 Senior Facilities Agreement; and (3) Flaga’s credit facility agreement. We have designated term loan borrowings under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes as net investment hedges. In connection with these early repayments of debt, UGI International recognized pre-tax losses of $6.1 , which are reflected in “ Loss on extinguishments of debt ” on the 2019 Consolidated Statement of Income, and primarily comprises the write-off of unamortized debt issuance costs and transaction costs. In December 2017, UGI International, LLC entered into the 2017 UGI International Credit Agreement, a secured multicurrency revolving facility agreement due April 2020 with a group of banks providing for borrowings up to €300 , with borrowings available in euros or U.S. dollars. Upon entering into the 2018 UGI International Credit Facilities Agreement on October 25, 2018, the 2017 UGI International Credit Agreement was terminated. There were no borrowings made under the 2017 UGI International Credit Agreement. Also, in December 2017, Flaga repaid $9.2 of the outstanding principal amount of its then-existing $59.1 U.S. dollar denominated variable-rate term loan due September 2018. Concurrently, Flaga entered into the Flaga U.S. Dollar Term Loan which amended the aforementioned term loan to extend the maturity to April 2020. Prior to its repayment in October 2018, borrowings under the Flaga U.S. Dollar Term Loan bore interest at the one-month LIBOR rate plus a margin of 1.125% . Flaga effectively fixed the LIBOR component of the interest rate, and effectively fixed the U.S. dollar value of the interest and principal payments payable under the Flaga U.S. Dollar Term Loan, by entering into a cross-currency swap arrangement with a bank. Energy Services. On August 13, 2019, Energy Services entered into a seven-year $700 variable-rate senior secured term loan agreement with a group of lenders. The Energy Services Term Loan is payable in equal quarterly installments of $1.8 , commencing in September 2019, with the balance of the principal being due and payable in full at maturity. Under certain circumstances, Energy Services is required to make additional principal payments if the consolidated total leverage ratio, as defined, is greater than defined thresholds. Borrowings under the Energy Services Term Loan bear interest at rates per annum comprising the aggregate of the applicable margin and, subject to our election, either (1) the associated prime rate or (2) an adjusted LIBOR rate. The initial margin on term loan borrowings is 3.75% . In August 2019, Energy Services entered into a pay-fixed, receive-variable interest rate swap agreement to fix the underlying LIBOR rate on a significant portion of the outstanding principal on Energy Services Term Loan borrowings at 1.55% through July 2024. Proceeds from borrowings under the Energy Services Term Loan were used to finance a portion of the CMG Acquisition and for general corporate purposes. UGI Utilities. On June 27, 2019, UGI Utilities entered into the UGI Utilities 2019 Credit Agreement with a group of banks providing for borrowings up to $350 (including a $100 sublimit for letters of credit). UGI Utilities may request an increase in the amount of loan commitments under the UGI Utilities 2019 Credit Agreement to a maximum aggregate amount of $150 . Concurrently with entering into the UGI Utilities 2019 Credit Agreement, UGI Utilities terminated its existing $450 revolving credit agreement dated March 27, 2015. Under the UGI Utilities 2019 Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities 2019 Credit Agreement is currently scheduled to expire in June 2024. On February 1, 2019, UGI Utilities issued in a private placement $150 of UGI Utilities 4.55% Senior Notes due February 1, 2049. The UGI Utilities 4.55% Senior Notes were issued pursuant to a Note Purchase Agreement dated December 21, 2018, between UGI Utilities and certain note purchasers. The UGI Utilities 4.55% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. The net proceeds from the issuance of the UGI Utilities 4.55% Senior Notes were used to reduce revolving credit agreement borrowings and for general corporate purposes. In October 2017, UGI Utilities entered into the Utilities Term Loan, a $125 unsecured variable-rate term loan agreement with a group of banks. The Utilities Term Loan is payable in equal quarterly installments of $1.6 , commencing in March 2018, with the balance of the principal being due and payable in full on October 30, 2022. Proceeds from the Utilities Term Loan were used to repay revolving credit agreement borrowings and for general corporate purposes. Under the Utilities Term Loan, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.875% and is based upon the credit ratings of certain indebtedness of UGI Utilities. In July 2018, UGI Utilities entered into a forward-starting pay-fixed, receive-variable interest rate swap that generally fixes the underlying prevailing market interest rates on Utilities Term Loan borrowings at approximately 3.00% through July 2022. This forward-starting interest rate swap commenced on September 30, 2019. We have designated this forward-starting interest rate swap as a cash flow hedge. UGI Corporation. On August 1, 2019, UGI entered into the UGI Corporation Senior Credit Facility. The UGI Corporation Senior Credit Facility comprises (1) a five-year $250 amortizing variable-rate term loan which was drawn on August 21, 2019; (2) a three-year $300 variable-rate term loan which was drawn on August 1, 2019; and (3) a five-year $300 revolving credit facility (including a $10 sublimit for letters of credit) which was drawn in full on August 1, 2019. The $250 term loan commitment is payable in equal quarterly installments of $9.4 , commencing in December 2022, with the balance of the principal being due and payable in full on August 1, 2024. Proceeds from borrowings under the UGI Corporation Senior Credit Facility were used to finance the cash portion of the AmeriGas Merger; the CMG Acquisition; and for general corporate purposes. Because management currently intends to maintain a substantial portion of the amounts outstanding under the $300 revolving credit facility beyond September 30, 2020, and has the ability to do so under the terms of the UGI Corporation Senior Credit Agreement, such amounts have been classified as “Long-term debt” on the 2019 Consolidated Balance Sheet. Borrowings under the UGI Corporation Senior Credit Facility bear interest at rates per annum comprising the aggregate of the applicable margin and, subject to our election, either (1) the associated prime rate or (2) an adjusted LIBOR rate. The applicable margins on term loan and revolving credit facility borrowings are dependent upon a ratio of consolidated net indebtedness to consolidated EBITDA, as defined, and UGI’s credit ratings. The initial margin on term loan borrowings is 2.50% for the $250 amortizing term loan and 2.25% for the $300 term loan. In August 2019, UGI entered into pay-fixed, receive-variable interest rate swap agreements at 1.51% through July 2022, in order to fix the underlying LIBOR rates on the $300 term loan borrowings. In September 2019, UGI entered into pay-fixed, receive-variable interest rate swap agreements at 1.56% through March 2023, in order to fix the underlying LIBOR rates on a significant portion of the $250 term loan borrowings. Long-term Debt Long-term debt comprises the following at September 30: 2019 2018 AmeriGas Propane: AmeriGas Partners Senior Notes: 5.50% due May 2025 $ 700.0 $ 700.0 5.875% due August 2026 675.0 675.0 5.625% due May 2024 675.0 675.0 5.75% due May 2027 525.0 525.0 Heritage Operating, L.P. Senior Secured Notes (a) 3.8 7.5 Other 9.5 14.6 Unamortized debt issuance costs (23.7 ) (27.5 ) Total AmeriGas Propane 2,564.6 2,569.6 UGI International: 3.25% Senior Notes due November 2025 381.5 — UGI International, LLC variable-rate term loan due October 2023 (b) 327.0 — UGI France Senior Facilities term loan (c) — 627.0 Flaga variable-rate term loan (d) — 53.2 Flaga U.S. dollar variable-rate term loan (e) — 49.9 Other 19.3 20.9 Unamortized debt issuance costs (8.3 ) (2.5 ) Total UGI International 719.5 748.5 Midstream & Marketing: Energy Services variable-rate term loan due through August 2026 (f) 698.3 — Other 0.3 0.4 Unamortized discount and debt issuance costs (12.0 ) — Total Energy Services 686.6 0.4 UGI Utilities: Senior Notes: 4.12%, due September 2046 200.0 200.0 4.98%, due March 2044 175.0 175.0 4.55%, due February 2049 150.0 — 4.12%, due October 2046 100.0 100.0 6.21%, due September 2036 100.0 100.0 2.95%, due June 2026 100.0 100.0 Medium-Term Notes: 6.13%, due October 2034 20.0 20.0 6.50%, due August 2033 20.0 20.0 Variable-rate term loan due through October 2022 (g) 114.1 120.3 Other 4.7 6.8 Unamortized debt issuance costs (4.6 ) (4.1 ) Total UGI Utilities 979.2 838.0 2019 2018 UGI Corporation: UGI Corporation revolving credit facility maturing August 2024 (h) 300.0 — UGI Corporation variable-rate term loan due August 2022 (i) 300.0 — UGI Corporation variable-rate term loan due through August 2024 (i) 250.0 — Unamortized debt issuance costs (4.0 ) — Total UGI Corporation 846.0 — Other 8.1 8.8 Total long-term debt 5,804.0 4,165.3 Less: current maturities (24.1 ) (18.8 ) Total long-term debt due after one year $ 5,779.9 $ 4,146.5 (a) At September 30, 2019 and 2018 , the effective interest rate on the Heritage Operating, L.P. Senior Secured Notes was 6.75% . These notes are collateralized by AmeriGas OLP’s receivables, contracts, equipment, inventory, general intangibles and cash. (b) At September 30, 2019 , the effective interest rate on the term loan was approximately 2.04% . (c) At September 30, 2018, the effective interest rate on the term loan was approximately 1.93% . (d) The effective interest rate on this term loan at September 30, 2018, was 1.93% . (e) At September 30, 2018, the effective interest rate on this term loan was 0.55% . (f) The effective interest rate on this term loan at September 30, 2019 , was 5.79% . This term loan is collateralized by substantially all of the assets of Energy Services, subject to certain exceptions and carveouts including, but not limited to, accounts receivable and certain real property. (g) At September 30, 2019 and September 30, 2018 , the effective interest rate on this term loan was 3.05% and 2.76% , respectively. (h) The effective interest rate on credit facility borrowings at September 30, 2019 , was 4.55% . (i) At September 30, 2019 , the effective interest rates on the $300 variable-rate term loan and the $250 variable-rate term loan were 4.30% and 4.55% , respectively. Scheduled principal repayments of long-term debt for each of the next five fiscal years ending September 30 are as follows: 2020 2021 2022 2023 2024 AmeriGas Propane $ 7.8 $ 3.6 $ 1.6 $ 0.3 $ 675.0 UGI International 0.1 0.1 19.0 0.1 327.0 Midstream & Marketing 7.1 7.1 7.1 7.0 7.0 UGI Utilities 8.4 8.0 6.9 95.5 — UGI Corporation — — 300.0 37.5 512.5 Other 0.6 0.9 0.9 5.7 — Total $ 24.0 $ 19.7 $ 335.5 $ 146.1 $ 1,521.5 Credit Facilities and Short-term Borrowings Information about the Company’s principal credit agreements (excluding the Energy Services Receivables Facility, which is discussed below) as of September 30, 2019 and 2018 , is presented in the following table. Borrowings outstanding under these agreements (other than the UGI Corporation Credit Agreement) are classified as “Short-term borrowings” on the Consolidated Balance Sheets. Expiration Date Total Capacity Borrowings Outstanding Letters of Credit and Guarantees Outstanding Available Borrowing Capacity Weighted Average Interest Rate - End of Year September 30, 2019 AmeriGas OLP December 2022 $ 600.0 $ 328.0 $ 62.7 $ 209.3 4.50 % UGI International, LLC (a) October 2023 € 300.0 € 192.7 € — € 107.3 3.64 % Energy Services (b) March 2021 $ 200.0 $ 45.0 $ — $ 155.0 6.25 % UGI Utilities June 2024 $ 350.0 $ 166.0 $ — $ 184.0 3.00 % UGI Corporation (c) August 2024 $ 300.0 $ 300.0 $ — $ — 4.55 % September 30, 2018 AmeriGas OLP December 2022 $ 600.0 $ 232.0 $ 63.5 $ 304.5 4.58 % UGI International, LLC April 2020 € 300.0 € — € — € 300.0 N.A. UGI France April 2020 € 60.0 € — € — € 60.0 N.A. Flaga October 2020 € 55.0 € — € 0.5 € 54.5 N.A. Energy Services March 2021 $ 240.0 $ — $ — $ 240.0 N.A. UGI Utilities March 2020 $ 450.0 $ 189.5 $ 2.0 $ 258.5 3.03 % N.A. - Not applicable (a) The 2018 UGI International Credit Facilities Agreement permits UGI International, LLC to borrow in euros or dollars. At September 30, 2019 , the amount borrowed was USD-denominated borrowings of $210.0 , equal to €192.7 . (b) The Energy Services Credit Agreement includes a $50 sublimit for letters of credit and can be used for general corporate purposes of Energy Services and its subsidiaries. Borrowings bear interest at either (i) the Alternate Base Rate plus a margin or (ii) Adjusted LIBOR plus a margin. The Alternate Base Rate, as defined, is the highest of (a) the prime rate, (b) the federal funds rate plus 0.50% , and (c) Adjusted LIBOR plus 1.00% . The margin on such borrowings ranges from 0.75% to 2.25% . The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services. This credit agreement is collateralized by substantially all of the assets of Energy Services, subject to certain exceptions and carveouts including, but not limited to, accounts receivables and certain real property. On August 13, 2019, the Energy Services Credit Agreement was amended to decrease its borrowing capacity from $240 to $200 . (c) Borrowings outstanding are classified as “Long-term debt” on the 2019 Consolidated Balance Sheet. See “Significant Financing Activities - UGI Corporation” above for further information. Accounts Receivable Securitization Facility. Energy Services has a Receivables Facility with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2020. The Receivables Facility, as amended, provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November to April, and up to $75 of eligible receivables during the period May to October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes. Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, ESFC, which is consolidated for financial statement purposes. ESFC, in turn, has sold and, subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a major bank. Amounts sold to the bank are reflected as “ Short-term borrowings ” on the Consolidated Balance Sheets. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable. Losses on sales of receivables to the bank during Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , which amounts are included in “ Interest expense ” on the Consolidated Statements of Income, were not material. Information regarding the amounts of trade receivables transferred to ESFC and the amounts sold to the bank during Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , as well as the balance of ESFC trade receivables at September 30, 2019 , 2018 and 2017 follows: 2019 2018 2017 Trade receivables transferred to ESFC during the year $ 1,372.7 $ 1,279.5 $ 1,017.3 ESFC trade receivables sold to the bank during the year $ 179.0 $ 193.0 $ 243.0 ESFC trade receivables - end of year (a) $ 54.5 $ 65.0 $ 44.8 (a) At September 30, 2019 and 2018 , the amounts of ESFC trade receivables sold to the bank were $46.4 and $2.0 , respectively, and are reflected as “ Short-term borrowings ” on the Consolidated Balance Sheets. Restrictive Covenants Our long-term debt and credit facility agreements generally contain customary covenants and default provisions which may include, among other things, restrictions on the incurrence of additional indebtedness and also restrict liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. AmeriGas Propane. The AmeriGas Propane OLP Credit Agreement requires that AmeriGas OLP and AmeriGas Partners maintain ratios of total indebtedness to EBITDA, as defined, below certain thresholds. In addition, the Partnership must maintain a minimum ratio of EBITDA to interest expense, as defined and as calculated on a rolling four-quarter basis. Generally, as long as no default exists or would result therefrom, AmeriGas OLP is permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter. Under the AmeriGas Partners Senior Notes Indentures, AmeriGas Partners is generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. At September 30, 2019 , these restrictions did not limit the amount of Available Cash. See Note 15 for the definition of Available Cash included in the Partnership Agreement. The Heritage Operating, L.P. Senior Secured Notes’ financial covenants require AmeriGas OLP to maintain a ratio of consolidated funded indebtedness to consolidated EBITDA (as defined) below certain thresholds and to maintain a minimum ratio of consolidated EBITDA to consolidated interest expense (as defined). UGI International. The 2018 UGI International Credit Facilities Agreement requires a ratio of consolidated total net indebtedness to consolidated EBITDA, as defined, not to exceed 3.85 to 1.00. Energy Services. The Energy Services Term Loan requires that Energy Services and subsidiaries maintain a minimum ratio of consolidated EBITDA to debt service, as defined, of 1.10 to 1.00, and not exceed a ratio of total indebtedness to EBITDA, as defined, of 3.50 to 1.00. During an Acquisition Period, as defined in the agreement, the maximum ratio of total indebtedness to EBITDA is increased to 4.00 to 1.00. As of September 30, 2019 , Energy Services was within an Acquisition Period as defined in the agreement. Energy Services’ Credit Agreement requires that Energy Services and subsidiaries not exceed a ratio of total indebtedness to EBITDA, as defined, of 3.50 to 1.00, and maintain a minimum ratio of EBITDA to interest expense, as defined, of 3.50 to 1.00. During an Acquisition Period, as defined in the agreement, the maximum ratio of total indebtedness to EBITDA is increased to 4.00 to 1.00. As of September 30, 2019 , Energy Services was within the Acquisition Period as defined in the agreement. UGI Utilities. Certain of UGI Utilities’ Senior Notes include the usual and customary covenants for similar type notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. The UGI Utilities 2019 Credit Agreement, certain of UGI Utilities’ Senior Notes and the Utilities Term Loan require UGI Utilities not to exceed a ratio of consolidated debt to consolidated total capital, as defined, of 0.65 to 1.00. UGI Corporation. The UGI Corporation Senior Credit Facility requires that UGI maintain a ratio of consolidated EBITDA to consolidated interest expense, as defined and as calculated on a rolling four-quarter basis, above 3.50 to 1.00. In addition, UGI may not exceed a ratio of consolidated net indebtedness to consolidated EBITDA, as defined and as calculated on a rolling four-quarter basis, of 4.50 to 1.00 (declining over time to 4.00 to 1.00). During an Acquisition Period, as defined by the agreement, the ratio of consolidated net indebtedness to consolidated EBITDA, as defined and as calculated on a rolling four-quarter basis, is raised to 4.875 to 1.00 (declining over time to 4.50 to 1.00). At September 30, 2019, UGI was within an Acquisition Period as defined in the agreement. Restricted Net Assets At September 30, 2019 , the amount of net assets of UGI’s consolidated subsidiaries that were restricted from transfer to UGI under debt agreements, subsidiary partnership agreements and regulatory requirements under foreign laws totaled approximately $2,100 .

Income Taxes

Income Taxes	12 Months Ended
	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Note 7 — Income Taxes Income before income taxes comprises the following: 2019 2018 2017 Domestic $ 329.4 $ 576.0 $ 527.3 Foreign 71.1 278.5 174.1 Total income before income taxes $ 400.5 $ 854.5 $ 701.4 The provisions for income taxes consist of the following: 2019 2018 2017 Current expense (benefit): Federal $ 51.7 $ (2.7 ) $ (2.7 ) State 14.0 26.0 14.0 Foreign 69.6 77.6 56.2 Total current expense 135.3 100.9 67.5 Deferred expense (benefit): Federal 2.9 (77.1 ) 125.8 State 3.5 6.7 16.4 Foreign (48.8 ) 1.9 (31.8 ) Investment tax credit amortization (0.3 ) (0.3 ) (0.3 ) Total deferred expense (42.7 ) (68.8 ) 110.1 Total income tax expense $ 92.6 $ 32.1 $ 177.6 Federal income taxes for Fiscal 2019 , Fiscal 2018 and Fiscal 2017 are net of foreign tax credits of $9.8 , $13.0 and $40.9 , respectively. A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows: 2019 2018 2017 U.S. federal statutory tax rate 21.0 % 24.5 % 35.0 % Difference in tax rate due to: Effect of tax rate changes - TJCA 0.2 (20.9 ) — Effect of tax rate changes - International (0.5 ) (2.1 ) (4.1 ) Noncontrolling interests not subject to tax (2.7 ) (3.0 ) (4.3 ) State income taxes, net of federal benefit 3.6 2.9 2.9 Valuation allowance adjustments — 1.1 (1.1 ) Effects of foreign operations 1.8 3.1 (1.1 ) Excess tax benefits on share-based payments (1.0 ) (1.1 ) (1.3 ) Other, net 0.7 (0.7 ) (0.7 ) Effective tax rate 23.1 % 3.8 % 25.3 % On December 22, 2017, the TCJA was enacted into law. Among the significant changes resulting from the law, the TCJA reduced the U.S. federal income tax rate from 35% to 21%, effective January 1, 2018, created a territorial tax system with a one-time mandatory “toll tax” on previously un-repatriated foreign earnings, and allowed for immediate capital expensing of certain qualified property. It also applied restrictions on the deductibility of interest expense, eliminated bonus depreciation for regulated utilities and certain FERC-regulated property beginning in Fiscal 2019 and applied a broader application of compensation limitations. As a result of the TCJA, we reduced our net deferred income tax liabilities in Fiscal 2018 by $384.4 due to the remeasuring of our existing federal deferred income tax assets and liabilities as of the date of the enactment of the TCJA on December 22, 2017. Because most of the reduction to UGI Utilities’ net deferred income taxes related to regulated utility plant assets, most of UGI Utilities’ reduction in deferred income taxes was not recognized immediately in income tax expense. In accordance with GAAP as determined by ASC 740, we are required to record the effects of tax law changes in the period enacted. Our results for Fiscal 2018 contained provisional estimates of the impact of the TCJA. These amounts were considered provisional because they used estimates for which tax returns had not yet been filed and because estimated amounts could have been impacted by future regulatory and accounting guidance if and when issued. We adjusted provisional amounts as further information became available and as we refined our calculations. As permitted by SEC Staff Bulletin No. 118, these adjustments occurred during the reasonable “measurement period” defined as twelve months from the date of enactment. During Fiscal 2019, adjustments to provisional amounts recorded in prior periods were not material. In Fiscal 2018, we were subject to a blended federal tax rate of 24.5% because our fiscal year contained the effective date of the rate change from 35% to 21%. The effects of the tax law changes on Fiscal 2018 results (excluding the remeasurement impact described above) decreased income tax by $52.1 . In order for UGI Utilities’ regulated utility plant assets to continue to be eligible for accelerated tax depreciation, current law requires that excess deferred federal income taxes resulting from the remeasurement of deferred taxes on regulated utility plant be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess deferred income taxes. As a result of the TCJA, for Fiscal 2018, UGI Utilities initially recorded a net regulatory liability of $205.6 associated with excess deferred federal income taxes related to its regulated utility plant assets. This regulatory liability was increased, and a federal deferred income tax asset was recorded, in the amount of $83.6 to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes. This regulatory liability is being amortized to income tax expense over the remaining lives of the assets that gave rise to the excess deferred income taxes. For further information on this regulatory liability, see Note 9 . As further described in Note 9 , on May 17, 2018, the PAPUC issued a Temporary Rates Order for all PAPUC-regulated utilities with regard to federal tax reform. Among other things, the Temporary Rates Order required Pennsylvania utilities to establish a regulatory liability for tax benefits that accrued during the period January 1, 2018 through June 30, 2018, resulting from the change in the federal income tax rate from 35% to 21%. In accordance with the Temporary Rates Order, during Fiscal 2018, UGI Utilities reduced its revenues by $24.1 and recorded a regulatory liability in an equal amount. The total reduction of $24.1 primarily reflects (1) $17.1 of tax benefits accrued during the period January 1, 2018 to June 30, 2018, and (2) $7.0 to reflect tax benefits expected to be generated by the future amortization of the regulatory liability and accrued interest. In Fiscal 2018 and Fiscal 2017, earnings of the Company’s foreign subsidiaries were generally subject to U.S. taxation upon repatriation to the U.S. and the Company’s tax provisions reflected the related incremental U.S. tax except for certain foreign subsidiaries whose unremitted earnings were considered to be indefinitely reinvested. No deferred tax liability had been recognized with regard to remittance of those earnings because of the availability of U.S. foreign tax credits made it likely that no U.S. tax would be due if such earnings were repatriated. Upon enactment of the TCJA, substantially all prior unrepatriated earnings were subjected to U.S. tax under the transition tax rules. The transition tax was immaterial to the Company and we generally expect to have the ability to repatriate prior unrepatriated earnings without material U.S. federal tax cost. Our Fiscal 2019 effective tax rate was subject to the impact of changes to the taxation of foreign source income made by the TCJA. Fiscal 2019 tax expense includes $3.8 of GILTI and Branch taxes that are treated as current period costs and carry no related deferred taxes. Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , the beneficial effects of state tax flow through of accelerated depreciation reduced income tax expense by $7.4 , $4.2 and $2.5 , respectively. Deferred tax liabilities (assets) comprise the following at September 30: 2019 2018 Excess book basis over tax basis of property, plant and equipment $ 804.5 $ 807.8 Investment in AmeriGas Partners — 219.2 Utility regulatory assets 107.6 86.7 Intangible assets and goodwill 70.5 67.6 Derivative instruments — 30.4 Other 8.3 10.6 Gross deferred tax liabilities 990.9 1,222.3 Investment in AmeriGas Partners (303.5 ) — Pension plan liabilities (49.9 ) (20.0 ) Employee-related benefits (43.8 ) (43.6 ) Operating loss carryforwards (21.2 ) (26.2 ) Foreign tax credit carryforwards (81.4 ) (106.1 ) Utility regulatory liabilities (94.3 ) (118.6 ) Derivative instruments (15.3 ) — Utility environmental liabilities (15.3 ) (14.7 ) Other (33.4 ) (29.0 ) Gross deferred tax assets (658.1 ) (358.2 ) Deferred tax assets valuation allowance 90.7 116.8 Net deferred tax liabilities $ 423.5 $ 980.9 As a result of the AmeriGas Merger, we acquired all of the equity interests of AmeriGas Partners. In exchange for the interest acquired from the public, we issued stock and paid cash having a total implied fair value of $ 2,227.7 . The transaction represents a taxable exchange for which we received a step-up in the tax basis in the underlying assets acquired. A gross deferred tax asset of $ 2,030.3 related to the book tax basis difference in this investment has been recorded through equity in accordance with ASC 810. We evaluated the realizability of the resulting net deferred tax asset position of $ 512.3 assessing the available positive and negative evidence. As the taxable temporary differences of the Partnership’s tax depreciation in excess of book depreciation reverses, the associated deferred taxes are expected to be fully realized. In July 2019, the French Parliament enacted legislation retroactively increasing the corporate income tax rate for tax years beginning in 2019. As a result, the Fiscal 2020 tax rate remains at 34.43 %. The impact on deferred income tax liabilities increased income tax expense by $ 2.4 . In December 2017, the French Parliament approved the December 2017 French Finance Bills. One impact of the December 2017 French Finance Bills was an increase in the Fiscal 2018 corporate income tax rate in France from 34.4% to 39.4%. The December 2017 French Finance Bills also include measures to reduce the corporate income tax rate to 25.8%, effective for fiscal years starting after January 1, 2022 (Fiscal 2023). As a result of the December 2017 French Finance Bills, the Company reduced its net French deferred income tax liabilities and recognized an estimated deferred tax benefit of $12.1 to reflect the estimated impact of the corporate income tax rate reductions that will be implemented through Fiscal 2023. The Company’s Fiscal 2018 effective income tax rate reflects the impact of the higher Fiscal 2018 income tax rate in France as a result of the December 2017 French Finance Bills, which increased income tax expense for the year by approximately $0.6 . At September 30, 2019 , foreign net operating loss carryforwards principally relating to Flaga and certain subsidiaries of UGI France totaled $10.0 and $22.0 , respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries that approximate $147.9 and expire through 2039 . We also have federal operating loss carryforwards of $14.3 for certain operations of AmeriGas Propane that expire through 2036 . At September 30, 2019 , deferred tax assets relating to operating loss carryforwards include $2.0 for Flaga, $6.8 for certain subsidiaries of UGI France, $3.0 for AmeriGas Propane and $9.4 for certain other subsidiaries. Valuation allowances against deferred tax assets exist for foreign tax credit carryforwards and net operating loss carryforwards of foreign subsidiaries. The valuation allowance for all deferred tax assets decreased by $26.1 in Fiscal 2019. The decrease consisted of the release of $24.8 of valuation allowances on foreign tax credits that expired in Fiscal 2019 and a decrease in foreign operating loss carryforwards of $1.3 . The valuation allowance for all deferred tax assets increased by $9.7 in Fiscal 2018 due to an increase of $7.6 to re-establish a full valuation allowance associated with future utilization of foreign tax credits, primarily due to impacts of the TCJA and an increase in foreign operating loss carryforwards of $2.1 . We conduct business and file tax returns in the U.S., numerous states, local jurisdictions and in France and certain other European countries. Our U.S. federal income tax returns are settled through the 2015 tax year, our French tax returns are settled through the 2017 tax year, our Austrian tax returns are settled through 2016 and our other European tax returns are effectively settled for various years from 2010 to 2017. State and other income tax returns in the U.S. are generally subject to examination for a period of three to five years after the filing of the respective returns. UGI Corporation and subsidiaries’ 2017 and 2016 consolidated U.S. federal tax returns are currently under examination by the Internal Revenue Service. As of September 30, 2019 , we have unrecognized income tax benefits totaling $10.9 including related accrued interest of $1.0 . If these unrecognized tax benefits were subsequently recognized, $10.9 would be recorded as a benefit to income taxes on the Consolidated Statement of Income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. The expected change in unrecognized tax benefits and related interest in the next twelve months is $2.8 as the result of the expiration of certain statutes of limitation. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: 2019 2018 2017 Unrecognized tax benefits — beginning of year $ 11.5 $ 12.2 $ 7.2 Additions for tax positions of the current year 0.9 1.5 1.9 Additions for tax positions taken in prior years 0.4 0.6 4.6 Settlements with tax authorities/statute lapses (1.9 ) (2.8 ) (1.5 ) Unrecognized tax benefits — end of year $ 10.9 $ 11.5 $ 12.2

Employee Retirement Plans

Employee Retirement Plans	12 Months Ended
	Sep. 30, 2019
Retirement Benefits [Abstract]
Employee Retirement Plans	Note 8 — Employee Retirement Plans 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 following table provides a reconciliation of the PBOs of the U.S. Pension Plan and the UGI International pension plans, the ABOs of our other postretirement benefit plans, plan assets, and the funded status of pension and other postretirement plans as of September 30, 2019 and 2018 . ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation. Pension Benefits Other Postretirement Benefits 2019 2018 2019 2018 Change in benefit obligations: Benefit obligations — beginning of year $ 669.2 $ 697.8 $ 19.3 $ 27.0 Service cost 9.8 11.2 0.2 0.5 Interest cost 27.3 26.3 0.7 0.8 Actuarial loss (gain) 89.0 (37.0 ) 3.6 (2.1 ) Plan amendments 0.3 — — (5.8 ) Curtailment (1.3 ) (0.6 ) — (0.1 ) Settlements (13.1 ) — — — Foreign currency (3.1 ) (1.0 ) (0.2 ) — Benefits paid (28.0 ) (27.5 ) (0.9 ) (1.0 ) Benefit obligations — end of year $ 750.1 $ 669.2 $ 22.7 $ 19.3 Change in plan assets: Fair value of plan assets — beginning of year $ 563.3 $ 529.2 $ 15.3 $ 14.8 Actual gain on plan assets 13.0 44.9 0.9 0.9 Foreign currency (1.5 ) (0.6 ) — — Employer contributions 12.4 16.2 0.4 0.4 Settlements (13.1 ) — — — Benefits paid (27.3 ) (26.4 ) (0.4 ) (0.8 ) Fair value of plan assets — end of year $ 546.8 $ 563.3 $ 16.2 $ 15.3 Funded status of the plans — end of year $ (203.3 ) $ (105.9 ) $ (6.5 ) $ (4.0 ) Assets (liabilities) recorded in the balance sheet: Assets in excess of liabilities — included in other noncurrent assets $ — $ — $ 2.8 $ 6.7 Unfunded liabilities — included in other noncurrent liabilities (203.3 ) (105.9 ) (9.3 ) (10.7 ) Net amount recognized $ (203.3 ) $ (105.9 ) $ (6.5 ) $ (4.0 ) Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): Prior service cost (benefit) $ 1.3 $ 0.6 $ (1.2 ) $ (1.3 ) Net actuarial loss (gain) 25.4 14.0 0.5 (0.4 ) Total $ 26.7 $ 14.6 $ (0.7 ) $ (1.7 ) Amounts recorded in regulatory assets and liabilities (pre-tax): Prior service cost (benefit) $ 0.5 $ 0.7 $ (0.7 ) $ (1.2 ) Pension Benefits Other Postretirement Benefits 2019 2018 2019 2018 Net actuarial loss (gain) 177.4 85.7 1.4 (0.1 ) Total $ 177.9 $ 86.4 $ 0.7 $ (1.3 ) In Fiscal 2019 and Fiscal 2018 , the change in the pension plans’ PBO due to actuarial gains and losses is principally the result of changes in discount rates. The change in the pension plans’ PBO in Fiscal 2019 also reflects a settlement resulting from the conversion of a defined benefit pension plan to a defined contribution plan in the Netherlands. In Fiscal 2020 , we estimate that we will amortize approximately $15.0 of net actuarial losses, primarily associated with the U.S. Pension Plan, and $0.3 of net prior service cost from UGI stockholders’ equity and regulatory assets into retiree benefit cost. Actuarial assumptions for our U.S. plans are described below. Assumptions for the UGI International plans are based upon market conditions in France, Belgium and the Netherlands. The discount rate assumption was determined by selecting a hypothetical portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the plans’ benefit payments. The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below). Pension Plan Other Postretirement Benefits 2019 2018 2017 2019 2018 2017 Weighted-average assumptions: Discount rate – benefit obligations 3.30 % 4.40 % 4.00 % 3.30 % 4.40 % 4.00 % Discount rate – benefit cost 4.40 % 4.00 % 3.80 % 4.40 % 4.00 % 3.80 % Expected return on plan assets 7.30 % 7.40 % 7.50 % 5.00 % 5.00 % 5.00 % Rate of increase in salary levels 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % The ABOs for the U.S. Pension Plan were $658.5 and $572.8 as of September 30, 2019 and 2018 , respectively. The service cost component of our pension and other postretirement plans, net of amounts capitalized, are reflected in “Operating and administrative expenses” on the 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 income (expense), net ” on the Consolidated Statements of Income. Net periodic pension cost and other postretirement benefit cost include the following components: Pension Benefits Other Postretirement Benefits 2019 2018 2017 2019 2018 2017 Service cost $ 9.8 $ 11.2 $ 11.9 $ 0.2 $ 0.5 $ 1.0 Interest cost 27.3 26.3 25.0 0.7 0.8 0.8 Expected return on assets (36.3 ) (35.0 ) (33.6 ) (0.8 ) (0.7 ) (0.7 ) Curtailment gain (0.4 ) (0.2 ) (1.4 ) — — — Amortization of: Prior service cost (benefit) 0.3 0.3 0.3 (0.5 ) (6.3 ) (0.6 ) Actuarial loss (gain) 7.8 13.4 16.7 (0.1 ) (0.1 ) 0.3 Net benefit cost (benefit) 8.5 16.0 18.9 (0.5 ) (5.8 ) 0.8 Change in associated regulatory liabilities — — — (1.4 ) (0.5 ) (0.5 ) Net benefit cost (benefit) after change in regulatory liabilities $ 8.5 $ 16.0 $ 18.9 $ (1.9 ) $ (6.3 ) $ 0.3 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. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , we made cash contributions to the U.S. Pension Plan of $11.5 , $15.1 and $11.4 , respectively. The minimum required contributions in Fiscal 2020 are not expected to be material. 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. We do not expect to be required to make any contributions to the VEBA during Fiscal 2020 . Expected payments for pension and other postretirement welfare benefits are as follows: Pension Benefits Other Postretirement Benefits Fiscal 2020 $ 32.7 $ 1.0 Fiscal 2021 $ 31.7 $ 1.0 Fiscal 2022 $ 33.0 $ 1.0 Fiscal 2023 $ 35.6 $ 0.9 Fiscal 2024 $ 37.2 $ 0.9 Fiscal 2025 - 2029 $ 204.3 $ 4.9 We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. At September 30, 2019 and 2018 , the PBOs of these plans, including obligations for amounts held in grantor trusts, were $52.9 and $48.3 , respectively. We recorded pre-tax costs for these plans of $2.2 in Fiscal 2019 , $4.3 in Fiscal 2018 (which amount includes a $2.1 settlement charge) and $3.1 in Fiscal 2017 . These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $9.1 and $4.3 at September 30, 2019 and 2018 , respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $0.9 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2020 . During Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , the payments the Company made with respect to the supplemental executive defined benefit retirement plans were not material. The total fair value of the grantor trust investment assets associated with the supplemental executive defined benefit retirement plans, which are included in “ Other assets ” on the Consolidated Balance Sheets, totaled $33.8 and $34.3 at September 30, 2019 and 2018 , respectively. U.S. Pension Plan and VEBA Assets The assets of the U.S. Pension Plan and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the U.S. Pension Plan and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly traded, diversified equity and fixed income index mutual funds and UGI Common Stock. Assets associated with the UGI International plans are excluded from the disclosures in the tables below as such assets are not material. The targets, target ranges and actual allocations for the U.S. Pension Plan and VEBA trust assets at September 30 are as follows: U.S. Pension Plan Actual Target Asset Allocation Permitted Range 2019 2018 Equity investments: Domestic 54.8 % 58.2 % 52.5 % 40.0% – 65.0% International 11.8 % 11.8 % 12.5 % 7.5% – 17.5% Total 66.6 % 70.0 % 65.0 % 60.0% – 70.0% Fixed income funds & cash equivalents 33.4 % 30.0 % 35.0 % 30.0% – 40.0% Total 100.0 % 100.0 % 100.0 % VEBA Actual Target Asset Allocation Permitted Range 2019 2018 Domestic equity investments 64.9 % 65.6 % 65.0 % 60.0% – 70.0% Fixed income funds & cash equivalents 35.1 % 34.4 % 35.0 % 30.0% – 40.0% Total 100.0 % 100.0 % 100.0 % Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500 and mid- and small-cap index mutual funds. Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 7.7% and 8.5% of U.S. Pension Plan assets at September 30, 2019 and 2018 , respectively. The fair values of U.S. Pension Plan and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee. The fair values of the U.S. Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2 , as of September 30, 2019 and 2018 are as follows: U.S. Pension Plan Level 1 Level 2 Level 3 Other (a) Total September 30, 2019: Domestic equity investments: S&P 500 Index equity mutual funds $ 176.4 $ — $ — $ — $ 176.4 Small and midcap equity mutual funds 72.8 — — — 72.8 UGI Corporation Common Stock 40.9 — — — 40.9 Total domestic equity investments 290.1 — — — 290.1 International index equity mutual funds 62.1 — — — 62.1 Fixed income investments: Bond index mutual funds 170.5 — — — 170.5 Cash equivalents — — — 6.4 6.4 Total fixed income investments 170.5 — — 6.4 176.9 Total $ 522.7 $ — $ — $ 6.4 $ 529.1 September 30, 2018: Domestic equity investments: S&P 500 Index equity mutual funds $ 188.4 $ — $ — $ — $ 188.4 Small and midcap equity mutual funds 75.7 — — — 75.7 UGI Corporation Common Stock 45.2 — — — 45.2 Total domestic equity investments 309.3 — — — 309.3 International index equity mutual funds 62.9 — — — 62.9 Fixed income investments: Bond index mutual funds 154.3 — — — 154.3 Cash equivalents — — — 5.2 5.2 Total fixed income investments 154.3 — — 5.2 159.5 Total $ 526.5 $ — $ — $ 5.2 $ 531.7 VEBA Level 1 Level 2 Level 3 Other (a) Total September 30, 2019: S&P 500 Index equity mutual fund $ 10.5 $ — $ — $ — $ 10.5 Bond index mutual fund 5.5 — — — 5.5 Cash equivalents — — — 0.2 0.2 Total $ 16.0 $ — $ — $ 0.2 $ 16.2 September 30, 2018: S&P 500 Index equity mutual fund $ 10.1 $ — $ — $ — $ 10.1 Bond index mutual fund 4.9 — — — 4.9 Cash equivalents — — — 0.3 0.3 Total $ 15.0 $ — $ — $ 0.3 $ 15.3 (a) Assets measured at NAV and therefore excluded from the fair value hierarchy. The expected long-term rates of return on U.S. Pension Plan and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption. Defined Contribution Plans We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for employer matching contributions at various rates. The cost of benefits under the savings plans totaled $19.3 in Fiscal 2019 , $17.1 in Fiscal 2018 and $15.1 in Fiscal 2017 . The Company also sponsors certain nonqualified supplemental defined contribution executive retirement plans. These plans generally provide supplemental benefits to certain executives that would otherwise be provided under retirement plans but are prohibited due to limitations imposed by the Internal Revenue Code. The Company makes payments to self-directed grantor trusts with respect to these supplemental defined contribution plans. Such payments during Fiscal 2019 , Fiscal 2018 and Fiscal 2017 were not material. At September 30, 2019 and 2018 , the total fair values of these grantor trust investment assets, which amounts are included in “ Other assets ” on the Consolidated Balance Sheets, were $5.9 and $6.5 , respectively.

Utility Regulatory Assets and L

Utility Regulatory Assets and Liabilities and Regulatory Matters	12 Months Ended
	Sep. 30, 2019
Regulated Operations [Abstract]
Utility Regulatory Assets and Liabilities and Regulatory Matters	Note 9 — Utility Regulatory Assets and Liabilities and Regulatory Matters The following regulatory assets and liabilities associated with UGI Utilities are included in our Consolidated Balance Sheets at September 30: 2019 2018 Regulatory assets: Income taxes recoverable $ 115.2 $ 110.1 Underfunded pension and postretirement plans 178.6 87.1 Environmental costs 59.5 58.8 Removal costs, net 28.3 32.0 Other 14.0 13.0 Total regulatory assets $ 395.6 $ 301.0 Regulatory liabilities (a): Postretirement benefit overcollections $ 14.5 $ 17.8 Deferred fuel and power refunds 6.1 36.7 State income tax benefits — distribution system repairs 25.0 22.6 PAPUC Temporary Rates Order 31.3 24.4 Excess federal deferred income taxes 279.5 285.2 Other 2.4 3.5 Total regulatory liabilities $ 358.8 $ 390.2 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “Other noncurrent liabilities” on the Consolidated Balance Sheets. Other than removal costs, UGI Utilities currently does not recover a rate of return on the regulatory assets included in the table above. Income taxes recoverable . This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of the tax benefit on accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. UGI Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 65 years. Underfunded pension and other postretirement plans . This regulatory asset represents the portion of net actuarial losses and prior service costs (credits) associated with pension and other postretirement benefits which are probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants. Environmental costs . Environmental costs principally represent estimated probable future environmental remediation and investigation costs that Gas Utility expects to incur, primarily at MGP sites in Pennsylvania, in conjunction with remediation COAs with the PADEP. Pursuant to base rate orders, Gas Utility receives ratemaking recognition of its estimated environmental investigation and remediation costs associated with environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2019 , the period over which Gas Utility expects to recover these costs will depend upon future remediation activity. For additional information on environmental costs, see Note 16 . Removal costs, net . This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. As required by PAPUC ratemaking, removal costs include actual costs incurred associated with asset retirement obligations. Consistent with prior ratemaking treatment, Gas Utility expects to recover these costs over five years . Postretirement benefit overcollections . This regulatory liability represents the difference between amounts recovered through rates by Gas Utility and Electric Utility and actual costs incurred in accordance with accounting for postretirement benefits. With respect to Gas Utility, postretirement benefit overcollections are generally being refunded to customers over a ten -year period beginning October 19, 2016. With respect to Electric Utility, the overcollections are being refunded to ratepayers over a 20 -year period beginning October 27, 2018. 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 September 30, 2019 and 2018 were $(2.2) and $2.9 , respectively. State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal benefit, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas Utility or Electric Utility assets that are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets. PAPUC Temporary Rates Order. On May 17, 2018, the PAPUC ordered each regulated utility currently not in a general base rate case proceeding, including UGI Gas, PNG and CPG, to reduce their rates to credit customers any tax savings as a result of the TCJA through the establishment of a negative surcharge applied to bills rendered on or after July 1, 2018. In accordance with the terms of the Temporary Rates Order, the initial temporary negative surcharge was reconciled at the end of Fiscal 2018 to reflect the difference in the amount of bill credit received by customers and the amount of benefits received by the Company through the fiscal year end period and updated negative surcharges were placed in effect on January 1, 2019 at rates of 4.71% , 2.87% and 6.34% , respectively, for the UGI South, UGI North and UGI Central rate districts (as described below). These negative surcharges remained in effect until October 11, 2019, the effective date of Gas Utility’s new base rates. In its May 17, 2018 Order, the PAPUC also required Pennsylvania utilities to establish a regulatory liability for tax benefits that accrued during the period January 1, 2018 through June 30, 2018, resulting from the reduced federal tax rate. The rate treatment of this regulatory liability is addressed in Gas Utility’s base rate proceeding filed January 28, 2019 (see “Base Rate Filings” below). For Pennsylvania utilities that were in a general base rate proceeding, including Electric Utility, no negative surcharge applied. The tax benefits that accrued during the period January 1, 2018 through October 26, 2018, the date before Electric Utility’s base rate case became effective (see below) were refunded to Electric Utility ratepayers through a one-time bill credit. Excess federal deferred income taxes. This regulatory liability is the result of remeasuring UGI Utilities’ federal deferred income tax liabilities on utility plant due to the enactment of the TCJA on December 22, 2017 (see Note 7 ). In order for our utility assets to continue to be eligible for accelerated tax depreciation, current law requires that excess federal deferred income taxes resulting from the remeasurement be amortized no more rapidly than over the remaining lives of the assets that gave rise to the excess federal deferred income taxes, ranging from 1 year to approximately 65 years . This regulatory liability has been increased to reflect the tax benefit generated by the amortization of the excess deferred federal income taxes and is being amortized and credited to tax expense. Other . Other regulatory assets and liabilities comprise a number of deferred items including, among others, over or under refunds of tax benefits related to the TCJA for periods after June 30, 2018, certain information technology costs, energy efficiency conservation costs and rate case expenses. Other Regulatory Matters Utility Merger. On March 8, 2018 and March 13, 2018, UGI Utilities filed merger authorization requests with the PAPUC and MDPSC, respectively, to merge PNG and CPG into UGI Utilities. After receiving all necessary FERC, MDPSC, and PAPUC approvals, CPG and PNG were merged with and into UGI Utilities effective October 1, 2018. Consistent with the MDPSC Order issued July 25, 2018, and the PAPUC Order issued September 26, 2018, the former CPG, PNG and UGI Utilities, Inc. Gas Division service territories became the UGI Central, UGI North and UGI South rate districts of the UGI Utilities, Inc. Gas Division, respectively, without any ratemaking change. UGI Utilities’ obligations under the settlement approved by the PAPUC include various non-monetary conditions requiring UGI Utilities to maintain separate accounting-type schedules for limited future ratemaking purposes. Base Rate Filings. On January 28, 2019, the merged 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 . As part of this rate request, Gas Utility also proposed to create uniform class rates under a single tariff such that all members of each customer class, throughout a consolidated UGI Gas service territory, would be charged the same base distribution and purchased gas cost rates, and other surcharges, eliminating the need to maintain the former UGI North, UGI South, and UGI Central rate districts formed as part of the earlier merger. In its initial filing, Gas Utility proposed a 4.5% negative surcharge applicable to all customer distribution service bills to return to ratepayers $24.0 of tax benefits experienced by UGI Utilities over the period January 1, 2018 to June 30, 2018, plus applicable interest, thereby satisfying a requirement to make a proposal for distributing those benefits within three years of the May 17, 2018 PAPUC Order. 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 tariff, approved a plan for uniform class rates, and permits the Company 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 the negative surcharge, mentioned above, which became effective for a twelve-month period beginning on October 11, 2019. On January 26, 2018, Electric Utility filed a rate request with the PAPUC to increase its annual base distribution revenues by $9.2 , which was later reduced by Electric Utility to $7.7 to reflect the impact of the TCJA and other adjustments. The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable electric service. On October 25, 2018, the PAPUC approved a final Order providing for a $3.2 annual base distribution rate increase for Electric Utility, effective October 27, 2018. As part of the final 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. UGI Utilities cannot predict the ultimate outcome of this appeal. On August 31, 2017, the PAPUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for an $ 11.3 base distribution rate increase for PNG (now part of the consolidated UGI Gas service territory). The increase became effective on October 20, 2017.

Inventories

Inventories	12 Months Ended
	Sep. 30, 2019
Inventory Disclosure [Abstract]
Inventories	Note 10 — Inventories Inventories comprise the following at September 30: 2019 2018 Non-utility LPG and natural gas $ 150.2 $ 231.7 Gas Utility natural gas 26.6 37.3 Materials, supplies and other 53.1 49.2 Total inventories $ 229.9 $ 318.2 At September 30, 2019 , UGI Utilities was a party to four SCAAs with terms up to three years . Pursuant to 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 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 a non-affiliate at September 30, 2018 , comprising 2.3 bcf of natural gas, was $5.4 .

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Sep. 30, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Note 11 — Property, Plant and Equipment Property, plant and equipment comprise the following at September 30: 2019 2018 Utility: Distribution $ 3,366.2 $ 3,106.6 Transmission 106.0 97.1 General and other 389.3 281.7 Work in process 76.6 130.9 Total Utility 3,938.1 3,616.3 Non-utility: Land 183.5 191.4 Buildings and improvements 403.8 364.9 Transportation equipment 258.3 257.1 Equipment, primarily cylinders and tanks 3,455.2 3,375.4 Electric generation 326.9 319.5 Pipeline and related assets 1,150.2 473.0 Other 255.3 306.6 Work in process 101.7 57.9 Total non-utility 6,134.9 5,345.8 Total property, plant and equipment $ 10,073.0 $ 8,962.1

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Sep. 30, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	Note 12 — Goodwill and Intangible Assets Changes in the carrying amount of goodwill by reportable segment are as follows: AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Total Balance September 30, 2017 $ 2,001.3 $ 912.2 $ 11.6 $ 182.1 $ 3,107.2 Acquisitions 4.5 54.9 — — 59.4 Dispositions (2.8 ) — — — (2.8 ) Purchase accounting adjustments — 13.6 — — 13.6 Foreign currency translation — (17.0 ) — — (17.0 ) Balance September 30, 2018 2,003.0 963.7 11.6 182.1 3,160.4 Acquisitions — 25.6 329.9 — 355.5 Foreign currency translation — (59.5 ) — — (59.5 ) Balance September 30, 2019 $ 2,003.0 $ 929.8 $ 341.5 $ 182.1 $ 3,456.4 Intangible assets comprise the following at September 30: 2019 2018 Customer relationships $ 1,038.4 $ 790.4 Trademarks and tradenames 16.2 7.9 Noncompete agreements and other 46.4 58.2 Accumulated amortization (441.8 ) (393.2 ) Intangible assets, net (definite-lived) 659.2 463.3 Trademarks and tradenames (indefinite-lived) 49.4 50.3 Total intangible assets, net $ 708.6 $ 513.6 The increase in the gross carrying amount of intangible assets in Fiscal 2019 is due to acquisitions partially offset by the effects of currency translation. Amortization expense of intangible assets was $59.6 , $58.6 and $50.8 for Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , respectively. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2020 — $64.6 ; Fiscal 2021 — $61.4 ; Fiscal 2022 — $58.3 ; Fiscal 2023 — $56.8 ; Fiscal 2024 — $55.6 . In April 2018, a plan to discontinue the use of certain indefinite-lived tradenames and trademarks, primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane, was presented to the Partnership’s senior management. After considering the merits of the plan, the Partnership’s senior management approved a plan to discontinue the use of these tradenames and trademarks over a period of approximately three years . As a result, during the third quarter of Fiscal 2018, the Partnership determined that these tradenames and trademarks no longer had indefinite lives and adjusted the carrying amounts of these tradenames and trademarks to their estimated fair values of approximately $7.9 . During the third quarter of Fiscal 2018, the Partnership recorded a non-cash, pre-tax impairment charge of $75.0 which amount is reflected in “Impairment of Partnership tradenames and trademarks” on the Consolidated Statements of Income, and is amortizing the remaining fair value of these tradenames and trademarks of $7.9 over their estimated period of benefit of three years . See Note 17 for further information on the determination of fair values for the affected tradenames and trademarks.

Series Preferred Stock

Series Preferred Stock	12 Months Ended
	Sep. 30, 2019
Equity [Abstract]
Series Preferred Stock	Note 13 — Series Preferred Stock UGI has 10,000,000 shares of UGI Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. UGI had no shares of UGI Series Preferred Stock outstanding at September 30, 2019 or 2018 . UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. At September 30, 2019 and 2018 , there were no shares of UGI Utilities Series Preferred Stock outstanding.

Common Stock and Equity-Based C

Common Stock and Equity-Based Compensation	12 Months Ended
	Sep. 30, 2019
Share-based Payment Arrangement [Abstract]
Common Stock and Equity-Based Compensation	Note 14 — Common Stock and Equity-Based Compensation Common Stock On January 25, 2018, UGI’s Board of Directors approved an extension of the Company’s share repurchase program, which authorizes the repurchase of up to 8,000,000 shares of UGI Corporation Common Stock over a four -year period. Pursuant to these authorizations, during Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , the Company purchased and placed in treasury stock 300,000 , 1,200,000 and 900,000 shares at a total cost of $16.9 , $59.8 and $43.3 , respectively. UGI Common Stock share activity for Fiscal 2017 , Fiscal 2018 and Fiscal 2019 follows: Issued Treasury Outstanding Balance at September 30, 2016 173,894,141 (933,692 ) 172,960,449 Issued: Employee and director plans 93,550 1,051,704 1,145,254 Sale of reacquired common stock 50,000 50,000 Repurchases of common stock — (900,000 ) (900,000 ) Reacquired common stock – employee and director plans — (111,966 ) (111,966 ) Balance at September 30, 2017 173,987,691 (843,954 ) 173,143,737 Issued: Employee and director plans 155,306 1,804,712 1,960,018 Repurchases of common stock — (1,200,000 ) (1,200,000 ) Reacquired common stock – employee and director plans — (154,780 ) (154,780 ) Balance at September 30, 2018 174,142,997 (394,022 ) 173,748,975 Issued: Employee and director plans 548,285 430,847 979,132 AmeriGas Merger 34,612,847 — 34,612,847 Sale of reacquired common stock — 15,759 15,759 Repurchases of common stock — (300,000 ) (300,000 ) Reacquired common stock – employee and director plans — (51,924 ) (51,924 ) Balance at September 30, 2019 209,304,129 (299,340 ) 209,004,789 Equity-Based Compensation The Company grants equity-based awards to employees and non-employee directors comprising UGI stock options, UGI Common Stock-based equity instruments and, prior to the AmeriGas Merger, AmeriGas Partners Common Unit-based equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $18.1 ( $13.2 after-tax), $22.5 ( $15.7 after-tax) and $19.3 ( $11.8 after-tax) in Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , respectively. UGI Equity-Based Compensation Plans and Awards. Under the UGI Corporation 2013 OICP, we may grant options to acquire shares of UGI Common Stock, SARs, UGI Units (comprising “Stock Units” and “UGI Performance Units”), other equity-based awards and cash to employees and non-employee directors. The exercise price for options may not be less than the fair market value on the grant date. Awards granted under the 2013 OICP may vest immediately or ratably over a period of years, and stock options can be exercised no later than ten years from the grant date. In addition, the 2013 OICP provides that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each unvested grant will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements. Under the 2013 OICP, awards representing up to 21,750,000 shares of UGI Common Stock may be granted. Dividend equivalents on UGI Unit Awards to employees will be paid in cash. Dividend equivalents on non-employee director awards are accumulated in additional Stock Units. UGI Unit Awards granted to employees and non-employee directors are settled in shares of UGI Common Stock and cash. Substantially all UGI Unit Awards granted to UGI France employees are settled in shares of UGI Common Stock and do not accrue dividend equivalents. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance goals and service conditions. Beginning in Fiscal 2019, we began issuing shares of UGI Common Stock to satisfy substantially all option exercises and UGI Unit Awards. Prior to Fiscal 2019, we issued treasury shares to satisfy substantially all option exercises and UGI Unit Awards. Stock options may be net exercised whereby shares equal to the option price and the grantee’s applicable payroll tax withholding are withheld from the number of shares payable (“net exercise”). We record shares withheld pursuant to a net exercise as shares reacquired. Pursuant to the AmeriGas Merger Agreement, all holders of AmeriGas Partners equity-based compensation awards received replacement awards comprising UGI cash-settled restricted stock units. See discussion below under “AmeriGas Partners Equity-Based Compensation Plans and Awards” for additional information. UGI Stock Option Awards . Stock option transactions under equity-based compensation plans during Fiscal 2017 , Fiscal 2018 and Fiscal 2019 follow: Shares Weighted - Average Option Price Total Intrinsic Value Weighted - Average Contract Term (Years) Shares under option — September 30, 2016 8,488,451 $ 26.68 $ 157.6 6.6 Granted 1,343,800 $ 46.51 Canceled (60,236 ) $ 41.86 Exercised (990,267 ) $ 21.40 $ 26.7 Shares under option — September 30, 2017 8,781,748 $ 30.20 $ 146.7 6.3 Granted 1,401,400 $ 47.85 Canceled (152,017 ) $ 42.14 Expired (1,666 ) $ 35.80 Exercised (1,832,396 ) $ 26.00 $ 44.5 Shares under option — September 30, 2018 8,197,069 $ 33.93 $ 176.6 6.2 Granted 1,197,100 $ 53.27 Canceled (123,012 ) $ 48.69 Expired (13,699 ) $ 47.49 Exercised (779,353 ) $ 25.75 $ 22.8 Shares under option — September 30, 2019 8,478,105 $ 37.18 $ 114.9 5.9 Options exercisable — September 30, 2017 5,973,668 $ 25.53 Options exercisable — September 30, 2018 5,498,330 $ 28.63 Options exercisable — September 30, 2019 5,963,530 $ 32.02 $ 109.3 4.9 Options not exercisable — September 30, 2019 2,514,575 $ 49.43 $ 5.6 7.4 Cash received from stock option exercises and associated tax benefits were $19.5 and $5.1 , $43.4 and $12.6 , and $17.7 and $9.6 in Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , respectively. As of September 30, 2019 , there was $8.3 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 2.0 years. The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2019 : Range of exercise prices Under $30.00 $30.00 – $35.00 $35.01 – $40.00 $40.01 – $45.00 Over $45.00 Options outstanding at September 30, 2019: Number of options 2,879,501 1,094,763 870,115 81,593 3,552,133 Weighted average remaining contractual life (in years) 3.1 6.1 5.3 7.1 8.3 Weighted average exercise price $ 23.24 $ 33.66 $ 37.81 $ 44.42 $ 49.25 Options exercisable at September 30, 2019: Number of options 2,879,501 995,313 870,115 76,593 1,142,008 Weighted average exercise price $ 23.24 $ 33.65 $ 37.81 $ 44.48 $ 47.48 UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $8.70 in Fiscal 2019 , $7.51 in Fiscal 2018 and $7.62 in Fiscal 2017 . These amounts were determined using a Black-Scholes option pricing model that values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, expected dividend payments and the risk-free interest rate over the expected life of the option. The expected life of option awards represents the period of time during which option grants are expected to be outstanding and is derived from historical exercise patterns. Expected volatility is based on historical volatility of the price of UGI’s Common Stock. Expected dividend yield is based on historical UGI dividend rates. The risk free interest rate is based on U.S. Treasury bonds with terms comparable to the options in effect on the date of grant. The assumptions we used for valuing option grants during Fiscal 2019 , Fiscal 2018 and Fiscal 2017 are as follows: 2019 2018 2017 Expected life of option 6 years 6 years 5.75 years Weighted average volatility 17.2% 17.5% 19.8% Weighted average dividend yield 1.8% 2.1% 2.1% Expected volatility 17.2% 17.5% 19.8% Expected dividend yield 1.8% 2.1% 2.1% Risk free rate 1.5% – 2.6% 2.2% – 2.9% 1.8% – 2.1% UGI Unit Awards . UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of UGI Performance Units. The number of UGI Performance Units ultimately paid at the end of the performance period (generally three years ) may be higher or lower than the target amount, or even zero, based on UGI’s TSR percentile rank relative to the UGI comparator group. Grantees may receive 0% to 200% of the target award granted. For such grants, if UGI’s TSR ranks below the 25th percentile compared to the UGI comparator group, the employee will not be paid. At the 25th percentile, the employee will be paid an award equal to 25% of the target award; at the 40th percentile, 70% ; at the 50th percentile, 100% ; and at the 90th percentile and above, 200% . The actual amount of the award is interpolated between these percentile rankings. Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest. The fair value of UGI Stock Units on the grant date is equal to the market price of UGI Stock on the grant date plus the fair value of dividend equivalents if applicable. Under GAAP, UGI Performance Units are equity awards with a market-based condition which, if settled in shares, result in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of UGI Performance Units are estimated using a Monte Carlo valuation model. The fair value associated with the target award is accounted for as equity and the fair value of the award over the target, as well as all dividend equivalents, is accounted for as a liability. The expected term of the UGI Performance Unit awards is three years based on the performance period. Expected volatility is based on the historical volatility of UGI Common Stock over a three -year period. The risk-free interest rate is based on the yields on U.S. Treasury bonds at the time of grant. Volatility for all companies in the UGI comparator groups is based on historical volatility. The following table summarizes the weighted-average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs: Grants Awarded in Fiscal Year 2019 2018 2017 Risk free rate 2.5% 2.0% 1.5% Expected life 3 years 3 years 3 years Expected volatility 17.7% 18.9% 18.9% Dividend yield 1.9% 2.1% 2.1% The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $55.40 for Units granted in Fiscal 2019 , $55.26 for Units granted in Fiscal 2018 and $50.91 for Units granted in Fiscal 2017 . The following table summarizes UGI Unit award activity for Fiscal 2019 : UGI Units Weighted-Average Grant-Date Fair Value (per Unit) Total UGI Units at September 30, 2018 (a) 959,718 $ 32.38 UGI Performance Units: Granted 128,910 $ 55.40 Forfeited (13,102 ) $ 53.29 Unit awards paid (144,521 ) $ 34.62 UGI Stock Units: Granted (b) 29,784 $ 55.39 Forfeited (4,900 ) $ 51.22 Unit awards paid (62,069 ) $ 25.12 Total UGI Units at September 30, 2019 (a) 893,820 $ 36.39 (a) Total UGI Units includes UGI Stock Units issued to non-employee directors, which vest on the grant date, and UGI Performance Units and UGI Stock Units issued to retirement-eligible employees that vest on an accelerated basis. Total vested restricted units at September 30, 2019 and September 30, 2018 were 616,319 and 660,795 , respectively. (b) Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2018 and Fiscal 2017 were 52,314 and 42,079 , respectively. During Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows: 2019 2018 2017 UGI Performance Unit awards: Number of original awards granted, net of forfeitures 144,521 136,621 178,450 Performance period beginning January 1: 2016 2015 2014 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 116,950 69,680 138,985 Cash paid $ 9.9 $ 1.6 $ 10.9 UGI Stock Unit awards: Number of original awards granted, net of forfeitures 50,985 39,680 43,699 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 43,479 29,095 15,990 Cash paid $ 1.0 $ 0.6 $ 0.3 During Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , we granted UGI Unit awards representing 158,694 , 196,114 and 185,379 shares, respectively, having weighted-average grant date fair values per Unit of $55.40 , $53.36 and $50.08 , respectively. As of September 30, 2019 , there was a total of approximately $7.6 of unrecognized compensation cost associated with 893,820 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.9 years . The total grant-date fair values of UGI Units that vested during Fiscal 2019 , Fiscal 2018 and Fiscal 2017 were $4.9 , $7.3 and $7.1 , respectively. As of September 30, 2019 and 2018 , total liabilities of $10.2 and $18.8 , respectively, associated with UGI Unit awards are reflected in “ Employee compensation and benefits accrued ” and “ Other noncurrent liabilities ” on the Consolidated Balance Sheets. At September 30, 2019 , 8,700,734 shares of Common Stock were available for future grants under the 2013 OICP, which includes the number of AmeriGas Common Units available for grant under the 2010 Propane Plan that were converted to UGI Units as further described below. AmeriGas Partners Equity-Based Compensation Plans and Awards. Prior to the AmeriGas Merger, under the 2010 Propane Plan on behalf of AmeriGas Partners, L.P., the General Partner could award to employees and non-employee directors of the General Partner grants of AmeriGas Partners Units (comprising “AmeriGas Stock Units” and “AmeriGas Performance Units”), options, phantom units, unit appreciation rights and other Common Unit-based awards that, depending on the award, vested immediately or ratable over a period of time. Under the terms of the 2010 Propane Plan, each unvested grant generally terminated when the participant ceased to be employed (except in the event of retirement, death or disability, as defined). The 2010 Propane Plan also defined certain change of control and retirement eligibility conditions that, if met, generally resulted in accelerated vesting or elimination of further service requirements. Participants were eligible to receive Common Unit distribution equivalents under the terms of certain awards (ultimately paid in cash only on awards that vested). Effective with the AmeriGas Merger, all outstanding AmeriGas Stock Units and AmeriGas Performance Units were canceled and converted to cash-settled restricted stock units relating to UGI Common Stock (see “Impact of AmeriGas Merger on AmeriGas Unit Awards” below). AmeriGas Stock Unit and AmeriGas Performance Unit awards entitled the grantee to AmeriGas Partners Common Units or cash once the service condition was met and, with respect to AmeriGas Performance Units, subject to market performance conditions or actual net customer acquisition and retention performance (as defined in the applicable awards). Recipients were awarded a target number of AmeriGas Performance Units, and the number of AmeriGas Performance Units ultimately paid at the end of the performance period (generally three years ) could have been higher or lower than the target number, or it may have been zero. For that portion of Performance Unit awards whose ultimate payout was based upon market-based conditions (“AmeriGas TUR Performance Units”), the number of awards ultimately paid was based upon AmeriGas Partners’ TUR percentile rank relative to entities in the Tortoise MLP Group for those awards granted on or after January 1, 2019, and AmeriGas Partners’ TUR percentile rank relative to entities in the Alerian MLP Group with certain awards subject to modification as described below for those awards granted prior to January 1, 2019. AmeriGas TUR Performance Unit awards provided various performance target tiers ranging from 0% to 200% , with 0% payment when the AmeriGas Partners’ TUR was below the 25th percentile and up to 200% payment at the 90th percentile or above. The actual amount of the award was interpolated between the percentile rankings of each performance target tier. For AmeriGas TUR Performance Unit awards granted on or after January 1, 2015, but prior to January 1, 2019, the number of AmeriGas TUR Performance Units ultimately paid was based upon AmeriGas Partner’s TUR percentile rank relative to entities in the Alerian MLP Group ( 0% to 200% as described above) as modified by AmeriGas Partners’ performance relative to the Propane MLP Group. Such modification ranged from 70% to 130% , but in no event did the amount ultimately paid, after such modification, exceed 200% of the target award. Pursuant to the terms of the AmeriGas Merger Agreement, the performance periods for AmeriGas TUR Performance Units outstanding immediately prior to the AmeriGas Merger ended on August 20, 2019, the last trading day of the Common Units prior to the completion of the AmeriGas Merger. Under GAAP, AmeriGas TUR Performance Units awards were recorded as equity awards to the extent they were to be settled in Common Units. This resulted in the recognition of compensation cost equal to the fair value of such award estimated using a Monte Carlo valuation model, over the requisite employee service period regardless of whether the market-based conditions were satisfied. The fair value associated with the target awards, which were to be paid in Common Units, was accounted for as equity and the fair value of the award over the target, as well as all Common Unit distribution equivalents, which were to be paid in cash, was accounted for as a liability. For purposes of valuing AmeriGas TUR Performance Unit awards, expected volatility was based on the historical volatility of Common Units over a three -year period. The risk-free interest rate was based on the rates on U.S. Treasury bonds at the time of grant. Volatility for all entities in the peer group was based on historical volatility. The expected term of the AmeriGas TUR Performance Unit awards was three years based on the performance period. AmeriGas Performance Unit awards whose ultimate payout was based upon net customer acquisition and retention performance measures were recorded as expense if it became probable that all or a portion of the award would be paid. The fair value associated with the target award was the market price of the Common Units on the date of grant and was accounted for as equity. The fair value of the award over the target, as well as all Common Unit distribution equivalents, which were to be paid in cash, was accounted for as a liability. The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards subject to market-based conditions and related compensation costs: Grants Awarded in Fiscal Year 2019 2018 2017 Risk-free rate 2.5% 2.0% 1.5% Expected life 3 years 3 years 3 years Expected volatility 22.4% 21.1% 21.7% Dividend yield 12.5% 8.2% 7.8% The General Partner granted awards under the 2010 Propane Plan representing 133,098 , 84,811 and 67,563 Common Units in Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , respectively, having weighted-average grant date fair values per Common Unit subject to award of $30.58 , $50.05 and $52.37 , respectively. The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2019 : AmeriGas Partners Common Units Weighted-Average Grant-Date Fair Value (per Unit) Total Units at September 30, 2018 (a) 236,762 $ 47.12 AmeriGas Performance Units: Granted 79,980 $ 30.23 Forfeited (42,916 ) $ 46.83 Awards paid (17,133 ) $ 43.02 Performance criteria not met (29,394 ) $ 34.27 AmeriGas Stock Units: Granted 53,118 $ 31.10 Forfeited (800 ) $ 45.30 Awards paid (16,056 ) $ 40.98 Total Units at the date of AmeriGas Merger (a) 263,561 $ 40.89 Units converted to UGI cash-settled restricted units (263,561 ) $ (40.89 ) Total Units at September 30, 2019 — $ — (a) Total units includes AmeriGas Stock Units issued to non-employee directors, which vested on the grant date, and AmeriGas Performance Units and AmeriGas Stock Units issued to retirement-eligible employees that vest on an accelerated basis. Total vested restricted units at September 30, 2018 were 71,148 . During Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows: 2019 2018 2017 AmeriGas Performance Unit awards: Number of Common Units subject to original awards granted, net of forfeitures 52,495 65,525 53,800 Performance periods beginning in fiscal year: 2016 2015 2014 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 10,902 13,164 29,489 Cash paid $ 0.8 $ 1.2 $ 2.9 AmeriGas Stock Unit awards: Number of Common Units subject to original awards granted, net of forfeitures 20,585 14,811 32,658 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 9,706 5,322 3,932 Cash paid $ 0.2 $ 0.1 $ 0.1 The total grant-date fair values of AmeriGas Unit awards that vested during Fiscal 2019, Fiscal 2018 and Fiscal 2017 were $0.9 , $2.2 and $2.1 , respectively. As of September 30, 2018, total liabilities of $2.3 associated with Common Unit-based awards are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” on the Consolidated Balance Sheet. Impact of AmeriGas Merger on AmeriGas Unit Awards. Effective with the AmeriGas Merger on August 21, 2019, each outstanding award of AmeriGas Stock Units and AmeriGas Performance Units, including awards subject to market performance conditions, was canceled and converted into a number of cash-settled restricted stock units relating to UGI Common Stock determined by multiplying the number of such AmeriGas Unit awards by 0.6378 . With respect to outstanding AmeriGas TUR Performance Units, the number of such awards canceled and converted to UGI restricted stock units was determined by multiplying the target number of such awards times the performance multiplier as determined based upon a shortened performance period ending August 20, 2019, the last full trading day of the Common Units prior to the AmeriGas Merger. In accordance with the AmeriGas Merger Agreement, the resulting number of cash-settled restricted stock units relating to UGI Common Stock could be more, but not less, than the associated target number of AmeriGas TUR Performance Unit awards. These restricted stock units vest on the originally scheduled AmeriGas TUR Performance Unit award vesting dates with the only condition being employment with the Company at the time of vesting. With respect to AmeriGas Performance Unit awards whose payout was based upon net customer gain and retention performance, grantees’ target awards were canceled and converted to UGI cash-settled performance-based restricted units at a ratio of 0.6378 :1. Grantees of such awards may ultimately receive from 0% to 200% of the replacement awards based upon actual net customer gain and retention performance over the original three-year performance period. The converted awards remain subject to the same terms, conditions and restrictions as applied to the corresponding AmeriGas Unit awards immediately prior to the conversion including vesting terms, forfeitures, and distribution equivalent rights except that distribution equivalent rights will be based upon UGI dividends subsequent to the conversion. Pursuant to the terms of the AmeriGas Unit conversions described above, effective on August 21, 2019, 137,472 AmeriGas Performance Units and 126,089 AmeriGas Stock Units were converted into 215,957 of cash-settled restricted stock units relating to UGI Common Stock. The UGI cash-settled restricted stock units issued as replacement awards, other than those issued to AmeriGas’ independent board directors who terminated their directorship effective with the AmeriGas Merger, have been accounted for as modifications in accordance with ASC 718 which contemplates an exchange of the original award for a new award. Since the modifications changed the fixed portion of the award from an equity to a cash-settled award, any compensation expense related to an increase in the fair value of the award between the original grant date and the modification date was accounted for as equity. All compensation expense on the replacement awards recognized subsequent to the modification will be accounted for as a liability. The AmeriGas independent board members who terminated their directorship on August 21, 2019, received a cash payment based upon the market price of UGI Common Stock on that date, plus accrued distribution equivalents, totaling $1.8 . These payments were accounted for as settlements in accordance with ASC 718. All amounts accrued with respect to dividend equivalents relating to AmeriGas equity-compensation awards were carried over to the corresponding UGI replacement awards and will be paid, or forfeited, on the same terms and conditions as applied under the AmeriGas Unit awards. Holders of UGI replacement awards will receive a cash payment at the end of the performance period associated with such awards equal to the market price of UGI Common Stock plus any accumulated distribution or dividend equivalents, if applicable. As of September 30, 2019, there was a total of approximately $2.4 of unrecognized compensation cost associated with 212,896 UGI cash-settled restricted stock units that is expected to be recognized over a weighted-average period of 1.3 years. As of September 30, 2019, total liabilities of $4.6 associated with UGI cash-settled restricted stock units are reflected in “Employee compensation and benefits accrued” and “Other noncurrent liabilities” on the Consolidated Balance Sheet. UGI has assumed the obligations of the General Partner and the Partnership under the 2010 Propane Plan, and the 2010 Propane Plan was deemed amended to conform to all of the terms and form of the 2013 OICP and combined with the 2013 OICP. The number of Common Units that remain available for grant under the 2010 Propane Plan were converted to 1,420,949 UGI awards available for future grant and delivery based upon a conversion ratio of 0.6378 :1. These available converted awards may be granted only to those individuals who were eligible to receive awards under the 2010 Propane Plan immediately before the AmeriGas Merger including any such eligible individuals hired after the AmeriGas Merger.

Partnership Distributions

Partnership Distributions	12 Months Ended
	Sep. 30, 2019
Distributions Made to Members or Limited Partners [Abstract]
Partnership Distributions	Note 15 — Partnership Distributions In accordance with the Partnership Agreement, the Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount equal to its Available Cash (as defined in the Partnership Agreement) for such quarter. Available Cash is generally defined as: 1. all cash on hand at the end of such quarter, plus 2. all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter, less 3. the amount of cash reserves established by the General Partner in its reasonable discretion. The General Partner may establish reserves for the proper conduct of the Partnership’s business and for distributions during the next four quarters. Prior to the AmeriGas Merger, distributions of Available Cash were made 98% to limited partners and 2% to the General Partner (representing a 1% General Partner interest in AmeriGas Partners and 1.01% interest in AmeriGas OLP) until Available Cash exceeded the Minimum Quarterly Distribution of $0.55 and the First Target Distribution of $0.055 per Common Unit (or a total of $0.605 per Common Unit). When Available Cash exceeded $0.605 per Common Unit in any quarter, the General Partner would receive a greater percentage of the total Partnership distribution (the “incentive distribution”) but only with respect to the amount by which the distribution per Common Unit to limited partners exceeded $0.605 . During Fiscal 2019 (prior to the AmeriGas Merger), Fiscal 2018 and Fiscal 2017 , the Partnership made quarterly distributions to Common Unitholders in excess of $0.605 per limited partner unit. As a result, the General Partner received a greater percentage of the total Partnership distribution than its aggregate 2% general partner interest in AmeriGas OLP and AmeriGas Partners. During Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $54.9 , $54.9 and $52.7 , respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2019 , Fiscal 2018 and Fiscal 2017 of $45.7 , $45.3 and $43.5 , respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Sep. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 16 — Commitments and Contingencies Commitments Leases We lease various buildings and other facilities and vehicles, computer and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such leases was $115.1 in Fiscal 2019 , $106.2 in Fiscal 2018 and $99.5 in Fiscal 2017 . Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows: 2020 2021 2022 2023 2024 After 2024 AmeriGas Propane $ 82.1 $ 71.6 $ 60.0 $ 52.3 $ 45.0 $ 94.8 UGI Utilities 1.2 0.5 0.4 0.3 0.3 — UGI International 12.9 10.0 7.0 5.7 5.1 6.5 Other 4.2 3.8 3.6 3.4 3.2 37.9 Total $ 100.4 $ 85.9 $ 71.0 $ 61.7 $ 53.6 $ 139.2 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 September 30, 2019 and 2018 , our aggregate estimated accrued liabilities for environmental investigation and remediation costs related to the COAs totaled $50.4 and $51.0 , respectively. UGI Utilities has recorded an associated regulatory asset for these costs because recovery of these costs from customers is probable (see Note 9 ). We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to UGI Utilities’ results of operations because UGI Utilities receives ratemaking recovery of actual environmental investigation and remediation costs associated with the sites covered by the COAs. This ratemaking recognition reconciles the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by a former subsidiary. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by a former subsidiary of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At September 30, 2019 and 2018 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities’ MGP sites outside Pennsylvania was material. AmeriGas Propane AmeriGas OLP Saranac Lake. In 2008, the NYDEC notified AmeriGas OLP that the NYDEC had placed property purportedly owned by AmeriGas OLP in Saranac Lake, New York on the New York State Registry of Inactive Hazardous Waste Disposal Sites. A site characterization study performed by the NYDEC disclosed contamination related to a former MGP. AmeriGas OLP responded to the NYDEC in 2009 to dispute the contention it was a PRP as it did not operate the MGP and appeared to only own a portion of the site. In 2017, the NYDEC communicated to AmeriGas OLP that the NYDEC had previously issued three RODs related to remediation of the site totaling approximately $27.7 and requested additional information regarding AmeriGas OLP’s purported ownership. AmeriGas 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, the Partnership accrued an undiscounted environmental remediation liability of $7.5 related to the site during Fiscal 2017, which amount is included in “Operating and administrative expenses” on the Consolidated Statements of Income. 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.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Sep. 30, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 17 — Fair Value Measurements Recurring Fair Value Measurements The following table presents, on a gross basis, our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2 : Asset (Liability) Level 1 Level 2 Level 3 Total 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 September 30, 2018 Derivative instruments: Assets: Commodity contracts $ 93.5 $ 117.5 $ — $ 211.0 Foreign currency contracts $ — $ 20.6 $ — $ 20.6 Cross-currency contracts $ — $ 0.9 $ — $ 0.9 Liabilities: Commodity contracts $ (33.6 ) $ (9.8 ) $ — $ (43.4 ) Foreign currency contracts $ — $ (14.4 ) $ — $ (14.4 ) Interest rate contracts $ — $ (1.0 ) $ — $ (1.0 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 40.8 $ — $ — $ 40.8 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 8 ). The fair values of our Level 1 exchange-traded commodity futures and option contracts and non-exchange-traded commodity futures and forward contracts are based upon actively quoted market prices for identical assets and liabilities. The remainder of our derivative instruments are designated as Level 2. The fair values of certain non-exchange-traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. The fair values of our Level 2 interest rate contracts, foreign currency contracts and cross-currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. Nonrecurring Fair Value Measurements As discussed in Note 12 , in April 2018, the Partnership’s senior management approved a plan to discontinue the use of certain indefinite-lived tradenames and trademarks, primarily associated with the Partnership’s January 2012 acquisition of Heritage Propane, over a period of approximately three years . This action required the Partnership to remeasure the fair values of these tradenames and trademarks based upon their remaining period of benefit. The Partnership used the relief from royalty method to estimate the fair values of the tradenames and trademarks, which method estimates our theoretical royalty savings from ownership of the tradenames and trademarks. Key assumptions used in this method include discount rates, royalty rates, growth rates and sales projections. These assumptions reflect current economic conditions, management expectations and projected future cash flows expected to be generated from these tradenames and trademarks. The Partnership determined that the lowest level of the inputs that were significant to the fair value measurement were unobservable inputs that fall within Level 3 of the fair value hierarchy. As of the April 2018 measurement date, these tradenames and trademarks had an estimated fair value of $7.9 . 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: 2019 2018 Carrying amount $ 5,856.6 $ 4,199.4 Estimated fair value $ 6,189.3 $ 4,150.3 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 18

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Sep. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 18 — 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 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 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 9 ). Electricity Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At September 30, 2019 and 2018 , all Electric Utility forward electricity purchase contracts were subject to the NPNS exception. Non-utility Operations LPG In order to manage market price risk associated with the Partnership’s fixed-price programs, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, 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 From time to time we enter into long-term debt agreements with interest rates that are generally indexed to short-term market interest rates. In order to fix the underlying short-term market interest rates, we enter into pay-fixed, receive-variable interest rate swap agreements and designate such swaps as cash flow hedges. As more fully described in Note 6, during Fiscal 2019 UGI Corporation, UGI International, LLC and Energy Services entered into variable-rate, long-term debt agreements and also entered into associated pay-fixed, receive-variable interest rate swap agreements for all or a significant portion of the loans’ outstanding principal balance, and all or a significant portion of the loans’ tenor. In Fiscal 2018, UGI Utilities entered into a variable-rate amortizing term loan agreement and also entered into a forward starting, amortizing, pay-fixed, receive-variable interest rate swap agreement commencing September 30, 2019. Prior to their repayment on October 25, 2018 (see Note 6 ), UGI France’s and Flaga’s long-term debt agreements had interest rates that were generally indexed to short-term market interest rates. UGI France and Flaga entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor and LIBOR rates of interest on these variable-rate debt agreements. We designated these interest rate swaps as cash flow hedges. These interest rate swaps were settled concurrent with the repayment of the UGI France and Flaga long-term debt. The remainder of our businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into in IRPAs. We account for IRPAs as cash flow hedges. At September 30, 2019 and 2018 , we had no unsettled IRPAs. At September 30, 2019 , the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3.5 . Foreign Currency Exchange Rate Risk Forward Foreign Currency Exchange Contracts In order to reduce 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 income (expense), net ” on the Consolidated Statements of Income. In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we entered into forward foreign currency exchange contracts to hedge a portion of anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March, expiring through September 2019. We accounted for these foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At September 30, 2019, there were no amounts associated with these contracts remaining in AOCI. 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. Concurrent with the issuance of euro-denominated long-term debt under the 2018 UGI International Credit Facilities Agreement and the UGI International 3.25% Senior Notes in October 2018, we designated this euro-denominated debt as net investment hedges of a portion of our euro-denominated UGI International net investment (see Note 6 ). Cross-currency Contracts Prior to its repayment on October 25, 2018 (see Note 6 ), Flaga entered into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of its U.S. dollar denominated variable-rate term loan. These cross-currency hedges included initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. These cross-currency swaps also included interest rate swaps of a floating U.S. dollar-denominated interest rate to a fixed euro-denominated interest rate. We designated these cross-currency swaps as cash flow hedges. These cross-currency swaps were settled concurrent with the repayment of Flaga’s U.S. dollar variable rate term loan in October 2018. Quantitative Disclosures Related to Derivative Instruments The following table summarizes by derivative type the gross notional amounts related to open derivative contracts at September 30, 2019 and 2018 and the final settlement date of the Company's open derivative transactions as of September 30, 2019 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) September 30, Type Units Settlements Extending Through 2019 2018 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms October 2020 23.3 23.2 Non-utility Operations LPG swaps Gallons September 2021 800.4 394.3 Natural gas futures, forward and pipeline contracts Dekatherms December 2024 196.1 159.7 Natural gas basis swap contracts Dekatherms December 2024 131.1 54.4 NYMEX natural gas storage futures contracts Dekatherms March 2020 0.3 1.8 NYMEX natural gas option contracts Dekatherms March 2020 2.4 — NYMEX propane storage futures contracts Gallons April 2020 0.5 0.6 Electricity long forward and futures contracts Kilowatt hours January 2023 3,098.1 4,307.6 Electricity short forward and futures contracts Kilowatt hours May 2022 366.7 359.3 Interest Rate Risk: Interest rate swaps Euro October 2022 € 300.0 € 585.8 Interest rate swaps USD July 2024 $ 1,357.3 $ 114.1 Foreign Currency Exchange Rate Risk: Forward foreign exchange contracts USD September 2022 $ 516.0 $ 512.2 Net investment hedge forward foreign exchange contracts Euro October 2024 € 172.8 € — Cross-currency swaps USD N/A $ — $ 49.9 Derivative Instrument Credit Risk We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. At September 30, 2019 and 2018 , the Company paid (received) cash collateral of $29.3 and $(12.2) , respectively. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2019 and 2018 , restricted cash in brokerage accounts totaled $63.7 and $9.6 , 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 September 30, 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 September 30, 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 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 Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements. Fair Value of Derivative Instruments The following table presents the Company’s derivative assets and liabilities by type, as well as the effects of offsetting, as of September 30: 2019 2018 Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 17.4 $ 1.5 Cross-currency contracts — 0.9 17.4 2.4 Derivatives subject to PGC and DS mechanisms: Commodity contracts 1.4 3.0 Derivatives not designated as hedging instruments: Commodity contracts 40.7 208.0 Foreign currency contracts 41.6 19.1 82.3 227.1 Total derivative assets – gross 101.1 232.5 Gross amounts offset in the balance sheet (29.0 ) (34.3 ) Cash collateral received — (12.2 ) Total derivative assets – net $ 72.1 $ 186.0 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ — $ (0.4 ) Interest rate contracts (12.3 ) (1.0 ) (12.3 ) (1.4 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (3.7 ) (0.1 ) Derivatives not designated as hedging instruments: Commodity contracts (171.3 ) (43.3 ) Foreign currency contracts (4.3 ) (14.0 ) (175.6 ) (57.3 ) Total derivative liabilities – gross (191.6 ) (58.8 ) Gross amounts offset in the balance sheet 29.0 34.3 Cash collateral pledged 29.3 — Total derivative liabilities – net $ (133.3 ) $ (24.5 ) Effects of Derivative Instruments The following tables provide information on the effects of derivative instruments on the Consolidated Statements of Income and changes in AOCI for Fiscal 2019 , Fiscal 2018 and Fiscal 2017 : Gain (Loss) Recognized in AOCI Gain (Loss) Reclassified from AOCI into Income Location of Gain (Loss) Reclassified from 2019 2018 2017 2019 2018 2017 Cash Flow Hedges: Foreign currency contracts $ 1.2 $ 0.4 $ 0.2 $ 2.4 $ (3.0 ) $ 17.8 Cost of sales Cross-currency contracts (0.1 ) 1.2 0.5 (0.3 ) 1.1 (0.1 ) Interest expense /other operating income, net Interest rate contracts (11.6 ) 0.2 1.5 (4.5 ) (5.0 ) (3.9 ) Interest expense Total $ (10.5 ) $ 1.8 $ 2.2 $ (2.4 ) $ (6.9 ) $ 13.8 Net Investment Hedges: Foreign currency contracts $ 17.4 $ — $ — Gain (Loss) Recognized in Income Location of Recognized in Income 2019 2018 2017 Derivatives Not Designated as Hedging Instruments: Commodity contracts $ (344.1 ) $ 155.4 $ 166.0 Cost of sales Commodity contracts 7.2 (5.3 ) (2.0 ) Revenues Commodity contracts (0.3 ) 0.3 0.2 Operating and administrative expenses Foreign currency contracts 37.7 16.2 (23.8 ) Other non-operating income (expense), net Total $ (299.5 ) $ 166.6 $ 140.4 For Fiscal 2019 , Fiscal 2018 , and Fiscal 2017 , the amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material. We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts that provide for the purchase and delivery, or sale, of energy products, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although certain of these contracts have the requisite elements of a derivative instrument, these contracts qualify for NPNS exception accounting because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Sep. 30, 2019
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Note 19 — Accumulated Other Comprehensive Income (Loss) Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and long-term intra-company transaction adjustments. Changes in AOCI during Fiscal 2019 , Fiscal 2018 and Fiscal 2017 are as follows: Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2016 $ (29.1 ) $ (13.4 ) $ (112.2 ) $ (154.7 ) Other comprehensive income before reclassification adjustments (after-tax) 6.5 1.7 59.4 67.6 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 5.5 (13.8 ) — (8.3 ) Reclassification adjustments tax (benefit) expense (2.1 ) 4.1 — 2.0 Reclassification adjustments (after-tax) 3.4 (9.7 ) — (6.3 ) Other comprehensive income (loss) attributable to UGI 9.9 (8.0 ) 59.4 61.3 AOCI - September 30, 2017 $ (19.2 ) $ (21.4 ) $ (52.8 ) $ (93.4 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) 10.4 1.0 (30.5 ) (19.1 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) (3.3 ) 6.9 — 3.6 Reclassification adjustments tax expense (benefit) 1.1 (2.6 ) — (1.5 ) Reclassification adjustments (after-tax) (2.2 ) 4.3 — 2.1 Other comprehensive income (loss) attributable to UGI 8.2 5.3 (30.5 ) (17.0 ) AOCI - September 30, 2018 $ (11.0 ) $ (16.1 ) $ (83.3 ) $ (110.4 ) Other comprehensive loss before reclassification adjustments (after-tax) (13.0 ) (7.3 ) (82.2 ) (102.5 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 1.7 2.4 — 4.1 Reclassification adjustments tax benefit (0.5 ) (0.7 ) — (1.2 ) Reclassification adjustments (after-tax) 1.2 1.7 — 2.9 Other comprehensive loss attributable to UGI (11.8 ) (5.6 ) (82.2 ) (99.6 ) Reclassification of stranded income tax effects related to TCJA (2.9 ) (3.7 ) — (6.6 ) AOCI - September 30, 2019 $ (25.7 ) $ (25.4 ) $ (165.5 ) $ (216.6 ) For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 18

Other Operating Income, Net

Other Operating Income, Net	12 Months Ended
	Sep. 30, 2019
Component of Operating Income [Abstract]
Other Operating Income, Net	Note 20 — Other Operating Income, Net Other operating income, net, for Fiscal 2019 , Fiscal 2018 and Fiscal 2017 comprises the following: 2019 2018 2017 Finance charges $ 16.5 $ 16.4 $ 11.8 AFUDC associated with pipeline projects — — 5.5 Interest and interest-related income 5.6 3.2 1.7 Utility non-tariff service income 0.7 2.8 1.5 Loss on private equity partnership investment (1.5 ) — (11.0 ) Gains (losses) on sales of fixed assets, net 2.9 5.3 (3.9 ) Other, net 6.9 3.6 4.9 Total other operating income, net $ 31.1 $ 31.3 $ 10.5

Quarterly Data (unaudited)

Quarterly Data (unaudited)	12 Months Ended
	Sep. 30, 2019
Quarterly Financial Data [Abstract]
Quarterly Data (unaudited)	Note 21 — Quarterly Data (unaudited) The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) that we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results fluctuate primarily because of the seasonal nature of our businesses and the effects of unrealized gains and losses on commodity and certain foreign currency derivative instruments (see Note 18 ) and other significant discrete items that can affect the comparison of period-over-period results. December 31, March 31, June 30, September 30, 2018 (a) 2017 (b) 2019 2018 (b) 2019 2018 (b) (c) 2019 (d) 2018 (b) Revenues $ 2,200.2 $ 2,125.2 $ 2,606.1 $ 2,812.0 $ 1,363.7 $ 1,440.9 $ 1,150.4 $ 1,273.1 Operating income (loss) $ 167.7 $ 395.0 $ 538.8 $ 591.0 $ 9.6 $ 29.5 $ (99.0 ) $ 49.2 Net income (loss) including noncontrolling interests $ 88.5 $ 434.2 $ 396.7 $ 407.7 $ (46.5 ) $ (11.7 ) $ (130.8 ) $ (7.8 ) Net income (loss) attributable to UGI Corporation $ 64.2 $ 365.9 $ 245.4 $ 276.0 $ (1.9 ) $ 52.4 $ (51.5 ) $ 24.4 Earnings (loss) per common share attributable to UGI Corporation stockholders: Basic $ 0.37 $ 2.11 $ 1.41 $ 1.59 $ (0.01 ) $ 0.30 $ (0.27 ) $ 0.14 Diluted $ 0.36 $ 2.07 $ 1.38 $ 1.57 $ (0.01 ) $ 0.30 $ (0.27 ) $ 0.14 Weighted-average common shares outstanding (thousands): Basic 174,413 173,670 174,501 173,570 174,759 173,991 189,905 174,391 Diluted 177,566 176,948 177,318 176,350 174,759 176,807 189,905 177,506 (a) Includes loss on extinguishments of debt at UGI International which reduced net income attributable to UGI by $4.2 (see Note 6 ). (b) The quarters ended December 31, 2017, March 31, 2018, June 30, 2018 and September 30, 2018, include the impact of adjustments to remeasure net deferred income tax liabilities associated with (1) the TCJA, including adjustments to provisional amounts, which increased (decreased) net income by $166.0 , $5.3 , $0.8 and $(5.8) , respectively, and (2) the December 2017 French Finance Bills, which increased (decreased) net income by $17.3 , $(3.7) , $(0.1) and $(1.4) , respectively (see Note 7 ). (c) Includes the impact of the impairment of Partnership tradenames and trademarks, which decreased net income attributable to UGI by $14.5 (see Notes 12 and 17 ). (d) Weighted-average common shares outstanding includes the impact from the August 2019 issuance of 34,612,847 shares of UGI Common Stock in connection with the AmeriGas Merger (see Note 5 ).

Segment Information

Segment Information	12 Months Ended
	Sep. 30, 2019
Segment Reporting [Abstract]
Segment Information	Note 22 — 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. AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers in all 50 states. UGI International derives its revenues principally from the distribution of LPG to retail customers in France and in northern, central and eastern European countries. In addition, UGI International derives revenue from natural gas marketing businesses in France, Belgium and the United Kingdom and a natural gas and electricity marketing business in the Netherlands. Midstream & Marketing derives its revenues principally from the sale of natural gas, liquid fuels and electricity as well as revenues and fees from storage, pipeline transportation, natural gas gathering and natural gas production activities primarily in the Mid-Atlantic region of the U.S. Midstream & Marketing also derives revenues from the sale of electricity through PJM, a regional electricity transmission organization in the eastern U.S., and, to a lesser extent, also from contracting services provided by HVAC to customers in portions of eastern and central Pennsylvania. UGI Utilities derives its revenues principally from the sale and distribution of natural gas to customers in eastern and central Pennsylvania and, to a lesser extent, from the sale and distribution of electricity in two northeastern Pennsylvania counties. The accounting policies of our reportable segments are the same as those described in Note 2 . 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. Fiscal 2018 and Fiscal 2017 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 debt incurred by UGI Corporation 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. No single customer represents more than ten percent of our consolidated revenues. In addition, all of our reportable segments’ revenues, other than those of UGI International, are derived from sources within the United States, and all of our reportable segments’ long-lived assets, other than those of UGI International, are located in the United States. The amounts of revenues and long-lived assets associated with our operations in France represent approximately 20% and 10% of the respective consolidated amounts. Total Elim- inations AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Corporate & Other (a) 2019 Revenues from external customers $ 7,320.4 $ — $ 2,682.0 $ 2,372.2 $ 1,281.1 $ 980.7 $ 4.4 Intersegment revenues $ — $ (305.4 ) (b) $ — $ — $ 234.6 $ 67.9 $ 2.9 Cost of sales $ 4,323.1 $ (301.7 ) (b) $ 1,191.3 $ 1,416.4 $ 1,241.2 $ 481.3 $ 294.6 Operating income (loss) $ 617.1 $ 0.5 $ 404.0 $ 228.9 $ 105.0 $ 224.2 $ (345.5 ) Income from equity investees 9.1 — — — 9.1 (c) — — Loss on extinguishments of debt (6.1 ) — — — — — (6.1 ) Other non-operating income, net 38.2 — — 5.4 — 1.5 31.3 Earnings (losses) before interest expense and income taxes 658.3 0.5 404.0 234.3 114.1 225.7 (320.3 ) Interest expense (257.8 ) — (167.4 ) (25.0 ) (9.0 ) (49.6 ) (6.8 ) Income tax (expense) benefit (92.6 ) (0.2 ) (25.7 ) (64.6 ) (27.1 ) (42.9 ) 67.9 Noncontrolling interests’ net (income) loss (51.7 ) — (142.7 ) 0.1 — — 90.9 Net income (loss) attributable to UGI $ 256.2 $ 0.3 $ 68.2 $ 144.8 $ 78.0 $ 133.2 $ (168.3 ) Depreciation and amortization $ 448.1 $ (0.2 ) $ 179.4 $ 123.8 $ 51.4 $ 92.8 $ 0.9 Total assets $ 13,346.6 $ (352.8 ) $ 4,095.3 $ 2,975.2 $ 2,744.5 $ 3,559.5 $ 324.9 Short-term borrowings $ 796.3 $ — $ 328.0 $ 210.9 $ 91.4 $ 166.0 $ — Capital expenditures (including the effects of accruals) $ 707.6 $ — $ 107.3 $ 106.4 $ 137.7 $ 355.3 $ 0.9 Investments in equity investees $ 189.6 $ — $ — $ 11.6 $ 178.0 $ — $ — Goodwill $ 3,456.4 $ — $ 2,003.0 $ 929.8 $ 341.5 $ 182.1 $ — 2018 (d)(e) Revenues from external customers $ 7,651.2 $ — $ 2,823.0 $ 2,683.8 $ 1,149.1 $ 998.5 $ (3.2 ) Intersegment revenues $ — $ (370.8 ) (b) $ — $ — $ 272.6 $ 93.9 $ 4.3 Cost of sales $ 4,074.9 $ (366.6 ) (b) $ 1,314.7 $ 1,620.1 $ 1,090.8 $ 522.9 $ (107.0 ) Operating income (loss) $ 1,064.7 $ 0.3 $ 422.2 $ 247.9 $ 175.1 $ 239.9 $ (20.7 ) (d) Income (loss) from equity investees 4.3 — — (0.5 ) 4.8 (c) — — Other non-operating income (expense), net 15.6 — — (7.0 ) (1.2 ) (2.4 ) 26.2 Earnings before interest expense and income taxes 1,084.6 0.3 422.2 240.4 178.7 237.5 5.5 Total Elim- inations AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Corporate & Other (a) Interest expense (230.1 ) — (163.1 ) (21.1 ) (2.4 ) (42.9 ) (0.6 ) Income tax (expense) benefit (32.1 ) (1.4 ) (30.5 ) (69.2 ) (49.6 ) (53.7 ) 172.3 Noncontrolling interests’ net (income) loss (103.7 ) — (152.3 ) 3.0 — — 45.6 Net income (loss) attributable to UGI $ 718.7 $ (1.1 ) $ 76.3 $ 153.1 $ 126.7 $ 140.9 $ 222.8 Depreciation and amortization $ 455.1 $ (0.3 ) $ 185.8 $ 140.6 $ 43.5 $ 84.6 $ 0.9 Total assets $ 11,980.9 $ (125.3 ) $ 3,933.9 $ 3,279.0 $ 1,328.9 $ 3,266.6 $ 297.8 Short-term borrowings $ 424.9 $ — $ 232.0 $ 1.4 $ 2.0 $ 189.5 $ — Capital expenditures (including the effects of accruals) $ 597.0 $ — $ 101.3 $ 111.4 $ 43.1 $ 338.5 $ 2.7 Investments in equity investees $ 87.6 $ — $ — $ 12.8 $ 74.8 $ — $ — Goodwill $ 3,160.4 $ — $ 2,003.0 $ 963.7 $ 11.6 $ 182.1 $ — 2017 (e) Revenues from external customers $ 6,120.7 $ — $ 2,453.5 $ 1,877.5 $ 943.0 $ 847.5 $ (0.8 ) Intersegment revenues $ — $ (222.7 ) (b) $ — $ — $ 178.2 $ 40.1 $ 4.4 Cost of sales $ 2,837.3 $ (218.3 ) (b) $ 1,002.9 $ 935.3 $ 856.7 $ 367.3 $ (106.6 ) Operating income $ 1,010.0 $ 0.3 $ 355.3 $ 234.3 $ 139.4 $ 232.7 $ 48.0 Income from equity investees 4.3 — — — 4.3 (c) — — Loss on extinguishments of debt (59.7 ) — — — — — (59.7 ) Other non-operating (expense) income, net (29.7 ) — — 1.2 (0.2 ) (4.4 ) (26.3 ) Earnings (losses) before interest expense and income taxes 924.9 0.3 355.3 235.5 143.5 228.3 (38.0 ) Interest expense (223.5 ) — (160.2 ) (20.6 ) (2.1 ) (40.2 ) (0.4 ) Income tax (expense) benefit (177.6 ) (0.2 ) (32.5 ) (58.9 ) (54.5 ) (72.1 ) 40.6 Noncontrolling interests’ net (income) loss (87.2 ) — (108.4 ) (0.2 ) — — 21.4 Net income attributable to UGI $ 436.6 $ 0.1 $ 54.2 $ 155.8 $ 86.9 $ 116.0 $ 23.6 Depreciation and amortization $ 416.3 $ (0.2 ) $ 190.5 $ 117.4 $ 35.4 $ 72.3 $ 0.9 Total assets $ 11,582.2 $ (51.5 ) $ 4,069.4 $ 3,132.0 $ 1,165.5 $ 2,994.0 $ 272.8 Short-term borrowings $ 366.9 $ — $ 140.0 $ 17.9 $ 39.0 $ 170.0 $ — Capital expenditures (including the effects of accruals) $ 624.3 $ — $ 98.1 $ 90.3 $ 117.5 $ 317.7 $ 0.7 Investments in equity investees $ 59.1 $ — $ — $ 8.1 $ 51.0 $ — $ — Goodwill $ 3,107.2 $ — $ 2,001.3 $ 912.2 $ 11.6 $ 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 Fiscal 2019 , Fiscal 2018 and Fiscal 2017 : Location on Income Statement AmeriGas Propane UGI International Midstream & Marketing 2019 Net losses on commodity derivative instruments not associated with current-period transactions Revenue / Cost of sales $ (116.8 ) $ (142.5 ) $ (31.0 ) Unrealized gains on foreign currency derivative instruments Other non-operating income (expense), net $ — $ 32.2 $ — Loss on extinguishments of debt Loss on extinguishment of debt $ — $ (6.1 ) $ — AmeriGas Merger expenses Operating and administrative expenses $ (6.3 ) $ — $ — Acquisition and integration expenses associated with the CMG Acquisition Operating and administrative expenses $ — $ — $ (15.6 ) LPG business transformation costs Operating and administrative expenses $ (14.5 ) $ (9.3 ) $ — 2018 Net gains (losses) on commodity derivative instruments not associated with current-period transactions Revenue / Cost of sales $ 12.5 $ 92.9 $ (1.5 ) Unrealized gains on foreign currency derivative instruments Other non-operating income (expense), net $ — $ 28.9 $ — Integration expenses associated with Finagaz Operating and administrative expenses $ — $ (30.5 ) $ — Impairment of Partnership tradenames and trademarks Impairment of Partnership tradenames and trademarks $ (75.0 ) $ — $ — 2017 Net gains on commodity derivative instruments not associated with current-period transactions Revenue / Cost of sales $ 31.1 $ 19.0 $ 55.7 Unrealized losses on foreign currency derivative instruments Other non-operating income (expense), net $ — $ (23.8 ) $ — Loss on extinguishments of debt Loss on extinguishment of debt $ (59.7 ) $ — $ — Integration expenses associated with Finagaz Operating and administrative expenses $ — $ (39.9 ) $ — (b) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (c) Includes AFUDC associated with PennEast (see Note 2 ). Fiscal 2019 also includes income from Pennant subsequent to the CMG Acquisition (see Note 5 ). (d) Fiscal 2018 results include impacts from the TCJA in the U.S. See Notes 7 and 9 for additional information. For Fiscal 2018, the remeasurement impacts from the TCJA and, for UGI International, the December 2017 French Finance Bills, were allocated from each of AmeriGas Propane, UGI International, Midstream & Marketing and UGI Utilities to Corporate & Other in amounts of $112.9 , $4.0 , $70.1 and $8.0 , respectively. For Fiscal 2017, the remeasurement impact from the December 2016 French Finance Bills of $29.0 was allocated from UGI International to Corporate & Other. (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	12 Months Ended
	Sep. 30, 2019
Restructuring and Related Activities [Abstract]
Global LPG Business Transformation Initiatives	Note 23 — 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 Fiscal 2019 we incurred $23.8 of costs principally comprising consulting, advisory and employee-related costs. These costs are reflected in “ Operating and administrative expenses ” on the 2019 Consolidated Statement of Income.

SCHEDULE I _ CONDENSED FINANCIA

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)	12 Months Ended
	Sep. 30, 2019
Condensed Financial Information Disclosure [Abstract]
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY)	BALANCE SHEETS (Millions of dollars) September 30, 2019 2018 ASSETS Current assets: Cash and cash equivalents $ 53.7 $ 13.4 Accounts receivable – related parties 5.4 12.8 Prepaid expenses and other current assets 22.8 10.5 Total current assets 81.9 36.7 Property, plant and equipment, net 3.0 2.6 Investments in subsidiaries 4,585.1 3,652.0 Other assets 77.4 71.9 Total assets $ 4,747.4 $ 3,763.2 LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY Current liabilities: Accounts and notes payable $ 15.4 $ 14.9 Accrued liabilities 9.1 6.7 Total current liabilities 24.5 21.6 Long-term debt 846.0 — Other noncurrent liabilities 59.4 60.2 Total liabilities 929.9 81.8 Commitments and contingencies (Note 1) Common stockholders’ equity: Common Stock, without par value (authorized – 450,000,000 shares; issued – 209,304,129 and 174,142,997 shares, respectively) 1,396.9 1,200.8 Retained earnings 2,653.1 2,610.7 Accumulated other comprehensive loss (216.6 ) (110.4 ) Treasury stock, at cost (15.9 ) (19.7 ) Total common stockholders’ equity 3,817.5 3,681.4 Total liabilities and common stockholders’ equity $ 4,747.4 $ 3,763.2 Note 1 — Commitments and Contingencies: At September 30, 2019 , UGI Corporation had agreed to indemnify the issuers of $84.4 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to $475.0 of obligations to suppliers and customers of Energy Services and subsidiaries of which $378.4 of such obligations were outstanding as of September 30, 2019 . Scheduled principal repayments of long-term debt during the next five fiscal years include $300.0 in Fiscal 2022, $37.5 in Fiscal 2023 and $512.5 in Fiscal 2024. STATEMENTS OF INCOME (Millions of dollars, except per share amounts) Year Ended September 30, 2019 2018 2017 Revenues $ — $ — $ — Costs and expenses: Operating and administrative expenses 50.0 63.4 44.5 Other operating income, net (a) (49.7 ) (52.2 ) (45.9 ) 0.3 11.2 (1.4 ) Operating (loss) income (0.3 ) (11.2 ) 1.4 Pension and other postretirement plans non-service expense (0.9 ) (1.3 ) (1.8 ) Interest expense (6.4 ) — — Intercompany interest income 0.3 0.1 — Loss before income taxes (7.3 ) (12.4 ) (0.4 ) Income tax (benefit) expense (2.8 ) 6.1 (5.7 ) (Loss) income before equity in income of unconsolidated subsidiaries (4.5 ) (18.5 ) 5.3 Equity in income of unconsolidated subsidiaries 260.7 737.2 431.3 Net income attributable to UGI Corporation $ 256.2 $ 718.7 $ 436.6 Other comprehensive (loss) income (3.3 ) 3.4 1.3 Equity in other comprehensive (loss) income of unconsolidated subsidiaries (96.3 ) (20.4 ) 60.0 Comprehensive income attributable to UGI Corporation $ 156.6 $ 701.7 $ 497.9 Earnings per common share attributable to UGI Corporation stockholders: Basic $ 1.44 $ 4.13 $ 2.51 Diluted $ 1.41 $ 4.06 $ 2.46 Weighted - average common shares outstanding (thousands): Basic 178,417 173,908 173,662 Diluted 181,111 176,905 177,159 (a) UGI provides certain financial and administrative services to certain of its subsidiaries. UGI bills these subsidiaries monthly for all direct expenses incurred by UGI on behalf of its subsidiaries as well as allocated shares of indirect corporate expense incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to certain of its subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed and considers the relative percentage of such items for each subsidiary to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to its subsidiaries. These billed expenses are classified as “Other operating income, net” in the Statements of Income above. STATEMENTS OF CASH FLOWS (Millions of dollars) Year Ended September 30, 2019 2018 2017 NET CASH PROVIDED BY OPERATING ACTIVITIES (a) $ 169.8 $ 208.2 $ 253.2 CASH FLOWS FROM INVESTING ACTIVITIES: Expenditures for property, plant and equipment — (2.3 ) (0.4 ) Net investments in unconsolidated subsidiaries (768.1 ) (6.5 ) (40.7 ) Net cash used by investing activities (768.1 ) (8.8 ) (41.1 ) CASH FLOWS FROM FINANCING ACTIVITIES: Payment of dividends on Common Stock (199.5 ) (176.9 ) (168.9 ) Issuances of debt, net of issuance costs 845.9 — — Issuances of Common Stock 16.8 34.9 11.0 Repurchases of UGI Common Stock (16.9 ) (59.8 ) (43.3 ) Other (7.7 ) — 0.1 Net cash provided (used) by financing activities 638.6 (201.8 ) (201.1 ) Cash and cash equivalents increase (decrease) $ 40.3 $ (2.4 ) $ 11.0 Cash and cash equivalents: End of year $ 53.7 $ 13.4 $ 15.8 Beginning of year 13.4 15.8 4.8 Cash and cash equivalents increase (decrease) $ 40.3 $ (2.4 ) $ 11.0 (a) Includes dividends received from unconsolidated subsidiaries of $162.5 , $190.5 and $241.9 for the years ended September 30, 2019 , 2018 and 2017 , respectively.

SCHEDULE II _ VALUATION AND QUA

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS	12 Months Ended
	Sep. 30, 2019
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS	UGI CORPORATION AND SUBSIDIARIES SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS (Millions of dollars) Balance at beginning of year Charged (credited) to costs and expenses Other Balance at end of year Year Ended September 30, 2019 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 35.1 $ 28.6 $ (32.1 ) (1) $ 31.6 Other reserves: Deferred tax assets valuation allowance $ 116.8 $ (26.1 ) $ — $ 90.7 Year Ended September 30, 2018 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 26.9 $ 35.6 $ (27.4 ) (1) $ 35.1 Other reserves: Deferred tax assets valuation allowance $ 107.1 $ 9.7 $ — $ 116.8 Year Ended September 30, 2017 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 27.3 $ 30.7 $ (31.1 ) (1) $ 26.9 Other reserves: Deferred tax assets valuation allowance $ 114.3 $ (7.6 ) $ 0.4 (2) $ 107.1 (1) Uncollectible accounts written off, net of recoveries. (2) Foreign tax credit valuation allowance adjustment.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Sep. 30, 2019
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Our consolidated financial statements are prepared in accordance with GAAP. 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.
Reclassification	Certain prior-year amounts have been reclassified to conform to the current-year presentation.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which are majority owned. We report outside ownership interests in other consolidated but less than 100% -owned subsidiaries, as noncontrolling interests. Prior to the AmeriGas Merger, we also reported the public’s interest in the Partnership as a noncontrolling interest. We eliminate intercompany accounts and transactions when we consolidate.
Effects of Regulation	Effects of Regulation
Fair Value Measurements	Fair Value Measurements The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements performed on a recurring basis principally relate to derivative instruments and investments held in supplemental executive retirement plan grantor trusts. GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels: • Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. • Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. • Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments.
Derivative Instruments	Derivative Instruments Derivative instruments are reported on the 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 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 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.
Foreign Currency Translation	Foreign Currency Translation Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income. Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise with the impact of subsequent changes in such rates reflected in the income statement. The functional currency of a significant portion of our international operations is the euro.
Revenue Recognition	Revenue Recognition Effective October 1, 2018, the Company adopted ASU No. 2014-09, “Revenue from Contracts with Customers,” which, as amended, is included in ASC 606. This new accounting guidance supersedes previous revenue recognition requirements in ASC 605. ASC 606 requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We adopted this new accounting guidance using the modified retrospective transition method to those contracts which were not completed as of October 1, 2018. Periods prior to October 1, 2018, have not been restated and continue to be reported in accordance with ASC 605. The Company recorded a $7.1 reduction to opening retained earnings as of October 1, 2018, to reflect the cumulative effect of ASC 606 on certain contracts not complete as of the date of adoption. The adoption of ASC 606 did not, and is not expected to, have a material impact on the amount or timing of our revenue recognition and on our consolidated net income, cash flows or financial position. Certain revenues such as revenue from leases, financial instruments and other revenues are not within the scope of ASC 606 because they are not from contracts with customers. Such revenues are accounted for in accordance with other GAAP. Revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, are not included in revenues. Gross receipts taxes at Midstream & Marketing and Electric Utility are presented on a gross basis. The Company has elected to use the practical expedient to expense the costs to obtain contracts when incurred for contracts that have a term less than one year
Accounts Receivable	Accounts Receivable Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.
LPG Delivery Expenses	LPG Delivery Expenses Expenses associated with the delivery of LPG to customers of the Partnership and our UGI International operations (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as “ Operating and administrative expenses ” on the Consolidated Statements of Income. Depreciation expense associated with the Partnership and UGI International delivery vehicles is classified in “ Depreciation and amortization ” on the Consolidated Statements of Income.
Income Taxes	Income Taxes AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss and (2) the differences between the book and tax basis of our investment in the Partnership. AmeriGas OLP has subsidiaries which operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation. For additional information regarding the tax effects of the AmeriGas Merger, see Note 7 . UGI Utilities records deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax depreciation methods based upon amounts recognized for ratemaking purposes. UGI Utilities also records a deferred income tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and records a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse. We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. At September 30, 2019 and 2018 , such deferred investment tax credits totaled $2.3 and $ 2.6 , respectively. We record interest on underpayments and overpayments of income taxes, and income tax penalties, in “ Income tax expense ” on the Consolidated Statements of Income. For Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , interest income or expense recognized in “ Income tax expense ” on the Consolidated Statements of Income was not material. The TCJA was enacted on December 22, 2017, and included a broad range of tax reform provisions affecting the Company, including, among other things, changes in the U.S. corporate income tax rate. The TCJA reduced the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. We were subject to a 24.5% blended U.S. federal income tax rate for Fiscal 2018 because our fiscal year contained the effective date of the rate change from 35% to 21%
Other Non-Operating Income (Expense), Net	Other Non-Operating Income (Expense), Net Included in “ Other non-operating income (expense), net ,” on the Consolidated Statements of Income are net gains (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.
Earnings Per Common Share	Earnings Per Common Share
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash Cash and cash equivalents include cash on hand, cash in banks and highly liquid investments with maturities of three months or less when purchased. Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.
Inventories	Inventories Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for non-utility LPG and natural gas and Gas Utility natural gas; specific identification for appliances; and the FIFO method for all other inventories.
Property, Plant and Equipment and Related Depreciation	We classify amortization of computer software and related IT system installation costs included in property, plant and equipment as depreciation expense. For property subject to cost of service rate regulation including substantially all of UGI Utilities depreciable utility plant and equipment, upon retirement we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets and amortized over five years , consistent with prior ratemaking treatment. Property, Plant and Equipment and Related Depreciation We record property, plant and equipment at the lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs, and for certain operations subject to cost-of-service rate regulation, AFUDC. We also include in property, plant and equipment costs associated with computer software we develop or obtain for use in our business. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition. When we retire or otherwise dispose of non-utility plant and equipment, we eliminate the associated cost and accumulated depreciation and recognize any resulting gain or loss in " Other operating income, net " on the Consolidated Statements of Income.
Goodwill and Intangible Assets	Goodwill and Intangible Assets Intangible Assets. We amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. No amortization expense of intangible assets is included in cost of sales on the Consolidated Statements of Income (see Note 12 ). Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships (other than customer relationships acquired in the CMG Acquisition), certain tradenames and noncompete agreements, generally do not exceed 15 years . The estimated useful lives of customer relationships acquired in the CMG Acquisition is 35 years (see Note 5 ). We review definite-lived intangible assets for impairment whenever events or changes in circumstances indicate that the associated carrying amounts may not be recoverable. Determining whether an impairment loss occurred requires comparing the carrying amount to the sum of undiscounted cash flows expected to be generated by the asset. Intangible assets with indefinite lives are not amortized but are tested for impairment annually (and more frequently if events or changes in circumstances between annual tests indicate that it is more likely than not that they are impaired) and written down to fair value, if impaired. During Fiscal 2018, the Partnership recorded a non-cash, pre-tax impairment charge of $75.0 which amount is reflected in “ Impairment of Partnership tradenames and trademarks ” on the Consolidated Statements of Income, and is amortizing the remaining fair value of these tradenames and trademarks of $7.9 over their estimated period of benefit of three years . For further information on these tradenames and trademarks, see Note 12 . Goodwill. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is an operating segment, or a business one level below an operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. Each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. For certain of our reporting units with goodwill, we assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. For our other reporting units with goodwill, we bypass the qualitative assessment and perform the quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, an impairment loss is recognized in an amount equal to such excess but not to exceed the total amount of the goodwill of the reporting unit.
Impairment of Long-Lived Assets	We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets.
Debt Issuance Costs	Debt Issuance Costs We defer and amortize debt issuance costs and debt premiums and discounts over the expected lives of the respective debt issues considering maturity dates. Deferred debt issuance costs associated with long-term debt are reflected as a direct deduction from the carrying amount of such debt. Deferred debt issuance costs associated with revolving credit facilities reflected as short-term borrowings are classified as “ Other assets ” on our Consolidated Balance Sheets. Amortization of debt issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt prior to their stated maturity are generally recognized and recorded in “Loss on extinguishments of debt” on the Consolidated Statements of Income. As permitted by regulatory authorities, gains or losses resulting from refinancings of UGI Utilities’ debt are deferred and amortized over the lives of the new issuances.
Refundable Tank and Cylinder Deposits	Refundable Tank and Cylinder Deposits Included in “ Other noncurrent liabilities ” on our Consolidated Balance Sheets are customer paid deposits on tanks and cylinders primarily owned by subsidiaries of UGI France of $279.7 and $272.0 at September 30, 2019 and 2018
Environmental Matters	Environmental Matters We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites.
Loss Contingencies Subject to Insurance	Loss Contingencies Subject to Insurance We are subject to risk of loss for general, automobile and product liability, and workers’ compensation claims for which we obtain insurance coverage under insurance policies that are subject to self-insured retentions or deductibles. In accordance with GAAP, we record accruals when it is probable that a liability exists and the amount or range of amounts can be reasonably estimated. When no amount within a range of possible loss is a better estimate than any other amount within the range, liabilities recorded are based upon the low end of the range. For litigation and pending claims including those covered by insurance policies, the analysis of probable loss is performed on a case by case basis and includes an evaluation of the nature of the claim, the procedural status of the matter, the probability or likelihood of success in prosecuting or defending the claim, the information available with respect to the claim, the opinions and views of outside counsel and other advisors, and past experience in similar matters. With respect to unasserted claims arising from unreported incidents, we may use the work of specialists to estimate the ultimate losses to be incurred using actuarially determined loss development factors applied to actual claims data. Our estimated reserves for loss contingencies may differ materially from the ultimate liability and such reserves may change materially as more information becomes available and estimated reserves are adjusted. We maintain insurance coverage such that our net exposure for claims covered by insurance would be limited to the self-insured retentions or deductibles, claims above which would be paid by the insurance carrier. For such claims, we record a receivable related to the amount of the liability expected to be paid by insurance.
Employee Retirement Plans	Employee Retirement Plans
Equity-Based Compensation	Equity-Based Compensation All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and, prior to the AmeriGas Merger, grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units” or “Unit Awards”), are measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as a liability or as equity on our Consolidated Balance Sheets. Equity-based compensation costs associated with the portion of Unit Awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Equity-based compensation costs associated with all or a portion of Unit Awards classified as liabilities are measured based upon their estimated fair value at the grant date and remeasured as of the end of each period. We record deferred tax assets for awards that we expect will result in deductions on our income tax returns based on the amount of compensation cost recognized and the statutory tax rate in the jurisdiction in which we will receive a deduction. Differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return are recorded on the Consolidated Statements of Income. Excess tax benefits and tax deficiencies associated with employee share-based awards that vest or are exercised are recognized as income tax benefit or expense in the reporting period in which they occur, and assumed proceeds under the treasury stock method used for computing diluted shares outstanding do not include windfall tax benefits in the diluted shares calculation. We account for forfeitures of share-based payments when they occur.
New Accounting Standards Adopted in Fiscal 2019 and Not Yet Adopted	New Accounting Standards Adopted in Fiscal 2019 Revenue Recognition. Effective October 1, 2018, the Company adopted new accounting guidance regarding revenue recognition. See Notes 2 and 4 for a detailed description of the impact of the new guidance and related disclosures. Cloud Computing Implementation Costs. In August 2018, the FASB issued ASU No. 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.” The new guidance requires a customer in a cloud computing arrangement that is a service contract to capitalize certain implementation costs as if the arrangement was an internal-use software project. These deferred implementation costs are expensed over the fixed, noncancelable term of the service arrangement plus any reasonably certain renewal periods. The new guidance also requires the entity to present the expense related to the capitalized implementation costs in the same income statement line as the hosting service fees; to classify payments for capitalized implementation costs in the statement of cash flows in the same manner as payments for hosting service fees; and to present the capitalized implementation costs in the balance sheet in the same line item in which prepaid hosting service fees are presented. We adopted this ASU effective October 1, 2018, and applied the guidance prospectively to all implementation costs associated with cloud computing arrangements that are service contracts incurred beginning October 1, 2018. As UGI Utilities receives rate recovery for cloud computing implementation costs, such costs will continue to be deferred as a regulatory asset and included as a component of property, plant, and equipment. The adoption of the new guidance did not have a material impact on our results of operations during Fiscal 2019. Stranded Tax Effects in Accumulated Other Comprehensive Income. In February 2018, the FASB issued ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU provides that the stranded tax effects in AOCI resulting from the remeasurement of deferred income taxes associated with items included in AOCI due to the enactment of the TCJA may be reclassified to retained earnings, at the election of the entity, in the period the ASU is adopted. We adopted this ASU effective October 1, 2018. In connection with the adoption of this guidance, we reclassified a benefit of $6.6 from AOCI to opening retained earnings as of October 1, 2018, to reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of AOCI. Pension and Other Postretirement Benefit Costs. In March 2017, the FASB issued ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” This ASU requires entities to disaggregate the service cost component from the other components of net periodic benefit cost and present it with compensation costs for related employees in the income statement. The other components are required to be presented elsewhere in the income statement and outside of income from operations. The amendments in this ASU permit only the service cost component to be eligible for capitalization, when applicable. For entities subject to rate regulation, including UGI Utilities, the ASU recognized that in the event a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in the recognition of a regulatory asset or liability. We adopted this ASU effective October 1, 2018, with retrospective adoption for the presentation of pension and postretirement expense on the income statement and a prospective adoption for capitalization, as required by the ASU. The adoption of the new standard did not have a material impact on our financial statements. Statement of Cash Flows - Restricted Cash. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” The guidance in this ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, as well as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents are included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statement of cash flows. We adopted this ASU effective October 1, 2018 with retrospective adoption as required by the ASU. Pension and Other Postretirement Benefit Costs Disclosures. In August 2018, the FASB issued ASU No. 2018-14, “Changes to the Disclosure Requirements for Defined Benefit Plans.” This ASU modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans by removing and adding certain disclosures for these plans. We adopted this ASU during the fourth quarter of Fiscal 2019 and applied the new guidance retrospectively for all periods presented in the financial statements. The adoption of the new guidance did not have a material impact on the Company’s financial statement disclosures. Fair Value Measurements Disclosures. In August 2018, the FASB issued ASU No. 2018-13, “Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU modifies the disclosure requirements for fair value measurements by removing, modifying, or adding certain disclosures. We adopted this ASU during the fourth quarter of Fiscal 2019. The guidance regarding removing and modifying disclosures was adopted on a retrospective basis and the guidance regarding new disclosures has been adopted on a prospective basis. The adoption of the new guidance did not have a material impact on the Company’s financial statement disclosures. New Accounting Standards Adopted Effective October 1, 2019 Derivatives and Hedging. In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU amends and simplifies existing guidance to allow companies to more accurately present the economic effects of risk management activities in the financial statements. The amendments in this ASU are effective for the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). For cash flow and net investment hedges as of the adoption date, the guidance requires a modified retrospective approach. The amended presentation and disclosure guidance is required prospectively. The Company adopted the new guidance effective October 1, 2019. We do not expect the adoption of this new guidance will have a material impact on our financial statements. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU, as subsequently updated, amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for the Company for interim and annual periods beginning October 1, 2019 (Fiscal 2020). Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements unless an entity chooses the transition option in ASU 2018-11, “Leases: Targeted Improvements” which, among other things, provides entities with a transition option to recognize the cumulative-effect adjustment from the modified retrospective application to the opening balance of retained earnings in the period of adoption. We adopted this ASU, as updated, effective October 1, 2019, using the transition method which allows the Company to maintain historical presentation for periods before October 1, 2019. The Company elected to apply the following practical expedients: • Short-term leases: We have excluded short-term leases (term of 12 months or less) from balance sheet presentation. • Easements: We did not re-evaluate existing land easements that were not previously accounted for as leases. • 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 this new guidance. We enhanced controls and processes and implemented a new lease system that will enable the accumulation and presentation of financial information as required by the new standard. We continue to finalize our implementation efforts and estimate that the adoption will result in the recognition of approximately $400 to $600 of offsetting operating lease right-of-use assets and operating lease liabilities associated with operating leases in effect at the date of adoption. We do not expect the adoption to have a material impact on the consolidated statements of income or cash flows. Accounting Standard Not Yet Adopted Credit Losses. In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments. ” This ASU 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 loss for 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 and determining the period in which the new guidance will be adopted.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Sep. 30, 2019
Accounting Policies [Abstract]
Schedule of Other Non-Operating Income (Expense)	Other non-operating income (expense), net comprises the following: 2019 2018 2017 Gains (losses) on foreign currency contracts, net $ 37.7 $ 16.2 $ (23.9 ) Pension and other postretirement plans non-service income (expense), net 0.5 (0.6 ) (5.8 ) Total other non-operating income (expense), net $ 38.2 $ 15.6 $ (29.7 )
Shares Used in Computing Basic and Diluted Earnings Per Share	In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2019 , Fiscal 2018 and Fiscal 2017 : (Thousands of shares) 2019 2018 2017 Weighted-average common shares outstanding for basic computation (a) 178,417 173,908 173,662 Incremental shares issuable for stock options and common stock awards (b) 2,694 2,997 3,497 Weighted-average common shares outstanding for diluted computation 181,111 176,905 177,159 (a) Fiscal 2019 includes the partial-year impact from the August 2019 issuance of 34,613 shares of UGI Common Stock in connection with the AmeriGas Merger (see Note 5 ). (b) For Fiscal 2019 and Fiscal 2017 , there were 1,162 shares and 146 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive.
Schedule of Reconciliation of the Total Cash, Cash Equivalents and Restricted Cash	The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Consolidated Balance Sheets to the corresponding amounts reported on the Consolidated Statements of Cash Flows. Cash, Cash Equivalents and Restricted Cash September 30, 2019 September 30, 2018 September 30, 2017 September 30, 2016 Cash and cash equivalents $ 447.1 $ 452.6 $ 558.4 $ 502.8 Restricted cash 63.7 9.6 10.3 15.6 Cash, cash equivalents and restricted cash $ 510.8 $ 462.2 $ 568.7 $ 518.4
Schedule of Reconciliation of the Total Cash, Cash Equivalents and Restricted Cash	The following table provides a reconciliation of the total cash, cash equivalents and restricted cash reported on the Consolidated Balance Sheets to the corresponding amounts reported on the Consolidated Statements of Cash Flows. Cash, Cash Equivalents and Restricted Cash September 30, 2019 September 30, 2018 September 30, 2017 September 30, 2016 Cash and cash equivalents $ 447.1 $ 452.6 $ 558.4 $ 502.8 Restricted cash 63.7 9.6 10.3 15.6 Cash, cash equivalents and restricted cash $ 510.8 $ 462.2 $ 568.7 $ 518.4
Estimated Useful Lives by Type	At September 30, 2019 , estimated useful lives by asset type were as follows: Asset Type Minimum Estimated Useful Life (in years) Maximum Estimated Useful Life (in years) Buildings and improvements 10 40 Equipment, primarily cylinders and tanks 5 30 Electricity generation facilities 25 40 Pipeline and related assets 25 40 Transportation equipment and office furniture and fixtures 3 10 Computer software 1 10 Property, plant and equipment comprise the following at September 30: 2019 2018 Utility: Distribution $ 3,366.2 $ 3,106.6 Transmission 106.0 97.1 General and other 389.3 281.7 Work in process 76.6 130.9 Total Utility 3,938.1 3,616.3 Non-utility: Land 183.5 191.4 Buildings and improvements 403.8 364.9 Transportation equipment 258.3 257.1 Equipment, primarily cylinders and tanks 3,455.2 3,375.4 Electric generation 326.9 319.5 Pipeline and related assets 1,150.2 473.0 Other 255.3 306.6 Work in process 101.7 57.9 Total non-utility 6,134.9 5,345.8 Total property, plant and equipment $ 10,073.0 $ 8,962.1
Average Composite Depreciation Rates	The average composite depreciation rates at our Gas Utility and Electric Utility for Fiscal 2019 , Fiscal 2018 and Fiscal 2017 were as follows: 2019 2018 2017 Gas Utility 2.2 % 2.3 % 2.2 % Electric Utility 2.1 % 2.2 % 2.4 %

Revenue from Contract with Cu_2

Revenue from Contract with Customers (Tables)	12 Months Ended
	Sep. 30, 2019
Revenue from Contract with Customer [Abstract]
Schedule of Disaggregation of Revenue By Reportable Segment	The following table presents our disaggregated revenues by reportable segment during Fiscal 2019 : 2019 Total Eliminations AmeriGas Propane UGI International Midstream & Marketing (a) UGI Utilities (a) Corporate & Other Revenues from contracts with customers: Utility: Core Market: Residential $ 552.7 $ — $ — $ — $ — $ 552.7 $ — Commercial & Industrial 226.3 — — — — 226.3 — Large delivery service 138.0 — — — — 138.0 — Off-system sales and capacity releases 46.4 (64.8 ) — — — 111.2 — Other (b) 14.9 (3.1 ) — — — 18.0 — Total Utility 978.3 (67.9 ) — — — 1,046.2 — Non-Utility: LPG: Retail 4,007.9 — 2,340.9 1,667.0 — — — Wholesale 233.3 — 63.9 169.4 — — — Energy Marketing 1,520.7 (134.2 ) — 448.3 1,206.6 — — Midstream: Pipeline 94.5 — — — 94.5 — — Peaking 17.6 (96.8 ) — — 114.4 — — Other 1.9 — — — 1.9 — — Electricity Generation 43.2 — — — 43.2 — — Other 313.3 (3.3 ) 213.2 54.9 48.5 — — Total Non-Utility 6,232.4 (234.3 ) 2,618.0 2,339.6 1,509.1 — — Total revenues from contracts with customers 7,210.7 (302.2 ) 2,618.0 2,339.6 1,509.1 1,046.2 — Other revenues (c) 109.7 (3.2 ) 64.0 32.6 6.6 2.4 7.3 Total revenues $ 7,320.4 $ (305.4 ) $ 2,682.0 $ 2,372.2 $ 1,515.7 $ 1,048.6 $ 7.3 (a) Includes intersegment revenues principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (b) UGI Utilities includes an unallocated negative surcharge revenue reduction of $ (5.5) during Fiscal 2019 as a result of a PAPUC Order issued May 17, 2018, related to the TCJA (see Note 9 ). (c) Primarily represents revenues from tank rentals at AmeriGas Propane and UGI International, revenues from certain gathering assets at Midstream & Marketing, and gains and losses on commodity derivative instruments not associated with current-period transactions reflected in Corporate & Other, none of which are within the scope of ASC 606 and are accounted for in accordance with other GAAP.

AmeriGas Merger and Acquisiti_2

AmeriGas Merger and Acquisitions (Tables)	12 Months Ended
	Sep. 30, 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 .
Total Cash Paid and Liabilities Incurred	Total cash paid and liabilities incurred in connection with these acquisitions were as follows: 2019 2018 2017 UGI International Midstream & Marketing AmeriGas Propane UGI International AmeriGas Propane UGI International Total cash paid $ 49.3 $ 15.0 $ 10.1 $ 121.9 $ 36.8 $ 99.7 Liabilities incurred (a) — — 2.7 — 10.8 20.6 Total purchase price $ 49.3 $ 15.0 $ 12.8 $ 121.9 $ 47.6 $ 120.3 (a) UGI International Fiscal 2017 amount includes note payable to seller. AmeriGas Propane amounts principally comprise amounts payable under noncompete agreements.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Sep. 30, 2019
Debt Disclosure [Abstract]
Schedule of Loss on Extinguishment of Debt	In connection with the early repayment of AmeriGas Partners’ 7.00% Senior Notes, during Fiscal 2017, the Partnership recognized pre-tax losses, which are reflected in “ Loss on extinguishments of debt ” on the Consolidated Statements of Income and comprise the following: 2017 Early redemption premiums $ 51.3 Write-off of unamortized debt issuance costs 8.4 Loss on extinguishments of debt $ 59.7
Schedule of Long-term Debt Instruments	Long-term debt comprises the following at September 30: 2019 2018 AmeriGas Propane: AmeriGas Partners Senior Notes: 5.50% due May 2025 $ 700.0 $ 700.0 5.875% due August 2026 675.0 675.0 5.625% due May 2024 675.0 675.0 5.75% due May 2027 525.0 525.0 Heritage Operating, L.P. Senior Secured Notes (a) 3.8 7.5 Other 9.5 14.6 Unamortized debt issuance costs (23.7 ) (27.5 ) Total AmeriGas Propane 2,564.6 2,569.6 UGI International: 3.25% Senior Notes due November 2025 381.5 — UGI International, LLC variable-rate term loan due October 2023 (b) 327.0 — UGI France Senior Facilities term loan (c) — 627.0 Flaga variable-rate term loan (d) — 53.2 Flaga U.S. dollar variable-rate term loan (e) — 49.9 Other 19.3 20.9 Unamortized debt issuance costs (8.3 ) (2.5 ) Total UGI International 719.5 748.5 Midstream & Marketing: Energy Services variable-rate term loan due through August 2026 (f) 698.3 — Other 0.3 0.4 Unamortized discount and debt issuance costs (12.0 ) — Total Energy Services 686.6 0.4 UGI Utilities: Senior Notes: 4.12%, due September 2046 200.0 200.0 4.98%, due March 2044 175.0 175.0 4.55%, due February 2049 150.0 — 4.12%, due October 2046 100.0 100.0 6.21%, due September 2036 100.0 100.0 2.95%, due June 2026 100.0 100.0 Medium-Term Notes: 6.13%, due October 2034 20.0 20.0 6.50%, due August 2033 20.0 20.0 Variable-rate term loan due through October 2022 (g) 114.1 120.3 Other 4.7 6.8 Unamortized debt issuance costs (4.6 ) (4.1 ) Total UGI Utilities 979.2 838.0 2019 2018 UGI Corporation: UGI Corporation revolving credit facility maturing August 2024 (h) 300.0 — UGI Corporation variable-rate term loan due August 2022 (i) 300.0 — UGI Corporation variable-rate term loan due through August 2024 (i) 250.0 — Unamortized debt issuance costs (4.0 ) — Total UGI Corporation 846.0 — Other 8.1 8.8 Total long-term debt 5,804.0 4,165.3 Less: current maturities (24.1 ) (18.8 ) Total long-term debt due after one year $ 5,779.9 $ 4,146.5 (a) At September 30, 2019 and 2018 , the effective interest rate on the Heritage Operating, L.P. Senior Secured Notes was 6.75% . These notes are collateralized by AmeriGas OLP’s receivables, contracts, equipment, inventory, general intangibles and cash. (b) At September 30, 2019 , the effective interest rate on the term loan was approximately 2.04% . (c) At September 30, 2018, the effective interest rate on the term loan was approximately 1.93% . (d) The effective interest rate on this term loan at September 30, 2018, was 1.93% . (e) At September 30, 2018, the effective interest rate on this term loan was 0.55% . (f) The effective interest rate on this term loan at September 30, 2019 , was 5.79% . This term loan is collateralized by substantially all of the assets of Energy Services, subject to certain exceptions and carveouts including, but not limited to, accounts receivable and certain real property. (g) At September 30, 2019 and September 30, 2018 , the effective interest rate on this term loan was 3.05% and 2.76% , respectively. (h) The effective interest rate on credit facility borrowings at September 30, 2019 , was 4.55% . (i) At September 30, 2019 , the effective interest rates on the $300 variable-rate term loan and the $250 variable-rate term loan were 4.30% and 4.55% , respectively.
Schedule of Maturities of Long-term Debt	Scheduled principal repayments of long-term debt for each of the next five fiscal years ending September 30 are as follows: 2020 2021 2022 2023 2024 AmeriGas Propane $ 7.8 $ 3.6 $ 1.6 $ 0.3 $ 675.0 UGI International 0.1 0.1 19.0 0.1 327.0 Midstream & Marketing 7.1 7.1 7.1 7.0 7.0 UGI Utilities 8.4 8.0 6.9 95.5 — UGI Corporation — — 300.0 37.5 512.5 Other 0.6 0.9 0.9 5.7 — Total $ 24.0 $ 19.7 $ 335.5 $ 146.1 $ 1,521.5
Schedule of Short-term Debt	Information about the Company’s principal credit agreements (excluding the Energy Services Receivables Facility, which is discussed below) as of September 30, 2019 and 2018 , is presented in the following table. Borrowings outstanding under these agreements (other than the UGI Corporation Credit Agreement) are classified as “Short-term borrowings” on the Consolidated Balance Sheets. Expiration Date Total Capacity Borrowings Outstanding Letters of Credit and Guarantees Outstanding Available Borrowing Capacity Weighted Average Interest Rate - End of Year September 30, 2019 AmeriGas OLP December 2022 $ 600.0 $ 328.0 $ 62.7 $ 209.3 4.50 % UGI International, LLC (a) October 2023 € 300.0 € 192.7 € — € 107.3 3.64 % Energy Services (b) March 2021 $ 200.0 $ 45.0 $ — $ 155.0 6.25 % UGI Utilities June 2024 $ 350.0 $ 166.0 $ — $ 184.0 3.00 % UGI Corporation (c) August 2024 $ 300.0 $ 300.0 $ — $ — 4.55 % September 30, 2018 AmeriGas OLP December 2022 $ 600.0 $ 232.0 $ 63.5 $ 304.5 4.58 % UGI International, LLC April 2020 € 300.0 € — € — € 300.0 N.A. UGI France April 2020 € 60.0 € — € — € 60.0 N.A. Flaga October 2020 € 55.0 € — € 0.5 € 54.5 N.A. Energy Services March 2021 $ 240.0 $ — $ — $ 240.0 N.A. UGI Utilities March 2020 $ 450.0 $ 189.5 $ 2.0 $ 258.5 3.03 % N.A. - Not applicable (a) The 2018 UGI International Credit Facilities Agreement permits UGI International, LLC to borrow in euros or dollars. At September 30, 2019 , the amount borrowed was USD-denominated borrowings of $210.0 , equal to €192.7 . (b) The Energy Services Credit Agreement includes a $50 sublimit for letters of credit and can be used for general corporate purposes of Energy Services and its subsidiaries. Borrowings bear interest at either (i) the Alternate Base Rate plus a margin or (ii) Adjusted LIBOR plus a margin. The Alternate Base Rate, as defined, is the highest of (a) the prime rate, (b) the federal funds rate plus 0.50% , and (c) Adjusted LIBOR plus 1.00% . The margin on such borrowings ranges from 0.75% to 2.25% . The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services. This credit agreement is collateralized by substantially all of the assets of Energy Services, subject to certain exceptions and carveouts including, but not limited to, accounts receivables and certain real property. On August 13, 2019, the Energy Services Credit Agreement was amended to decrease its borrowing capacity from $240 to $200 . (c) Borrowings outstanding are classified as “Long-term debt” on the 2019 Consolidated Balance Sheet. See “Significant Financing Activities - UGI Corporation” above for further information.
Schedule of Receivables Facility	Information regarding the amounts of trade receivables transferred to ESFC and the amounts sold to the bank during Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , as well as the balance of ESFC trade receivables at September 30, 2019 , 2018 and 2017 follows: 2019 2018 2017 Trade receivables transferred to ESFC during the year $ 1,372.7 $ 1,279.5 $ 1,017.3 ESFC trade receivables sold to the bank during the year $ 179.0 $ 193.0 $ 243.0 ESFC trade receivables - end of year (a) $ 54.5 $ 65.0 $ 44.8 (a) At September 30, 2019 and 2018 , the amounts of ESFC trade receivables sold to the bank were $46.4 and $2.0 , respectively, and are reflected as “ Short-term borrowings ” on the Consolidated Balance Sheets.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Income Before Income Taxes	Income before income taxes comprises the following: 2019 2018 2017 Domestic $ 329.4 $ 576.0 $ 527.3 Foreign 71.1 278.5 174.1 Total income before income taxes $ 400.5 $ 854.5 $ 701.4
Provisions for Income Taxes	The provisions for income taxes consist of the following: 2019 2018 2017 Current expense (benefit): Federal $ 51.7 $ (2.7 ) $ (2.7 ) State 14.0 26.0 14.0 Foreign 69.6 77.6 56.2 Total current expense 135.3 100.9 67.5 Deferred expense (benefit): Federal 2.9 (77.1 ) 125.8 State 3.5 6.7 16.4 Foreign (48.8 ) 1.9 (31.8 ) Investment tax credit amortization (0.3 ) (0.3 ) (0.3 ) Total deferred expense (42.7 ) (68.8 ) 110.1 Total income tax expense $ 92.6 $ 32.1 $ 177.6
Reconciliation of U.S. Federal Statutory Tax Rate to Effective Tax Rate	A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows: 2019 2018 2017 U.S. federal statutory tax rate 21.0 % 24.5 % 35.0 % Difference in tax rate due to: Effect of tax rate changes - TJCA 0.2 (20.9 ) — Effect of tax rate changes - International (0.5 ) (2.1 ) (4.1 ) Noncontrolling interests not subject to tax (2.7 ) (3.0 ) (4.3 ) State income taxes, net of federal benefit 3.6 2.9 2.9 Valuation allowance adjustments — 1.1 (1.1 ) Effects of foreign operations 1.8 3.1 (1.1 ) Excess tax benefits on share-based payments (1.0 ) (1.1 ) (1.3 ) Other, net 0.7 (0.7 ) (0.7 ) Effective tax rate 23.1 % 3.8 % 25.3 %
Deferred Tax Liabilities (Assets)	Deferred tax liabilities (assets) comprise the following at September 30: 2019 2018 Excess book basis over tax basis of property, plant and equipment $ 804.5 $ 807.8 Investment in AmeriGas Partners — 219.2 Utility regulatory assets 107.6 86.7 Intangible assets and goodwill 70.5 67.6 Derivative instruments — 30.4 Other 8.3 10.6 Gross deferred tax liabilities 990.9 1,222.3 Investment in AmeriGas Partners (303.5 ) — Pension plan liabilities (49.9 ) (20.0 ) Employee-related benefits (43.8 ) (43.6 ) Operating loss carryforwards (21.2 ) (26.2 ) Foreign tax credit carryforwards (81.4 ) (106.1 ) Utility regulatory liabilities (94.3 ) (118.6 ) Derivative instruments (15.3 ) — Utility environmental liabilities (15.3 ) (14.7 ) Other (33.4 ) (29.0 ) Gross deferred tax assets (658.1 ) (358.2 ) Deferred tax assets valuation allowance 90.7 116.8 Net deferred tax liabilities $ 423.5 $ 980.9
Reconciliation of Unrecognized Tax Benefits	A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: 2019 2018 2017 Unrecognized tax benefits — beginning of year $ 11.5 $ 12.2 $ 7.2 Additions for tax positions of the current year 0.9 1.5 1.9 Additions for tax positions taken in prior years 0.4 0.6 4.6 Settlements with tax authorities/statute lapses (1.9 ) (2.8 ) (1.5 ) Unrecognized tax benefits — end of year $ 10.9 $ 11.5 $ 12.2

Employee Retirement Plans (Tabl

Employee Retirement Plans (Tables)	12 Months Ended
	Sep. 30, 2019
Retirement Benefits [Abstract]
Change in Pension Benefits and Other Postretirement Benefits Obligations	The following table provides a reconciliation of the PBOs of the U.S. Pension Plan and the UGI International pension plans, the ABOs of our other postretirement benefit plans, plan assets, and the funded status of pension and other postretirement plans as of September 30, 2019 and 2018 . ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation. Pension Benefits Other Postretirement Benefits 2019 2018 2019 2018 Change in benefit obligations: Benefit obligations — beginning of year $ 669.2 $ 697.8 $ 19.3 $ 27.0 Service cost 9.8 11.2 0.2 0.5 Interest cost 27.3 26.3 0.7 0.8 Actuarial loss (gain) 89.0 (37.0 ) 3.6 (2.1 ) Plan amendments 0.3 — — (5.8 ) Curtailment (1.3 ) (0.6 ) — (0.1 ) Settlements (13.1 ) — — — Foreign currency (3.1 ) (1.0 ) (0.2 ) — Benefits paid (28.0 ) (27.5 ) (0.9 ) (1.0 ) Benefit obligations — end of year $ 750.1 $ 669.2 $ 22.7 $ 19.3 Change in plan assets: Fair value of plan assets — beginning of year $ 563.3 $ 529.2 $ 15.3 $ 14.8 Actual gain on plan assets 13.0 44.9 0.9 0.9 Foreign currency (1.5 ) (0.6 ) — — Employer contributions 12.4 16.2 0.4 0.4 Settlements (13.1 ) — — — Benefits paid (27.3 ) (26.4 ) (0.4 ) (0.8 ) Fair value of plan assets — end of year $ 546.8 $ 563.3 $ 16.2 $ 15.3 Funded status of the plans — end of year $ (203.3 ) $ (105.9 ) $ (6.5 ) $ (4.0 ) Assets (liabilities) recorded in the balance sheet: Assets in excess of liabilities — included in other noncurrent assets $ — $ — $ 2.8 $ 6.7 Unfunded liabilities — included in other noncurrent liabilities (203.3 ) (105.9 ) (9.3 ) (10.7 ) Net amount recognized $ (203.3 ) $ (105.9 ) $ (6.5 ) $ (4.0 ) Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): Prior service cost (benefit) $ 1.3 $ 0.6 $ (1.2 ) $ (1.3 ) Net actuarial loss (gain) 25.4 14.0 0.5 (0.4 ) Total $ 26.7 $ 14.6 $ (0.7 ) $ (1.7 ) Amounts recorded in regulatory assets and liabilities (pre-tax): Prior service cost (benefit) $ 0.5 $ 0.7 $ (0.7 ) $ (1.2 ) Pension Benefits Other Postretirement Benefits 2019 2018 2019 2018 Net actuarial loss (gain) 177.4 85.7 1.4 (0.1 ) Total $ 177.9 $ 86.4 $ 0.7 $ (1.3 )
Actuarial Assumptions for Domestic Plans	The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below). Pension Plan Other Postretirement Benefits 2019 2018 2017 2019 2018 2017 Weighted-average assumptions: Discount rate – benefit obligations 3.30 % 4.40 % 4.00 % 3.30 % 4.40 % 4.00 % Discount rate – benefit cost 4.40 % 4.00 % 3.80 % 4.40 % 4.00 % 3.80 % Expected return on plan assets 7.30 % 7.40 % 7.50 % 5.00 % 5.00 % 5.00 % Rate of increase in salary levels 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 %
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 2019 2018 2017 2019 2018 2017 Service cost $ 9.8 $ 11.2 $ 11.9 $ 0.2 $ 0.5 $ 1.0 Interest cost 27.3 26.3 25.0 0.7 0.8 0.8 Expected return on assets (36.3 ) (35.0 ) (33.6 ) (0.8 ) (0.7 ) (0.7 ) Curtailment gain (0.4 ) (0.2 ) (1.4 ) — — — Amortization of: Prior service cost (benefit) 0.3 0.3 0.3 (0.5 ) (6.3 ) (0.6 ) Actuarial loss (gain) 7.8 13.4 16.7 (0.1 ) (0.1 ) 0.3 Net benefit cost (benefit) 8.5 16.0 18.9 (0.5 ) (5.8 ) 0.8 Change in associated regulatory liabilities — — — (1.4 ) (0.5 ) (0.5 ) Net benefit cost (benefit) after change in regulatory liabilities $ 8.5 $ 16.0 $ 18.9 $ (1.9 ) $ (6.3 ) $ 0.3
Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits	Expected payments for pension and other postretirement welfare benefits are as follows: Pension Benefits Other Postretirement Benefits Fiscal 2020 $ 32.7 $ 1.0 Fiscal 2021 $ 31.7 $ 1.0 Fiscal 2022 $ 33.0 $ 1.0 Fiscal 2023 $ 35.6 $ 0.9 Fiscal 2024 $ 37.2 $ 0.9 Fiscal 2025 - 2029 $ 204.3 $ 4.9
Pension Plans	The targets, target ranges and actual allocations for the U.S. Pension Plan and VEBA trust assets at September 30 are as follows: U.S. Pension Plan Actual Target Asset Allocation Permitted Range 2019 2018 Equity investments: Domestic 54.8 % 58.2 % 52.5 % 40.0% – 65.0% International 11.8 % 11.8 % 12.5 % 7.5% – 17.5% Total 66.6 % 70.0 % 65.0 % 60.0% – 70.0% Fixed income funds & cash equivalents 33.4 % 30.0 % 35.0 % 30.0% – 40.0% Total 100.0 % 100.0 % 100.0 % VEBA Actual Target Asset Allocation Permitted Range 2019 2018 Domestic equity investments 64.9 % 65.6 % 65.0 % 60.0% – 70.0% Fixed income funds & cash equivalents 35.1 % 34.4 % 35.0 % 30.0% – 40.0% Total 100.0 % 100.0 % 100.0 %
Fair Value of U.S. Pension Plan and VEBA Trust Assets	The fair values of the U.S. Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2 , as of September 30, 2019 and 2018 are as follows: U.S. Pension Plan Level 1 Level 2 Level 3 Other (a) Total September 30, 2019: Domestic equity investments: S&P 500 Index equity mutual funds $ 176.4 $ — $ — $ — $ 176.4 Small and midcap equity mutual funds 72.8 — — — 72.8 UGI Corporation Common Stock 40.9 — — — 40.9 Total domestic equity investments 290.1 — — — 290.1 International index equity mutual funds 62.1 — — — 62.1 Fixed income investments: Bond index mutual funds 170.5 — — — 170.5 Cash equivalents — — — 6.4 6.4 Total fixed income investments 170.5 — — 6.4 176.9 Total $ 522.7 $ — $ — $ 6.4 $ 529.1 September 30, 2018: Domestic equity investments: S&P 500 Index equity mutual funds $ 188.4 $ — $ — $ — $ 188.4 Small and midcap equity mutual funds 75.7 — — — 75.7 UGI Corporation Common Stock 45.2 — — — 45.2 Total domestic equity investments 309.3 — — — 309.3 International index equity mutual funds 62.9 — — — 62.9 Fixed income investments: Bond index mutual funds 154.3 — — — 154.3 Cash equivalents — — — 5.2 5.2 Total fixed income investments 154.3 — — 5.2 159.5 Total $ 526.5 $ — $ — $ 5.2 $ 531.7 VEBA Level 1 Level 2 Level 3 Other (a) Total September 30, 2019: S&P 500 Index equity mutual fund $ 10.5 $ — $ — $ — $ 10.5 Bond index mutual fund 5.5 — — — 5.5 Cash equivalents — — — 0.2 0.2 Total $ 16.0 $ — $ — $ 0.2 $ 16.2 September 30, 2018: S&P 500 Index equity mutual fund $ 10.1 $ — $ — $ — $ 10.1 Bond index mutual fund 4.9 — — — 4.9 Cash equivalents — — — 0.3 0.3 Total $ 15.0 $ — $ — $ 0.3 $ 15.3 (a) Assets measured at NAV and therefore excluded from the fair value hierarchy.

Utility Regulatory Assets and_2

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)	12 Months Ended
	Sep. 30, 2019
Regulated Operations [Abstract]
Schedule of Regulatory Assets	The following regulatory assets and liabilities associated with UGI Utilities are included in our Consolidated Balance Sheets at September 30: 2019 2018 Regulatory assets: Income taxes recoverable $ 115.2 $ 110.1 Underfunded pension and postretirement plans 178.6 87.1 Environmental costs 59.5 58.8 Removal costs, net 28.3 32.0 Other 14.0 13.0 Total regulatory assets $ 395.6 $ 301.0 Regulatory liabilities (a): Postretirement benefit overcollections $ 14.5 $ 17.8 Deferred fuel and power refunds 6.1 36.7 State income tax benefits — distribution system repairs 25.0 22.6 PAPUC Temporary Rates Order 31.3 24.4 Excess federal deferred income taxes 279.5 285.2 Other 2.4 3.5 Total regulatory liabilities $ 358.8 $ 390.2 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “Other noncurrent liabilities” on the Consolidated Balance Sheets.
Schedule of Regulatory Liabilities	The following regulatory assets and liabilities associated with UGI Utilities are included in our Consolidated Balance Sheets at September 30: 2019 2018 Regulatory assets: Income taxes recoverable $ 115.2 $ 110.1 Underfunded pension and postretirement plans 178.6 87.1 Environmental costs 59.5 58.8 Removal costs, net 28.3 32.0 Other 14.0 13.0 Total regulatory assets $ 395.6 $ 301.0 Regulatory liabilities (a): Postretirement benefit overcollections $ 14.5 $ 17.8 Deferred fuel and power refunds 6.1 36.7 State income tax benefits — distribution system repairs 25.0 22.6 PAPUC Temporary Rates Order 31.3 24.4 Excess federal deferred income taxes 279.5 285.2 Other 2.4 3.5 Total regulatory liabilities $ 358.8 $ 390.2 (a) Regulatory liabilities are recorded in “ Other current liabilities ” and “Other noncurrent liabilities” on the Consolidated Balance Sheets.

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Sep. 30, 2019
Inventory Disclosure [Abstract]
Inventories	Inventories comprise the following at September 30: 2019 2018 Non-utility LPG and natural gas $ 150.2 $ 231.7 Gas Utility natural gas 26.6 37.3 Materials, supplies and other 53.1 49.2 Total inventories $ 229.9 $ 318.2

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Sep. 30, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	At September 30, 2019 , estimated useful lives by asset type were as follows: Asset Type Minimum Estimated Useful Life (in years) Maximum Estimated Useful Life (in years) Buildings and improvements 10 40 Equipment, primarily cylinders and tanks 5 30 Electricity generation facilities 25 40 Pipeline and related assets 25 40 Transportation equipment and office furniture and fixtures 3 10 Computer software 1 10 Property, plant and equipment comprise the following at September 30: 2019 2018 Utility: Distribution $ 3,366.2 $ 3,106.6 Transmission 106.0 97.1 General and other 389.3 281.7 Work in process 76.6 130.9 Total Utility 3,938.1 3,616.3 Non-utility: Land 183.5 191.4 Buildings and improvements 403.8 364.9 Transportation equipment 258.3 257.1 Equipment, primarily cylinders and tanks 3,455.2 3,375.4 Electric generation 326.9 319.5 Pipeline and related assets 1,150.2 473.0 Other 255.3 306.6 Work in process 101.7 57.9 Total non-utility 6,134.9 5,345.8 Total property, plant and equipment $ 10,073.0 $ 8,962.1

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Sep. 30, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Changes in the Carrying Amount of Goodwill	Changes in the carrying amount of goodwill by reportable segment are as follows: AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Total Balance September 30, 2017 $ 2,001.3 $ 912.2 $ 11.6 $ 182.1 $ 3,107.2 Acquisitions 4.5 54.9 — — 59.4 Dispositions (2.8 ) — — — (2.8 ) Purchase accounting adjustments — 13.6 — — 13.6 Foreign currency translation — (17.0 ) — — (17.0 ) Balance September 30, 2018 2,003.0 963.7 11.6 182.1 3,160.4 Acquisitions — 25.6 329.9 — 355.5 Foreign currency translation — (59.5 ) — — (59.5 ) Balance September 30, 2019 $ 2,003.0 $ 929.8 $ 341.5 $ 182.1 $ 3,456.4
Schedule of Finite-Lived Intangible Assets	Intangible assets comprise the following at September 30: 2019 2018 Customer relationships $ 1,038.4 $ 790.4 Trademarks and tradenames 16.2 7.9 Noncompete agreements and other 46.4 58.2 Accumulated amortization (441.8 ) (393.2 ) Intangible assets, net (definite-lived) 659.2 463.3 Trademarks and tradenames (indefinite-lived) 49.4 50.3 Total intangible assets, net $ 708.6 $ 513.6
Schedule of Indefinite-Lived Intangible Assets	Intangible assets comprise the following at September 30: 2019 2018 Customer relationships $ 1,038.4 $ 790.4 Trademarks and tradenames 16.2 7.9 Noncompete agreements and other 46.4 58.2 Accumulated amortization (441.8 ) (393.2 ) Intangible assets, net (definite-lived) 659.2 463.3 Trademarks and tradenames (indefinite-lived) 49.4 50.3 Total intangible assets, net $ 708.6 $ 513.6

Common Stock and Equity-Based_2

Common Stock and Equity-Based Compensation (Tables)	12 Months Ended
	Sep. 30, 2019
Share-based Payment Arrangement [Abstract]
Common Stock Share Activity	UGI Common Stock share activity for Fiscal 2017 , Fiscal 2018 and Fiscal 2019 follows: Issued Treasury Outstanding Balance at September 30, 2016 173,894,141 (933,692 ) 172,960,449 Issued: Employee and director plans 93,550 1,051,704 1,145,254 Sale of reacquired common stock 50,000 50,000 Repurchases of common stock — (900,000 ) (900,000 ) Reacquired common stock – employee and director plans — (111,966 ) (111,966 ) Balance at September 30, 2017 173,987,691 (843,954 ) 173,143,737 Issued: Employee and director plans 155,306 1,804,712 1,960,018 Repurchases of common stock — (1,200,000 ) (1,200,000 ) Reacquired common stock – employee and director plans — (154,780 ) (154,780 ) Balance at September 30, 2018 174,142,997 (394,022 ) 173,748,975 Issued: Employee and director plans 548,285 430,847 979,132 AmeriGas Merger 34,612,847 — 34,612,847 Sale of reacquired common stock — 15,759 15,759 Repurchases of common stock — (300,000 ) (300,000 ) Reacquired common stock – employee and director plans — (51,924 ) (51,924 ) Balance at September 30, 2019 209,304,129 (299,340 ) 209,004,789
Stock Option Awards	Stock option transactions under equity-based compensation plans during Fiscal 2017 , Fiscal 2018 and Fiscal 2019 follow: Shares Weighted - Average Option Price Total Intrinsic Value Weighted - Average Contract Term (Years) Shares under option — September 30, 2016 8,488,451 $ 26.68 $ 157.6 6.6 Granted 1,343,800 $ 46.51 Canceled (60,236 ) $ 41.86 Exercised (990,267 ) $ 21.40 $ 26.7 Shares under option — September 30, 2017 8,781,748 $ 30.20 $ 146.7 6.3 Granted 1,401,400 $ 47.85 Canceled (152,017 ) $ 42.14 Expired (1,666 ) $ 35.80 Exercised (1,832,396 ) $ 26.00 $ 44.5 Shares under option — September 30, 2018 8,197,069 $ 33.93 $ 176.6 6.2 Granted 1,197,100 $ 53.27 Canceled (123,012 ) $ 48.69 Expired (13,699 ) $ 47.49 Exercised (779,353 ) $ 25.75 $ 22.8 Shares under option — September 30, 2019 8,478,105 $ 37.18 $ 114.9 5.9 Options exercisable — September 30, 2017 5,973,668 $ 25.53 Options exercisable — September 30, 2018 5,498,330 $ 28.63 Options exercisable — September 30, 2019 5,963,530 $ 32.02 $ 109.3 4.9 Options not exercisable — September 30, 2019 2,514,575 $ 49.43 $ 5.6 7.4
Additional Information Relating to Stock Options Outstanding and Exercisable	The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2019 : Range of exercise prices Under $30.00 $30.00 – $35.00 $35.01 – $40.00 $40.01 – $45.00 Over $45.00 Options outstanding at September 30, 2019: Number of options 2,879,501 1,094,763 870,115 81,593 3,552,133 Weighted average remaining contractual life (in years) 3.1 6.1 5.3 7.1 8.3 Weighted average exercise price $ 23.24 $ 33.66 $ 37.81 $ 44.42 $ 49.25 Options exercisable at September 30, 2019: Number of options 2,879,501 995,313 870,115 76,593 1,142,008 Weighted average exercise price $ 23.24 $ 33.65 $ 37.81 $ 44.48 $ 47.48
Assumptions Used for Valuing Option Grants	The assumptions we used for valuing option grants during Fiscal 2019 , Fiscal 2018 and Fiscal 2017 are as follows: 2019 2018 2017 Expected life of option 6 years 6 years 5.75 years Weighted average volatility 17.2% 17.5% 19.8% Weighted average dividend yield 1.8% 2.1% 2.1% Expected volatility 17.2% 17.5% 19.8% Expected dividend yield 1.8% 2.1% 2.1% Risk free rate 1.5% – 2.6% 2.2% – 2.9% 1.8% – 2.1%
Weighted Average Assumptions Used to Determine the Fair Value of UGI Performance Unit Awards and Related Compensation Costs	The following table summarizes the weighted-average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs: Grants Awarded in Fiscal Year 2019 2018 2017 Risk free rate 2.5% 2.0% 1.5% Expected life 3 years 3 years 3 years Expected volatility 17.7% 18.9% 18.9% Dividend yield 1.9% 2.1% 2.1%
UGI Performance Unit Award Activity	The following table summarizes UGI Unit award activity for Fiscal 2019 : UGI Units Weighted-Average Grant-Date Fair Value (per Unit) Total UGI Units at September 30, 2018 (a) 959,718 $ 32.38 UGI Performance Units: Granted 128,910 $ 55.40 Forfeited (13,102 ) $ 53.29 Unit awards paid (144,521 ) $ 34.62 UGI Stock Units: Granted (b) 29,784 $ 55.39 Forfeited (4,900 ) $ 51.22 Unit awards paid (62,069 ) $ 25.12 Total UGI Units at September 30, 2019 (a) 893,820 $ 36.39 (a) Total UGI Units includes UGI Stock Units issued to non-employee directors, which vest on the grant date, and UGI Performance Units and UGI Stock Units issued to retirement-eligible employees that vest on an accelerated basis. Total vested restricted units at September 30, 2019 and September 30, 2018 were 616,319 and 660,795 , respectively. (b) Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2018 and Fiscal 2017 were 52,314 and 42,079 , respectively.
Schedule of Payment for UGI Performance Unit and UGI Stock Unit Awards in Shares and Cash	During Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows: 2019 2018 2017 UGI Performance Unit awards: Number of original awards granted, net of forfeitures 144,521 136,621 178,450 Performance period beginning January 1: 2016 2015 2014 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 116,950 69,680 138,985 Cash paid $ 9.9 $ 1.6 $ 10.9 UGI Stock Unit awards: Number of original awards granted, net of forfeitures 50,985 39,680 43,699 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 43,479 29,095 15,990 Cash paid $ 1.0 $ 0.6 $ 0.3
Weighted Average Assumption Used to Determine the Fair Value of AmeriGas Performance Unit Awards and Related Compensation Costs	The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards subject to market-based conditions and related compensation costs: Grants Awarded in Fiscal Year 2019 2018 2017 Risk-free rate 2.5% 2.0% 1.5% Expected life 3 years 3 years 3 years Expected volatility 22.4% 21.1% 21.7% Dividend yield 12.5% 8.2% 7.8%
AmeriGas Common Unit Based Award Activity	The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2019 : AmeriGas Partners Common Units Weighted-Average Grant-Date Fair Value (per Unit) Total Units at September 30, 2018 (a) 236,762 $ 47.12 AmeriGas Performance Units: Granted 79,980 $ 30.23 Forfeited (42,916 ) $ 46.83 Awards paid (17,133 ) $ 43.02 Performance criteria not met (29,394 ) $ 34.27 AmeriGas Stock Units: Granted 53,118 $ 31.10 Forfeited (800 ) $ 45.30 Awards paid (16,056 ) $ 40.98 Total Units at the date of AmeriGas Merger (a) 263,561 $ 40.89 Units converted to UGI cash-settled restricted units (263,561 ) $ (40.89 ) Total Units at September 30, 2019 — $ — (a) Total units includes AmeriGas Stock Units issued to non-employee directors, which vested on the grant date, and AmeriGas Performance Units and AmeriGas Stock Units issued to retirement-eligible employees that vest on an accelerated basis. Total vested restricted units at September 30, 2018 were 71,148 .
AmeriGas Common Unit Based Awards in Common Units and Cash	During Fiscal 2019 , Fiscal 2018 and Fiscal 2017 , the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows: 2019 2018 2017 AmeriGas Performance Unit awards: Number of Common Units subject to original awards granted, net of forfeitures 52,495 65,525 53,800 Performance periods beginning in fiscal year: 2016 2015 2014 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 10,902 13,164 29,489 Cash paid $ 0.8 $ 1.2 $ 2.9 AmeriGas Stock Unit awards: Number of Common Units subject to original awards granted, net of forfeitures 20,585 14,811 32,658 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 9,706 5,322 3,932 Cash paid $ 0.2 $ 0.1 $ 0.1

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Sep. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Minimum Future Payments Under Operating Leases	Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows: 2020 2021 2022 2023 2024 After 2024 AmeriGas Propane $ 82.1 $ 71.6 $ 60.0 $ 52.3 $ 45.0 $ 94.8 UGI Utilities 1.2 0.5 0.4 0.3 0.3 — UGI International 12.9 10.0 7.0 5.7 5.1 6.5 Other 4.2 3.8 3.6 3.4 3.2 37.9 Total $ 100.4 $ 85.9 $ 71.0 $ 61.7 $ 53.6 $ 139.2

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Sep. 30, 2019
Fair Value Disclosures [Abstract]
Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following table presents, on a gross basis, our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2 : Asset (Liability) Level 1 Level 2 Level 3 Total 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 September 30, 2018 Derivative instruments: Assets: Commodity contracts $ 93.5 $ 117.5 $ — $ 211.0 Foreign currency contracts $ — $ 20.6 $ — $ 20.6 Cross-currency contracts $ — $ 0.9 $ — $ 0.9 Liabilities: Commodity contracts $ (33.6 ) $ (9.8 ) $ — $ (43.4 ) Foreign currency contracts $ — $ (14.4 ) $ — $ (14.4 ) Interest rate contracts $ — $ (1.0 ) $ — $ (1.0 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 40.8 $ — $ — $ 40.8 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 8 ).
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: 2019 2018 Carrying amount $ 5,856.6 $ 4,199.4 Estimated fair value $ 6,189.3 $ 4,150.3

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Sep. 30, 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 September 30, 2019 and 2018 and the final settlement date of the Company's open derivative transactions as of September 30, 2019 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) September 30, Type Units Settlements Extending Through 2019 2018 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms October 2020 23.3 23.2 Non-utility Operations LPG swaps Gallons September 2021 800.4 394.3 Natural gas futures, forward and pipeline contracts Dekatherms December 2024 196.1 159.7 Natural gas basis swap contracts Dekatherms December 2024 131.1 54.4 NYMEX natural gas storage futures contracts Dekatherms March 2020 0.3 1.8 NYMEX natural gas option contracts Dekatherms March 2020 2.4 — NYMEX propane storage futures contracts Gallons April 2020 0.5 0.6 Electricity long forward and futures contracts Kilowatt hours January 2023 3,098.1 4,307.6 Electricity short forward and futures contracts Kilowatt hours May 2022 366.7 359.3 Interest Rate Risk: Interest rate swaps Euro October 2022 € 300.0 € 585.8 Interest rate swaps USD July 2024 $ 1,357.3 $ 114.1 Foreign Currency Exchange Rate Risk: Forward foreign exchange contracts USD September 2022 $ 516.0 $ 512.2 Net investment hedge forward foreign exchange contracts Euro October 2024 € 172.8 € — Cross-currency swaps USD N/A $ — $ 49.9
Schedule of Derivative Assets, Liabilities and the Effects of Offsetting	The following table presents the Company’s derivative assets and liabilities by type, as well as the effects of offsetting, as of September 30: 2019 2018 Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 17.4 $ 1.5 Cross-currency contracts — 0.9 17.4 2.4 Derivatives subject to PGC and DS mechanisms: Commodity contracts 1.4 3.0 Derivatives not designated as hedging instruments: Commodity contracts 40.7 208.0 Foreign currency contracts 41.6 19.1 82.3 227.1 Total derivative assets – gross 101.1 232.5 Gross amounts offset in the balance sheet (29.0 ) (34.3 ) Cash collateral received — (12.2 ) Total derivative assets – net $ 72.1 $ 186.0 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ — $ (0.4 ) Interest rate contracts (12.3 ) (1.0 ) (12.3 ) (1.4 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (3.7 ) (0.1 ) Derivatives not designated as hedging instruments: Commodity contracts (171.3 ) (43.3 ) Foreign currency contracts (4.3 ) (14.0 ) (175.6 ) (57.3 ) Total derivative liabilities – gross (191.6 ) (58.8 ) Gross amounts offset in the balance sheet 29.0 34.3 Cash collateral pledged 29.3 — Total derivative liabilities – net $ (133.3 ) $ (24.5 )
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 Consolidated Statements of Income and changes in AOCI for Fiscal 2019 , Fiscal 2018 and Fiscal 2017 : Gain (Loss) Recognized in AOCI Gain (Loss) Reclassified from AOCI into Income Location of Gain (Loss) Reclassified from 2019 2018 2017 2019 2018 2017 Cash Flow Hedges: Foreign currency contracts $ 1.2 $ 0.4 $ 0.2 $ 2.4 $ (3.0 ) $ 17.8 Cost of sales Cross-currency contracts (0.1 ) 1.2 0.5 (0.3 ) 1.1 (0.1 ) Interest expense /other operating income, net Interest rate contracts (11.6 ) 0.2 1.5 (4.5 ) (5.0 ) (3.9 ) Interest expense Total $ (10.5 ) $ 1.8 $ 2.2 $ (2.4 ) $ (6.9 ) $ 13.8 Net Investment Hedges: Foreign currency contracts $ 17.4 $ — $ — Gain (Loss) Recognized in Income Location of Recognized in Income 2019 2018 2017 Derivatives Not Designated as Hedging Instruments: Commodity contracts $ (344.1 ) $ 155.4 $ 166.0 Cost of sales Commodity contracts 7.2 (5.3 ) (2.0 ) Revenues Commodity contracts (0.3 ) 0.3 0.2 Operating and administrative expenses Foreign currency contracts 37.7 16.2 (23.8 ) Other non-operating income (expense), net Total $ (299.5 ) $ 166.6 $ 140.4

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Sep. 30, 2019
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	Changes in AOCI during Fiscal 2019 , Fiscal 2018 and Fiscal 2017 are as follows: Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2016 $ (29.1 ) $ (13.4 ) $ (112.2 ) $ (154.7 ) Other comprehensive income before reclassification adjustments (after-tax) 6.5 1.7 59.4 67.6 Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 5.5 (13.8 ) — (8.3 ) Reclassification adjustments tax (benefit) expense (2.1 ) 4.1 — 2.0 Reclassification adjustments (after-tax) 3.4 (9.7 ) — (6.3 ) Other comprehensive income (loss) attributable to UGI 9.9 (8.0 ) 59.4 61.3 AOCI - September 30, 2017 $ (19.2 ) $ (21.4 ) $ (52.8 ) $ (93.4 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) 10.4 1.0 (30.5 ) (19.1 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) (3.3 ) 6.9 — 3.6 Reclassification adjustments tax expense (benefit) 1.1 (2.6 ) — (1.5 ) Reclassification adjustments (after-tax) (2.2 ) 4.3 — 2.1 Other comprehensive income (loss) attributable to UGI 8.2 5.3 (30.5 ) (17.0 ) AOCI - September 30, 2018 $ (11.0 ) $ (16.1 ) $ (83.3 ) $ (110.4 ) Other comprehensive loss before reclassification adjustments (after-tax) (13.0 ) (7.3 ) (82.2 ) (102.5 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 1.7 2.4 — 4.1 Reclassification adjustments tax benefit (0.5 ) (0.7 ) — (1.2 ) Reclassification adjustments (after-tax) 1.2 1.7 — 2.9 Other comprehensive loss attributable to UGI (11.8 ) (5.6 ) (82.2 ) (99.6 ) Reclassification of stranded income tax effects related to TCJA (2.9 ) (3.7 ) — (6.6 ) AOCI - September 30, 2019 $ (25.7 ) $ (25.4 ) $ (165.5 ) $ (216.6 )

Other Operating Income, Net (Ta

Other Operating Income, Net (Tables)	12 Months Ended
	Sep. 30, 2019
Component of Operating Income [Abstract]
Other Operating Income, Net	Other operating income, net, for Fiscal 2019 , Fiscal 2018 and Fiscal 2017 comprises the following: 2019 2018 2017 Finance charges $ 16.5 $ 16.4 $ 11.8 AFUDC associated with pipeline projects — — 5.5 Interest and interest-related income 5.6 3.2 1.7 Utility non-tariff service income 0.7 2.8 1.5 Loss on private equity partnership investment (1.5 ) — (11.0 ) Gains (losses) on sales of fixed assets, net 2.9 5.3 (3.9 ) Other, net 6.9 3.6 4.9 Total other operating income, net $ 31.1 $ 31.3 $ 10.5

Quarterly Data (unaudited) (Tab

Quarterly Data (unaudited) (Tables)	12 Months Ended
	Sep. 30, 2019
Quarterly Financial Data [Abstract]
Quarterly Data (unaudited)	The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) that we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results fluctuate primarily because of the seasonal nature of our businesses and the effects of unrealized gains and losses on commodity and certain foreign currency derivative instruments (see Note 18 ) and other significant discrete items that can affect the comparison of period-over-period results. December 31, March 31, June 30, September 30, 2018 (a) 2017 (b) 2019 2018 (b) 2019 2018 (b) (c) 2019 (d) 2018 (b) Revenues $ 2,200.2 $ 2,125.2 $ 2,606.1 $ 2,812.0 $ 1,363.7 $ 1,440.9 $ 1,150.4 $ 1,273.1 Operating income (loss) $ 167.7 $ 395.0 $ 538.8 $ 591.0 $ 9.6 $ 29.5 $ (99.0 ) $ 49.2 Net income (loss) including noncontrolling interests $ 88.5 $ 434.2 $ 396.7 $ 407.7 $ (46.5 ) $ (11.7 ) $ (130.8 ) $ (7.8 ) Net income (loss) attributable to UGI Corporation $ 64.2 $ 365.9 $ 245.4 $ 276.0 $ (1.9 ) $ 52.4 $ (51.5 ) $ 24.4 Earnings (loss) per common share attributable to UGI Corporation stockholders: Basic $ 0.37 $ 2.11 $ 1.41 $ 1.59 $ (0.01 ) $ 0.30 $ (0.27 ) $ 0.14 Diluted $ 0.36 $ 2.07 $ 1.38 $ 1.57 $ (0.01 ) $ 0.30 $ (0.27 ) $ 0.14 Weighted-average common shares outstanding (thousands): Basic 174,413 173,670 174,501 173,570 174,759 173,991 189,905 174,391 Diluted 177,566 176,948 177,318 176,350 174,759 176,807 189,905 177,506 (a) Includes loss on extinguishments of debt at UGI International which reduced net income attributable to UGI by $4.2 (see Note 6 ). (b) The quarters ended December 31, 2017, March 31, 2018, June 30, 2018 and September 30, 2018, include the impact of adjustments to remeasure net deferred income tax liabilities associated with (1) the TCJA, including adjustments to provisional amounts, which increased (decreased) net income by $166.0 , $5.3 , $0.8 and $(5.8) , respectively, and (2) the December 2017 French Finance Bills, which increased (decreased) net income by $17.3 , $(3.7) , $(0.1) and $(1.4) , respectively (see Note 7 ). (c) Includes the impact of the impairment of Partnership tradenames and trademarks, which decreased net income attributable to UGI by $14.5 (see Notes 12 and 17 ). (d) Weighted-average common shares outstanding includes the impact from the August 2019 issuance of 34,612,847 shares of UGI Common Stock in connection with the AmeriGas Merger (see Note 5 ).

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Sep. 30, 2019
Segment Reporting [Abstract]
Segment Information	Total Elim- inations AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Corporate & Other (a) 2019 Revenues from external customers $ 7,320.4 $ — $ 2,682.0 $ 2,372.2 $ 1,281.1 $ 980.7 $ 4.4 Intersegment revenues $ — $ (305.4 ) (b) $ — $ — $ 234.6 $ 67.9 $ 2.9 Cost of sales $ 4,323.1 $ (301.7 ) (b) $ 1,191.3 $ 1,416.4 $ 1,241.2 $ 481.3 $ 294.6 Operating income (loss) $ 617.1 $ 0.5 $ 404.0 $ 228.9 $ 105.0 $ 224.2 $ (345.5 ) Income from equity investees 9.1 — — — 9.1 (c) — — Loss on extinguishments of debt (6.1 ) — — — — — (6.1 ) Other non-operating income, net 38.2 — — 5.4 — 1.5 31.3 Earnings (losses) before interest expense and income taxes 658.3 0.5 404.0 234.3 114.1 225.7 (320.3 ) Interest expense (257.8 ) — (167.4 ) (25.0 ) (9.0 ) (49.6 ) (6.8 ) Income tax (expense) benefit (92.6 ) (0.2 ) (25.7 ) (64.6 ) (27.1 ) (42.9 ) 67.9 Noncontrolling interests’ net (income) loss (51.7 ) — (142.7 ) 0.1 — — 90.9 Net income (loss) attributable to UGI $ 256.2 $ 0.3 $ 68.2 $ 144.8 $ 78.0 $ 133.2 $ (168.3 ) Depreciation and amortization $ 448.1 $ (0.2 ) $ 179.4 $ 123.8 $ 51.4 $ 92.8 $ 0.9 Total assets $ 13,346.6 $ (352.8 ) $ 4,095.3 $ 2,975.2 $ 2,744.5 $ 3,559.5 $ 324.9 Short-term borrowings $ 796.3 $ — $ 328.0 $ 210.9 $ 91.4 $ 166.0 $ — Capital expenditures (including the effects of accruals) $ 707.6 $ — $ 107.3 $ 106.4 $ 137.7 $ 355.3 $ 0.9 Investments in equity investees $ 189.6 $ — $ — $ 11.6 $ 178.0 $ — $ — Goodwill $ 3,456.4 $ — $ 2,003.0 $ 929.8 $ 341.5 $ 182.1 $ — 2018 (d)(e) Revenues from external customers $ 7,651.2 $ — $ 2,823.0 $ 2,683.8 $ 1,149.1 $ 998.5 $ (3.2 ) Intersegment revenues $ — $ (370.8 ) (b) $ — $ — $ 272.6 $ 93.9 $ 4.3 Cost of sales $ 4,074.9 $ (366.6 ) (b) $ 1,314.7 $ 1,620.1 $ 1,090.8 $ 522.9 $ (107.0 ) Operating income (loss) $ 1,064.7 $ 0.3 $ 422.2 $ 247.9 $ 175.1 $ 239.9 $ (20.7 ) (d) Income (loss) from equity investees 4.3 — — (0.5 ) 4.8 (c) — — Other non-operating income (expense), net 15.6 — — (7.0 ) (1.2 ) (2.4 ) 26.2 Earnings before interest expense and income taxes 1,084.6 0.3 422.2 240.4 178.7 237.5 5.5 Total Elim- inations AmeriGas Propane UGI International Midstream & Marketing UGI Utilities Corporate & Other (a) Interest expense (230.1 ) — (163.1 ) (21.1 ) (2.4 ) (42.9 ) (0.6 ) Income tax (expense) benefit (32.1 ) (1.4 ) (30.5 ) (69.2 ) (49.6 ) (53.7 ) 172.3 Noncontrolling interests’ net (income) loss (103.7 ) — (152.3 ) 3.0 — — 45.6 Net income (loss) attributable to UGI $ 718.7 $ (1.1 ) $ 76.3 $ 153.1 $ 126.7 $ 140.9 $ 222.8 Depreciation and amortization $ 455.1 $ (0.3 ) $ 185.8 $ 140.6 $ 43.5 $ 84.6 $ 0.9 Total assets $ 11,980.9 $ (125.3 ) $ 3,933.9 $ 3,279.0 $ 1,328.9 $ 3,266.6 $ 297.8 Short-term borrowings $ 424.9 $ — $ 232.0 $ 1.4 $ 2.0 $ 189.5 $ — Capital expenditures (including the effects of accruals) $ 597.0 $ — $ 101.3 $ 111.4 $ 43.1 $ 338.5 $ 2.7 Investments in equity investees $ 87.6 $ — $ — $ 12.8 $ 74.8 $ — $ — Goodwill $ 3,160.4 $ — $ 2,003.0 $ 963.7 $ 11.6 $ 182.1 $ — 2017 (e) Revenues from external customers $ 6,120.7 $ — $ 2,453.5 $ 1,877.5 $ 943.0 $ 847.5 $ (0.8 ) Intersegment revenues $ — $ (222.7 ) (b) $ — $ — $ 178.2 $ 40.1 $ 4.4 Cost of sales $ 2,837.3 $ (218.3 ) (b) $ 1,002.9 $ 935.3 $ 856.7 $ 367.3 $ (106.6 ) Operating income $ 1,010.0 $ 0.3 $ 355.3 $ 234.3 $ 139.4 $ 232.7 $ 48.0 Income from equity investees 4.3 — — — 4.3 (c) — — Loss on extinguishments of debt (59.7 ) — — — — — (59.7 ) Other non-operating (expense) income, net (29.7 ) — — 1.2 (0.2 ) (4.4 ) (26.3 ) Earnings (losses) before interest expense and income taxes 924.9 0.3 355.3 235.5 143.5 228.3 (38.0 ) Interest expense (223.5 ) — (160.2 ) (20.6 ) (2.1 ) (40.2 ) (0.4 ) Income tax (expense) benefit (177.6 ) (0.2 ) (32.5 ) (58.9 ) (54.5 ) (72.1 ) 40.6 Noncontrolling interests’ net (income) loss (87.2 ) — (108.4 ) (0.2 ) — — 21.4 Net income attributable to UGI $ 436.6 $ 0.1 $ 54.2 $ 155.8 $ 86.9 $ 116.0 $ 23.6 Depreciation and amortization $ 416.3 $ (0.2 ) $ 190.5 $ 117.4 $ 35.4 $ 72.3 $ 0.9 Total assets $ 11,582.2 $ (51.5 ) $ 4,069.4 $ 3,132.0 $ 1,165.5 $ 2,994.0 $ 272.8 Short-term borrowings $ 366.9 $ — $ 140.0 $ 17.9 $ 39.0 $ 170.0 $ — Capital expenditures (including the effects of accruals) $ 624.3 $ — $ 98.1 $ 90.3 $ 117.5 $ 317.7 $ 0.7 Investments in equity investees $ 59.1 $ — $ — $ 8.1 $ 51.0 $ — $ — Goodwill $ 3,107.2 $ — $ 2,001.3 $ 912.2 $ 11.6 $ 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 Fiscal 2019 , Fiscal 2018 and Fiscal 2017 : Location on Income Statement AmeriGas Propane UGI International Midstream & Marketing 2019 Net losses on commodity derivative instruments not associated with current-period transactions Revenue / Cost of sales $ (116.8 ) $ (142.5 ) $ (31.0 ) Unrealized gains on foreign currency derivative instruments Other non-operating income (expense), net $ — $ 32.2 $ — Loss on extinguishments of debt Loss on extinguishment of debt $ — $ (6.1 ) $ — AmeriGas Merger expenses Operating and administrative expenses $ (6.3 ) $ — $ — Acquisition and integration expenses associated with the CMG Acquisition Operating and administrative expenses $ — $ — $ (15.6 ) LPG business transformation costs Operating and administrative expenses $ (14.5 ) $ (9.3 ) $ — 2018 Net gains (losses) on commodity derivative instruments not associated with current-period transactions Revenue / Cost of sales $ 12.5 $ 92.9 $ (1.5 ) Unrealized gains on foreign currency derivative instruments Other non-operating income (expense), net $ — $ 28.9 $ — Integration expenses associated with Finagaz Operating and administrative expenses $ — $ (30.5 ) $ — Impairment of Partnership tradenames and trademarks Impairment of Partnership tradenames and trademarks $ (75.0 ) $ — $ — 2017 Net gains on commodity derivative instruments not associated with current-period transactions Revenue / Cost of sales $ 31.1 $ 19.0 $ 55.7 Unrealized losses on foreign currency derivative instruments Other non-operating income (expense), net $ — $ (23.8 ) $ — Loss on extinguishments of debt Loss on extinguishment of debt $ (59.7 ) $ — $ — Integration expenses associated with Finagaz Operating and administrative expenses $ — $ (39.9 ) $ — (b) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (c) Includes AFUDC associated with PennEast (see Note 2 ). Fiscal 2019 also includes income from Pennant subsequent to the CMG Acquisition (see Note 5 ). (d) Fiscal 2018 results include impacts from the TCJA in the U.S. See Notes 7 and 9 for additional information. For Fiscal 2018, the remeasurement impacts from the TCJA and, for UGI International, the December 2017 French Finance Bills, were allocated from each of AmeriGas Propane, UGI International, Midstream & Marketing and UGI Utilities to Corporate & Other in amounts of $112.9 , $4.0 , $70.1 and $8.0 , respectively. For Fiscal 2017, the remeasurement impact from the December 2016 French Finance Bills of $29.0 was allocated from UGI International to Corporate & Other. (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 ($)shares	Aug. 20, 2019	Aug. 01, 2019shares	Sep. 30, 2019USD ($)countyshares	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)
Investment [Line Items]
Total cash paid				$ 528.9	$ 0	$ 0
General Partner held a general partner interest in AmeriGas Partners				2.00%
Percentage of limited partnership interest in AmeriGas Partners				98.00%
Number of counties of operation | county				1
AmeriGas Partners
Investment [Line Items]
General Partner held a general partner interest in AmeriGas Partners				1.00%
AmeriGas OLP
Investment [Line Items]
General Partner held a general partner interest in AmeriGas Partners				1.01%
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]
Total cash paid	$ 528.9
Merger Sub | Common Stock
Investment [Line Items]
Consideration paid (in shares) | shares	34,612,847		34,612,847	34,613,000
Pennant | Affiliated Entity | CMG
Investment [Line Items]
Ownership percentage			47.00%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Principles of Consolidation (Details) $ in Millions	12 Months Ended
	Sep. 30, 2019USD ($)mi	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)
Schedule of Equity Method Investments [Line Items]
Ownership interests in certain subsidiaries under equity method investment, maximum	100.00%
Investments	$ 242.4	$ 147.2
Equity method investments	189.6	87.6	$ 59.1
Pennant
Schedule of Equity Method Investments [Line Items]
Equity method investments	90.8
UGI PennEast, LLC | PennEast
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 84.7	$ 72.6
Southern Company | PennEast
Schedule of Equity Method Investments [Line Items]
Ownership percentage	20.00%
New Jersey Resources | PennEast
Schedule of Equity Method Investments [Line Items]
Ownership percentage	20.00%
South Jersey Industries | PennEast
Schedule of Equity Method Investments [Line Items]
Ownership percentage	20.00%
Enbridge Inc | PennEast
Schedule of Equity Method Investments [Line Items]
Ownership percentage	20.00%
PennEast
Schedule of Equity Method Investments [Line Items]
Area of natural gas pipeline to be constructed (in miles) | mi	120
Pipeline contract term	15 years
Affiliated Entity | UGI PennEast, LLC | PennEast
Schedule of Equity Method Investments [Line Items]
Ownership percentage	20.00%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Revenue Recognition (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Oct. 01, 2018	Oct. 01, 2017	Oct. 01, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Contract length	less than one year
ASC 606 | Retained earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reduction in opening retained earnings		$ 7.1	$ 0	$ 0

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Accounting Policies [Abstract]
Accumulated deferred investment tax credit	$ 2.3	$ 2.6
Effective income tax rate reconciliation, at federal statutory income tax rate, percent	21.00%	24.50%	35.00%

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Other non-operating income (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Accounting Policies [Abstract]
Gains (losses) on foreign currency contracts, net	$ 37.7	$ 16.2	$ (23.9)
Pension and other postretirement plans non-service expense	0.5	(0.6)	(5.8)
Total other non-operating income (expense), net	$ 38.2	$ 15.6	$ (29.7)

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details) - shares	Aug. 21, 2019	Aug. 01, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Weighted-average common shares outstanding for basic computation (in shares)			189,905,000	174,759,000	174,501,000	174,413,000	174,391,000	173,991,000	173,570,000	173,670,000	178,417,000	173,908,000	173,662,000
Incremental shares issuable for stock options and common stock awards (in shares)											2,694,000	2,997,000	3,497,000
Weighted-average common shares outstanding for diluted computation (in shares)			189,905,000	174,759,000	177,318,000	177,566,000	177,506,000	176,807,000	176,350,000	176,948,000	181,111,000	176,905,000	177,159,000
Antidilutive securities excluded from computation of earnings per share (in shares)											1,162,000		146,000
Common Stock | Merger Sub
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Consideration paid (in shares)	34,612,847	34,612,847									34,613,000

Summary of Significant Accoun_9

Summary of Significant Accounting Policies - Reconciliation of the total cash, cash equivalents and restricted cash (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Accounting Policies [Abstract]
Cash and cash equivalents	$ 447.1	$ 452.6	$ 558.4	$ 502.8
Restricted cash	63.7	9.6	10.3	15.6
Cash, cash equivalents and restricted cash	$ 510.8	$ 462.2	$ 568.7	$ 518.4

Summary of Significant Accou_10

Summary of Significant Accounting Policies - Estimated Useful Lives by Type (Details)	12 Months Ended
	Sep. 30, 2019
Buildings and improvements | Minimum
Property, Plant and Equipment
Useful life (in years)	10 years
Buildings and improvements | Maximum
Property, Plant and Equipment
Useful life (in years)	40 years
Equipment, primarily cylinders and tanks | Minimum
Property, Plant and Equipment
Useful life (in years)	5 years
Equipment, primarily cylinders and tanks | Maximum
Property, Plant and Equipment
Useful life (in years)	30 years
Electricity generation facilities | Minimum
Property, Plant and Equipment
Useful life (in years)	25 years
Electricity generation facilities | Maximum
Property, Plant and Equipment
Useful life (in years)	40 years
Pipeline and related assets | Minimum
Property, Plant and Equipment
Useful life (in years)	25 years
Pipeline and related assets | Maximum
Property, Plant and Equipment
Useful life (in years)	40 years
Transportation equipment and office furniture and fixtures | Minimum
Property, Plant and Equipment
Useful life (in years)	3 years
Transportation equipment and office furniture and fixtures | Maximum
Property, Plant and Equipment
Useful life (in years)	10 years
Computer software | Minimum
Property, Plant and Equipment
Useful life (in years)	1 year
Computer software | Maximum
Property, Plant and Equipment
Useful life (in years)	10 years

Summary of Significant Accou_11

Summary of Significant Accounting Policies - Average Composite Depreciation Rates (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets	$ 3.7	$ 6.3
Depreciation	$ 388.5	$ 396.5	$ 365.5
Amortization period	5 years
Gas Utility
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates	2.20%	2.30%	2.20%
Electric Utility
Public Utility, Property, Plant and Equipment [Line Items]
Average composite depreciation rates	2.10%	2.20%	2.40%
UGI Utilities
Public Utility, Property, Plant and Equipment [Line Items]
Regulatory assets	$ 395.6	$ 301
Computer software | UGI Utilities
Public Utility, Property, Plant and Equipment [Line Items]
Useful life (in years)	15 years

Summary of Significant Accou_12

Summary of Significant Accounting Policies - Goodwill and Intangible Assets (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Finite-Lived Intangible Assets [Line Items]
Useful life		3 years
Impairment of intangible assets, finite-lived	$ 0	$ 75,000,000	$ 0
Finite-lived trademarks and tradenames, gross		7,900,000
Accumulated impairment losses	0	0
Provision for goodwill or other intangible asset impairments	$ 0	$ 0	$ 0
Customer relationships, noncompete agreements, and other
Finite-Lived Intangible Assets [Line Items]
Useful life	15 years
CMG | Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Useful life	35 years

Summary of Significant Accou_13

Summary of Significant Accounting Policies - Impairment of Long-Lived Assets and Cost Basis Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Accounting Policies [Abstract]
Provisions for impairments	$ 0	$ 0	$ 0

Summary of Significant Accou_14

Summary of Significant Accounting Policies - Refundable Tank and Cylinder Deposits (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018
Accounting Policies [Abstract]
Customer paid deposits primarily on owned tanks and cylinders	$ 279.7	$ 272

Accounting Changes - Narrative

Accounting Changes - Narrative (Details) - USD ($) $ in Millions	Oct. 01, 2018	Oct. 01, 2019
ASU 2018-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Tax Cuts and Jobs Act of 2017, reclassification from AOCI to retained earnings, tax effect	$ 6.6
Minimum | Forecast | Subsequent Event | ASU 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease, right-of-use asset		$ 400
Operating lease, liability		400
Maximum | Forecast | Subsequent Event | ASU 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease, right-of-use asset		600
Operating lease, liability		$ 600

Revenue from Contracts with Cus

Revenue from Contracts with Customers (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Oct. 01, 2018
Disaggregation of Revenue [Line Items]
Contract with customer, liability	$ 114.1	$ 111.2
Contract with customer, liability, revenue recognized	$ 90.7
Natural Gas Transportation and Gathering Services
Disaggregation of Revenue [Line Items]
Term of contract with customer	30 years
Storage Services
Disaggregation of Revenue [Line Items]
Term of contract with customer	1 year
Natural Gas
Disaggregation of Revenue [Line Items]
Term of contract with customer	15 years
Midstream & Marketing
Disaggregation of Revenue [Line Items]
Revenue, remaining performance obligation	$ 2,000
UGI Utilities
Disaggregation of Revenue [Line Items]
Revenue, remaining performance obligation	$ 200

Revenue from Contract with Cu_3

Revenue from Contract with Customers - Schedule of Disaggregation of Revenue By Reportable Segment (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									$ 7,210.7
Other revenues									109.7
Total revenues	$ 1,150.4	$ 1,363.7	$ 2,606.1	$ 2,200.2	$ 1,273.1	$ 1,440.9	$ 2,812	$ 2,125.2	7,320.4	$ 7,651.2	$ 6,120.7
Negative surcharge									5.5
Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									552.7
Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									226.3
Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									138
Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									46.4
Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									14.9
Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									978.3
Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									4,007.9
Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									233.3
Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									1,520.7
Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									94.5
Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									17.6
Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									1.9
Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									43.2
Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									313.3
Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									6,232.4
Eliminations
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									(302.2)
Other revenues									(3.2)
Total revenues									(305.4)	(370.8)	(222.7)
Eliminations | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Eliminations | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Eliminations | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Eliminations | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									(64.8)
Eliminations | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									(3.1)
Eliminations | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									(67.9)
Eliminations | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Eliminations | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Eliminations | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									(134.2)
Eliminations | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Eliminations | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									(96.8)
Eliminations | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Eliminations | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Eliminations | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									(3.3)
Eliminations | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									(234.3)
Eliminations | AmeriGas Propane
Disaggregation of Revenue [Line Items]
Total revenues									0	0	0
Eliminations | UGI International
Disaggregation of Revenue [Line Items]
Total revenues									0	0	0
Eliminations | Midstream & Marketing
Disaggregation of Revenue [Line Items]
Total revenues									234.6	272.6	178.2
Eliminations | UGI Utilities
Disaggregation of Revenue [Line Items]
Total revenues									67.9	93.9	40.1
Operating Segments | AmeriGas Propane
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									2,618
Other revenues									64
Total revenues									2,682	2,823	2,453.5
Operating Segments | AmeriGas Propane | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | AmeriGas Propane | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | AmeriGas Propane | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | AmeriGas Propane | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | AmeriGas Propane | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | AmeriGas Propane | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | AmeriGas Propane | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									2,340.9
Operating Segments | AmeriGas Propane | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									63.9
Operating Segments | AmeriGas Propane | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | AmeriGas Propane | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | AmeriGas Propane | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | AmeriGas Propane | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | AmeriGas Propane | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | AmeriGas Propane | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									213.2
Operating Segments | AmeriGas Propane | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									2,618
Operating Segments | UGI International
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									2,339.6
Other revenues									32.6
Total revenues									2,372.2	$ 2,683.8	$ 1,877.5
Operating Segments | UGI International | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI International | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI International | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI International | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI International | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI International | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI International | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									1,667
Operating Segments | UGI International | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									169.4
Operating Segments | UGI International | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									448.3
Operating Segments | UGI International | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI International | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI International | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI International | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI International | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									54.9
Operating Segments | UGI International | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									2,339.6
Operating Segments | Midstream & Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									1,509.1
Other revenues									6.6
Total revenues									1,515.7
Operating Segments | Midstream & Marketing | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | Midstream & Marketing | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | Midstream & Marketing | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | Midstream & Marketing | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | Midstream & Marketing | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | Midstream & Marketing | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | Midstream & Marketing | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | Midstream & Marketing | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | Midstream & Marketing | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									1,206.6
Operating Segments | Midstream & Marketing | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									94.5
Operating Segments | Midstream & Marketing | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									114.4
Operating Segments | Midstream & Marketing | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									1.9
Operating Segments | Midstream & Marketing | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									43.2
Operating Segments | Midstream & Marketing | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									48.5
Operating Segments | Midstream & Marketing | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									1,509.1
Operating Segments | UGI Utilities
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									1,046.2
Other revenues									2.4
Total revenues									1,048.6
Operating Segments | UGI Utilities | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									552.7
Operating Segments | UGI Utilities | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									226.3
Operating Segments | UGI Utilities | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									138
Operating Segments | UGI Utilities | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									111.2
Operating Segments | UGI Utilities | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									18
Operating Segments | UGI Utilities | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									1,046.2
Operating Segments | UGI Utilities | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI Utilities | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI Utilities | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI Utilities | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI Utilities | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI Utilities | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI Utilities | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI Utilities | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Operating Segments | UGI Utilities | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Other revenues									7.3
Total revenues									7.3
Corporate & Other | Residential
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Commercial & Industrial
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Large delivery service
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Off-system sales and capacity releases
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Total Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Retail
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Wholesale
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Energy Marketing
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Pipeline
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Peaking
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Electricity Generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									0
Corporate & Other | Total Non-Utility
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers									$ 0

AmeriGas Merger and Acquisiti_3

AmeriGas Merger and Acquisitions - Narrative (Details) $ / shares in Units, $ in Millions	Aug. 21, 2019USD ($)$ / sharesshares	Aug. 01, 2019USD ($)shares	Sep. 30, 2019USD ($)shares	Sep. 30, 2018USD ($)propane_distribution_business	Sep. 30, 2017USD ($)
Total cash paid			$ 528.9	$ 0	$ 0
Merger Sub
Total cash paid	$ 528.9
Incentive distribution, distribution	2,227.7
After tax transaction costs	7.7
Operating expenses	6.3
Deferred tax asset, step up in tax basis of the underlying assets	$ 512.3		$ 512.3
Merger Sub | Common Stock
Consideration paid (in shares) | shares	34,612,847	34,612,847	34,613,000
CMG
Total cash paid		$ 1,284.4
After tax transaction costs		$ 15.3
Merger Agreement, Proposed Consideration One | Merger Sub | Common Stock
Business combination, consideration transferred, equity interests issuable per acquiree share (in shares) | shares	0.500
Merger Agreement, Proposed Consideration Two | Merger Sub | Common Stock
Business combination, consideration transferred, equity interests issuable per acquiree share (in shares) | shares	0.6378
Merger Agreement, Proposed Consideration Two | Merger Sub | Cash Without Interest
Business combination, consideration transferred, equity interests issuable per share (in dollars per share) | $ / shares	$ 7.63
Merger Agreement, Proposed Consideration Three | Merger Sub | Cash Without Interest
Business combination, consideration transferred, equity interests issuable per share (in dollars per share) | $ / shares	$ 35.325
AmeriGas Propane
Total cash paid				10.1	36.8
Incentive distribution, distribution				$ 12.8	$ 47.6
Number of retail propane distribution businesses acquired | propane_distribution_business				2
Affiliated Entity | CMG | Pennant
Percentage of voting interests acquired		47.00%

AmeriGas Merger and Acquisiti_4

AmeriGas Merger and Acquisitions - Components of Final Purchase Price Allocation (Details) - USD ($) $ in Millions	Aug. 01, 2019	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Business Acquisition [Line Items]
Goodwill		$ 3,456.4	$ 3,160.4	$ 3,107.2
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

AmeriGas Merger and Acquisiti_5

AmeriGas Merger and Acquisitions - Total Cash Paid and Liabilities Incurred (Details) $ in Millions	12 Months Ended
	Sep. 30, 2019USD ($)mi	Sep. 30, 2018USD ($)miMW	Sep. 30, 2017USD ($)
Business Acquisition [Line Items]
Natural gas lines, acquired (in miles) | mi	21	60
Payments to acquire long-term investments	$ 20	$ 70.3
Natural gas-fired peaking turbine, acquired (mw) | MW		44
UGI International
Business Acquisition [Line Items]
Total cash paid	49.3	$ 121.9	$ 99.7
Liabilities incurred	0	0	20.6
Total purchase price	49.3	121.9	120.3
Midstream & Marketing
Business Acquisition [Line Items]
Total cash paid	15
Liabilities incurred	0
Total purchase price	$ 15
AmeriGas Propane
Business Acquisition [Line Items]
Total cash paid		10.1	36.8
Liabilities incurred		2.7	10.8
Total purchase price		$ 12.8	$ 47.6

Debt - AmeriGas Propane (Detail

Debt - AmeriGas Propane (Details) - USD ($)	1 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017
AmeriGas Partners | Senior Notes | 5.50% due May 2025
Debt Instrument
Aggregate principal amount		$ 700,000,000
Stated interest rate		5.50%
AmeriGas Partners | Senior Notes | 5.75% due May 2027
Debt Instrument
Aggregate principal amount		$ 525,000,000
Stated interest rate		5.75%
AmeriGas Partners | Senior Notes | 7.00% Senior Notes
Debt Instrument
Stated interest rate		7.00%
Aggregate principal balance repaid		$ 980,800,000
Revolving Credit Facility | Line of Credit | AmeriGas Credit Agreement
Debt Instrument
Total capacity (up to)	$ 600,000,000
Letter of Credit | Line of Credit | AmeriGas Credit Agreement
Debt Instrument
Total capacity (up to)	$ 150,000,000
Federal Funds Effective Swap Rate | AmeriGas Credit Agreement
Debt Instrument
Basis spread on variable rate (percentage)	0.50%
Minimum | Base Rate | AmeriGas Credit Agreement
Debt Instrument
Basis spread on variable rate (percentage)	0.50%
Minimum | Eurodollar | AmeriGas Credit Agreement
Debt Instrument
Basis spread on variable rate (percentage)	1.50%
Maximum | Base Rate | AmeriGas Credit Agreement
Debt Instrument
Basis spread on variable rate (percentage)	1.75%
Maximum | Eurodollar | AmeriGas Credit Agreement
Debt Instrument
Basis spread on variable rate (percentage)	2.75%

Debt - Loss on Extinguishment

Debt - Loss on Extinguishment of Debt (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Debt Instrument, Redemption [Line Items]
Loss on extinguishments of debt	$ 4.2	$ 6.1	$ 0	$ 59.7
AmeriGas Partners
Debt Instrument, Redemption [Line Items]
Early redemption premiums				51.3
Write-off of unamortized debt issuance costs				8.4
Loss on extinguishments of debt				$ 59.7

Debt - UGI International (Deta

Debt - UGI International (Details)

Aug. 13, 2019

Jul. 02, 2019

Oct. 25, 2018USD ($)

Oct. 25, 2018EUR (€)

Oct. 18, 2018EUR (€)

Dec. 31, 2017USD ($)

Dec. 31, 2018USD ($)

Sep. 30, 2019USD ($)

Sep. 30, 2018USD ($)

Sep. 30, 2017USD ($)

Sep. 30, 2019EUR (€)

Sep. 30, 2018EUR (€)

Dec. 31, 2017EUR (€)

Debt Instrument

Available borrowing capacity | $

$ 5,804,000,000

$ 4,165,300,000

Loss on extinguishments of debt | $

$ (4,200,000)

(6,100,000)

0

$ (59,700,000)

Line of Credit | Term Loan

Debt Instrument

Debt instrument, term

7 years

Line of Credit | Revolving Credit Facility

Debt Instrument

Debt instrument, term

5 years

UGI International Credit Agreement | Line of Credit | Revolving Credit Facility

Debt Instrument

Total capacity (up to)

€ 300,000,000

Borrowings outstanding | $

0

UGI International LLC

Debt Instrument

Total capacity (up to)

€ 300,000,000

€ 300,000,000

UGI International LLC | UGI International Credit Agreement | Line of Credit | Term Loan

Debt Instrument

Debt instrument, term

5 years

Available borrowing capacity

€ 300,000,000

UGI International LLC | UGI International Credit Agreement | Line of Credit | Revolving Credit Facility

Debt Instrument

Total capacity (up to)

€ 300,000,000

Variable interest rate floor (percentage)

0.00%

UGI International LLC | 3.25% Senior Unsecured Notes Due November 2025 | Senior Notes

Debt Instrument

Aggregate principal amount

€ 350,000,000

Stated interest rate

3.25%

Loss on extinguishments of debt | $

(6,100,000)

UGI France

Debt Instrument

Repayments of debt

€ 540,000,000

Flaga

Debt Instrument

Total capacity (up to)

55,000,000

Repayments of debt

$ 49,900,000

€ 45,800,000

Flaga | Flaga U.S. dollar variable-rate term loan | Term Loan

Debt Instrument

Repayments of debt | $

$ 9,200,000

Long-term debt, gross | $

$ 59,100,000

$ 0

$ 49,900,000

UGI France

Debt Instrument

Available borrowing capacity

60,000,000

Total capacity (up to)

€ 60,000,000

EURIBOR | UGI International LLC | UGI International Credit Agreement | Line of Credit | Revolving Credit Facility

Debt Instrument

Basis spread on variable rate (percentage)

1.70%

Derivative, fixed interest rate

0.34%

Minimum | UGI International LLC | UGI International Credit Agreement | Line of Credit

Debt Instrument

Basis spread on variable rate (percentage)

1.55%

Minimum | EURIBOR | UGI International LLC | UGI International Credit Agreement | Line of Credit | Revolving Credit Facility

Debt Instrument

Basis spread on variable rate (percentage)

1.20%

Minimum | London Interbank Offered Rate (LIBOR) | UGI International LLC | UGI International Credit Agreement | Line of Credit | Revolving Credit Facility

Debt Instrument

Basis spread on variable rate (percentage)

1.45%

Minimum | London Interbank Offered Rate (LIBOR) | Flaga | Flaga U.S. dollar variable-rate term loan | Term Loan

Debt Instrument

Basis spread on variable rate (percentage)

1.125%

Maximum | UGI International LLC | UGI International Credit Agreement | Line of Credit

Debt Instrument

Basis spread on variable rate (percentage)

3.20%

Maximum | EURIBOR | UGI International LLC | UGI International Credit Agreement | Line of Credit | Revolving Credit Facility

Debt Instrument

Basis spread on variable rate (percentage)

2.85%

Maximum | London Interbank Offered Rate (LIBOR) | UGI International LLC | UGI International Credit Agreement | Line of Credit | Revolving Credit Facility

Debt Instrument

Basis spread on variable rate (percentage)

3.10%

Debt - Energy Services (Detail

Debt - Energy Services (Details) - Term Loan - Line of Credit - USD ($)	Aug. 13, 2019	Aug. 31, 2019
Debt Instrument
Debt instrument, term	7 years
Energy Services
Debt Instrument
Aggregate principal amount	$ 700,000,000
Debt instrument, quarterly payment	$ 1,800,000
Basis spread on variable rate (percentage)	3.75%
Energy Services | London Interbank Offered Rate (LIBOR)
Debt Instrument
Derivative, fixed interest rate		1.55%

Debt - UGI Utilities (Details)

Debt - UGI Utilities (Details) - UGI Utilities - USD ($)	1 Months Ended	12 Months Ended
	Oct. 31, 2017	Sep. 30, 2019	Jun. 27, 2019	Feb. 01, 2019	Sep. 30, 2018
Debt Instrument
Total capacity (up to)		$ 350,000,000			$ 450,000,000
Line of Credit | 2019 Credit Agreement
Debt Instrument
Total capacity (up to)			$ 350,000,000
Additional loan amount			150,000,000
Line of Credit | 2019 Credit Agreement | Minimum
Debt Instrument
Basis spread on variable rate (percentage)		0.00%
Line of Credit | 2019 Credit Agreement | Maximum
Debt Instrument
Basis spread on variable rate (percentage)		1.75%
Senior Notes | 4.55% Senior Notes due February 2049
Debt Instrument
Aggregate principal amount				$ 150,000,000
Stated interest rate				4.55%
Term Loan
Debt Instrument
Aggregate principal amount	$ 125,000,000
Debt instrument, quarterly payment	$ 1,600,000
Term Loan | Minimum
Debt Instrument
Basis spread on variable rate (percentage)	0.00%
Term Loan | Maximum
Debt Instrument
Basis spread on variable rate (percentage)	1.875%
Derivative, fixed interest rate	3.00%
Letter of Credit | Line of Credit | 2019 Credit Agreement
Debt Instrument
Total capacity (up to)		$ 50,000,000	100,000,000
Revolving Credit Facility | Line of Credit | 2019 Credit Agreement
Debt Instrument
Total capacity (up to)			$ 450,000,000

Debt - UGI Corporation (Detail

Debt - UGI Corporation (Details) - USD ($)	Aug. 13, 2019	Aug. 01, 2019	Jul. 02, 2019	Sep. 30, 2019	Aug. 31, 2019	Aug. 21, 2019
Term Loan | Line of Credit
Debt Instrument
Debt instrument, term	7 years
Revolving Credit Facility | Line of Credit
Debt Instrument
Debt instrument, term			5 years
5-year Term Loan | Term Loan | Line of Credit
Debt Instrument
Debt instrument, term			5 years
Aggregate principal amount		$ 250,000,000
3-year Term loan | Term Loan | Line of Credit
Debt Instrument
Debt instrument, term			3 years
Aggregate principal amount		300,000,000
UGI Corporation
Debt Instrument
Total capacity				$ 300,000,000
UGI Corporation | Revolving Credit Facility | Line of Credit
Debt Instrument
Total capacity		300,000,000
UGI Corporation | Letter of Credit | Line of Credit
Debt Instrument
Total capacity		10,000,000
UGI Corporation | 5-year Term Loan | Term Loan | Line of Credit
Debt Instrument
Long-term debt, gross		250,000,000				$ 250,000,000
Debt instrument, quarterly payment		$ 9,400,000
Basis spread on variable rate (percentage)		2.50%
UGI Corporation | 3-year Term loan | Term Loan | Line of Credit
Debt Instrument
Long-term debt, gross		$ 300,000,000
Basis spread on variable rate (percentage)		2.25%
Aggregate principal amount		$ 300,000,000
UGI Corporation | London Interbank Offered Rate (LIBOR) | 5-year Term Loan | Term Loan | Line of Credit
Debt Instrument
Derivative, fixed interest rate				1.56%
UGI Corporation | London Interbank Offered Rate (LIBOR) | 3-year Term loan | Term Loan | Line of Credit
Debt Instrument
Derivative, fixed interest rate					1.51%

Debt - Schedule of Long-term D

Debt - Schedule of Long-term Debt (Details) € in Millions, $ in Millions	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2018EUR (€)	Dec. 31, 2017USD ($)
Debt Instrument
Total long-term debt	$ 5,804	$ 4,165.3
Less: current maturities	(24.1)	(18.8)
Total long-term debt due after one year	5,779.9	4,146.5
AmeriGas Propane
Debt Instrument
Unamortized debt issuance costs	(23.7)	(27.5)
Total long-term debt	2,564.6	2,569.6
AmeriGas Propane | Other
Debt Instrument
Long-term debt, gross	$ 9.5	14.6
AmeriGas Propane | Senior Notes | 5.50% due May 2025
Debt Instrument
Stated interest rate	5.50%
Long-term debt, gross	$ 700	700
AmeriGas Propane | Senior Notes | 5.875% due August 2026
Debt Instrument
Stated interest rate	5.875%
Long-term debt, gross	$ 675	675
AmeriGas Propane | Senior Notes | 5.625% due May 2024
Debt Instrument
Stated interest rate	5.625%
Long-term debt, gross	$ 675	675
AmeriGas Propane | Senior Notes | 5.75% due May 2027
Debt Instrument
Stated interest rate	5.75%
Long-term debt, gross	$ 525	525
AmeriGas Propane | Senior Secured Notes | Heritage Operating, L.P. Senior Secured Notes
Debt Instrument
Long-term debt, gross	3.8	7.5
UGI International
Debt Instrument
Unamortized debt issuance costs	(8.3)	(2.5)
Total long-term debt	$ 719.5	748.5
UGI International | Senior Notes | 3.25% Senior Notes due November 2025
Debt Instrument
Stated interest rate	3.25%
Long-term debt, gross	$ 381.5	0
UGI International | Term Loan | Variable-rate term loan
Debt Instrument
Long-term debt, gross	327	0
UGI France
Debt Instrument
Total long-term debt | €			€ 60
UGI France | Term Loan | UGI France Senior Facilities term loan
Debt Instrument
Long-term debt, gross	0	627
Flaga | Other | Other
Debt Instrument
Long-term debt, gross	19.3	20.9
Flaga | Term Loan | Flaga variable-rate term loan
Debt Instrument
Long-term debt, gross	0	53.2
Flaga | Term Loan | Flaga U.S. dollar variable-rate term loan
Debt Instrument
Long-term debt, gross	0	49.9		$ 59.1
Midstream & Marketing:
Debt Instrument
Unamortized debt issuance costs	(12)	0
Total long-term debt	686.6	0.4
Midstream & Marketing: | Other | Other
Debt Instrument
Long-term debt, gross	0.3	0.4
Midstream & Marketing: | Term Loan | Variable-rate term loan
Debt Instrument
Long-term debt, gross	698.3	0
UGI Utilities
Debt Instrument
Unamortized debt issuance costs	(4.6)	(4.1)
Total long-term debt	$ 979.2	838
UGI Utilities | Senior Notes | 4.12%, due September 2046
Debt Instrument
Stated interest rate	4.12%
Long-term debt, gross	$ 200	200
UGI Utilities | Senior Notes | 4.98%, due March 2044
Debt Instrument
Stated interest rate	4.98%
Long-term debt, gross	$ 175	175
UGI Utilities | Senior Notes | 4.55%, due February 2049
Debt Instrument
Stated interest rate	4.55%
Long-term debt, gross	$ 150	0
UGI Utilities | Senior Notes | 4.12%, due October 2046
Debt Instrument
Stated interest rate	4.12%
Long-term debt, gross	$ 100	100
UGI Utilities | Senior Notes | 6.21%, due September 2036
Debt Instrument
Stated interest rate	6.21%
Long-term debt, gross	$ 100	100
UGI Utilities | Senior Notes | 2.95%, due June 2026
Debt Instrument
Stated interest rate	2.95%
Long-term debt, gross	$ 100	100
UGI Utilities | Other | Other
Debt Instrument
Long-term debt, gross	4.7	6.8
UGI Utilities | Term Loan | Variable-rate term loan
Debt Instrument
Long-term debt, gross	$ 114.1	120.3
UGI Utilities | Medium-term Notes | 6.13%, due October 2034
Debt Instrument
Stated interest rate	6.13%
Long-term debt, gross	$ 20	20
UGI Utilities | Medium-term Notes | 6.50%, due August 2033
Debt Instrument
Stated interest rate	6.50%
Long-term debt, gross	$ 20	20
UGI Coporation
Debt Instrument
Unamortized debt issuance costs	(4)	0
Total long-term debt	846	0
UGI Coporation | Term Loan | 3-year Term loan
Debt Instrument
Long-term debt, gross	300	0
UGI Coporation | Term Loan | 5-year Term Loan
Debt Instrument
Long-term debt, gross	250	0
UGI Coporation | Line of Credit
Debt Instrument
Long-term debt, gross	300	0
Other
Debt Instrument
Total long-term debt	$ 8.1	$ 8.8

Debt - Schedule of Long-term_2

Debt - Schedule of Long-term Debt (Footnotes) (Details) - USD ($)	Sep. 30, 2019	Aug. 01, 2019	Sep. 30, 2018
AmeriGas Propane | Senior Secured Notes | HOLP Senior Secured Notes
Debt Instrument
Effective interest rate	6.75%		6.75%
UGI International | Term Loan | Variable-rate term loan
Debt Instrument
Effective interest rate	2.04%
UGI France | Term Loan | UGI France Senior Facilities term loan
Debt Instrument
Effective interest rate			1.93%
Flaga | Term Loan | Flaga variable-rate term loan
Debt Instrument
Effective interest rate			1.93%
Flaga | Term Loan | Flaga U.S. dollar variable-rate term loan
Debt Instrument
Effective interest rate			0.55%
Midstream & Marketing | Term Loan | Variable-rate term loan
Debt Instrument
Effective interest rate	5.79%
UGI Utilities | Term Loan | Variable-rate term loan
Debt Instrument
Effective interest rate	3.05%		2.76%
UGI Coporation | Term Loan | 3-year Term loan
Debt Instrument
Effective interest rate	4.30%
Aggregate principal amount		$ 300,000,000
UGI Coporation | Term Loan | 5-year Term Loan
Debt Instrument
Effective interest rate	4.55%
Aggregate principal amount		$ 250,000,000
UGI Coporation | Line of Credit
Debt Instrument
Effective interest rate	4.55%

Debt - Schedule of Principal R

Debt - Schedule of Principal Repayments of Long-term Debt (Details) $ in Millions	Sep. 30, 2019USD ($)
Debt Instrument
2020	$ 24
2021	19.7
2022	335.5
2023	146.1
2024	1,521.5
AmeriGas Propane
Debt Instrument
2020	7.8
2021	3.6
2022	1.6
2023	0.3
2024	675
UGI International
Debt Instrument
2020	0.1
2021	0.1
2022	19
2023	0.1
2024	327
Midstream & Marketing
Debt Instrument
2020	7.1
2021	7.1
2022	7.1
2023	7
2024	7
UGI Utilities
Debt Instrument
2020	8.4
2021	8
2022	6.9
2023	95.5
2024	0
UGI Corporation
Debt Instrument
2022	300
2023	37.5
2024	512.5
Other
Debt Instrument
2020	0.6
2021	0.9
2022	0.9
2023	$ 5.7

Debt - Schedule of Short-term

Debt - Schedule of Short-term Debt (Details)	Sep. 30, 2019USD ($)	Sep. 30, 2019EUR (€)	Aug. 13, 2019USD ($)	Aug. 12, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2018EUR (€)
AmeriGas OLP
Short-term Debt
Total Capacity	$ 600,000,000				$ 600,000,000
Borrowings Outstanding	328,000,000				232,000,000
Letters of Credit and Guarantees Outstanding	62,700,000				63,500,000
Available Borrowing Capacity	$ 209,300,000				$ 304,500,000
Weighted Average Interest Rate - End of Year	4.50%	4.50%			4.58%	4.58%
UGI International LLC
Short-term Debt
Total Capacity | €		€ 300,000,000				€ 300,000,000
Borrowings Outstanding	$ 210,000,000	192,700,000				0
Letters of Credit and Guarantees Outstanding | €		0				0
Available Borrowing Capacity | €		€ 107,300,000				300,000,000
Weighted Average Interest Rate - End of Year	3.64%	3.64%
UGI France
Short-term Debt
Total Capacity | €						60,000,000
Borrowings Outstanding | €						0
Letters of Credit and Guarantees Outstanding | €						0
Available Borrowing Capacity | €						60,000,000
Flaga
Short-term Debt
Total Capacity | €						55,000,000
Borrowings Outstanding | €						0
Letters of Credit and Guarantees Outstanding | €						500,000
Available Borrowing Capacity | €						€ 54,500,000
Energy Services
Short-term Debt
Total Capacity	$ 200,000,000		$ 200,000,000	$ 240,000,000	$ 240,000,000
Borrowings Outstanding	45,000,000				0
Letters of Credit and Guarantees Outstanding	0				0
Available Borrowing Capacity	$ 155,000,000				240,000,000
Weighted Average Interest Rate - End of Year	6.25%	6.25%
UGI Utilities
Short-term Debt
Total Capacity	$ 350,000,000				450,000,000
Borrowings Outstanding	166,000,000				189,500,000
Letters of Credit and Guarantees Outstanding	0				2,000,000
Available Borrowing Capacity	$ 184,000,000				$ 258,500,000
Weighted Average Interest Rate - End of Year	3.00%	3.00%			3.03%	3.03%
UGI Corporation
Short-term Debt
Total Capacity	$ 300,000,000
Borrowings Outstanding	300,000,000
Letters of Credit and Guarantees Outstanding	0
Available Borrowing Capacity	$ 0
Weighted Average Interest Rate - End of Year	4.55%	4.55%

Debt - Schedule of Short-ter_2

Debt - Schedule of Short-term Debt (Footnotes) (Details)	12 Months Ended
	Sep. 30, 2019USD ($)	Sep. 30, 2019EUR (€)	Aug. 13, 2019USD ($)	Aug. 12, 2019USD ($)	Jun. 27, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2018EUR (€)
Energy Services Credit Agreement | Minimum
Short-term Debt
Basis spread on variable rate (percentage)	0.75%
Energy Services Credit Agreement | Maximum
Short-term Debt
Basis spread on variable rate (percentage)	2.25%
Energy Services Credit Agreement | Federal Funds Effective Swap Rate
Short-term Debt
Basis spread on variable rate (percentage)	0.50%
Energy Services Credit Agreement | LIBOR
Short-term Debt
Basis spread on variable rate (percentage)	1.00%
UGI International LLC
Short-term Debt
Borrowing	$ 210,000,000	€ 192,700,000					€ 0
Total capacity | €		€ 300,000,000					€ 300,000,000
UGI Utilities
Short-term Debt
Borrowing	166,000,000					$ 189,500,000
Total capacity	$ 350,000,000					450,000,000
UGI Utilities | 2019 Credit Agreement | Line of Credit
Short-term Debt
Total capacity					$ 350,000,000
UGI Utilities | 2019 Credit Agreement | Minimum | Line of Credit
Short-term Debt
Basis spread on variable rate (percentage)	0.00%
UGI Utilities | 2019 Credit Agreement | Maximum | Line of Credit
Short-term Debt
Basis spread on variable rate (percentage)	1.75%
UGI Utilities | Letter of Credit | 2019 Credit Agreement | Line of Credit
Short-term Debt
Total capacity	$ 50,000,000				$ 100,000,000
Energy Services
Short-term Debt
Borrowing	45,000,000					0
Total capacity	$ 200,000,000		$ 200,000,000	$ 240,000,000		$ 240,000,000

Debt - Accounts Receivable Sec

Debt - Accounts Receivable Securitization Facility (Details) - Energy Services - Receivables Facility - Energy Services Receivables Facility - USD ($)	6 Months Ended
	Oct. 31, 2019	Apr. 30, 2019
Short-term Debt
Maximum borrowing capacity		$ 150,000,000
Subsequent Event
Short-term Debt
Maximum borrowing capacity	$ 75,000,000

Debt - Schedule of Receivables

Debt - Schedule of Receivables Facility (Details) - Energy Services - Receivables Facility - Energy Services Receivables Facility - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Short-term Debt
Trade receivables transferred to ESFC during the year	$ 1,372.7	$ 1,279.5	$ 1,017.3
ESFC trade receivables sold to the bank during the year	179	193	243
ESFC trade receivables - end of year	54.5	65	$ 44.8
Outstanding balance of trade receivables sold	$ 46.4	$ 2

Debt - Restrictive Covenants (

Debt - Restrictive Covenants (Details)	Sep. 30, 2019
UGI Utilities | 2019 Credit Agreement
Debt Instrument
Ratio of consolidated debt to consolidated total capital, maximum	0.65
Revolving Credit Facility | UGI International LLC | Line of Credit | UGI International Credit Agreement
Debt Instrument
Maximum ratio of Total Indebtedness to EBITDA	3.85
Term Loan | Energy Services | Line of Credit | Energy Services Credit Agreement
Debt Instrument
Maximum ratio of Total Indebtedness to EBITDA	3.50
Consolidated EBITDA to debt service, minimum	1.10
Minimum ratio of EBITDA to interest expense	3.50
Consolidated net indebtedness to consolidated EBITDA, during acquisition period, maximum	4
Term Loan | UGI Corporation | Line of Credit | The UGI Corporation Senior Credit Facility
Debt Instrument
Maximum ratio of Total Indebtedness to EBITDA	4.50
Consolidated net indebtedness to consolidated EBITDA, during acquisition period, maximum	4.875
EBITDA to consolidated interest expense ratio, maximum	3.50
Total indebtedness to EBITDA Ratio, final ratio, maximum	4
Consolidated net indebtedness to consolidated EBITDA, during acquisition period, final ratio, maximum	4.50

Debt - Restricted Net Assets (

Debt - Restricted Net Assets (Details) $ in Millions	Sep. 30, 2019USD ($)
Senior Notes | 4.98% Senior Notes, due March 2044
Debt Instrument
Amount of net assets restricted from transfer to parent company under different agreements	$ 2,100

Income Taxes - Income Before In

Income Taxes - Income Before Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Domestic	$ 329.4	$ 576	$ 527.3
Foreign	71.1	278.5	174.1
Income before income taxes	$ 400.5	$ 854.5	$ 701.4

Income Taxes - Provisions for I

Income Taxes - Provisions for Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Current expense (benefit):
Federal	$ 51.7	$ (2.7)	$ (2.7)
State	14	26	14
Foreign	69.6	77.6	56.2
Total current expense	135.3	100.9	67.5
Deferred expense (benefit):
Federal	2.9	(77.1)	125.8
State	3.5	6.7	16.4
Foreign	(48.8)	1.9	(31.8)
Investment tax credit amortization	(0.3)	(0.3)	(0.3)
Total deferred expense	(42.7)	(68.8)	110.1
Total income tax expense	$ 92.6	$ 32.1	$ 177.6

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	Aug. 21, 2019	Dec. 31, 2017	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Jun. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Foreign tax credits								$ 9.8	$ 13	$ 40.9
Income Tax Examination [Line Items]
Tax Cuts And Jobs Act Of 2017, incomplete accounting, change in tax rate, deferred tax liability, provisional income tax benefit, including unrecognized deferred tax liability									$ 384.4
Effective income tax rate reconciliation, at federal statutory income tax rate, percent								21.00%	24.50%	35.00%
Increase (decrease) in income tax liabilities									$ (52.1)
Tax Cuts And Jobs Act Of 2017, incomplete accounting, change in tax rate, provisional unrecognized deferred tax liability			$ 205.6						205.6
Increase (decrease) in regulatory liabilities, excess deferred income taxes									83.6
Tax Cuts And Jobs Act of 2017, transition tax for accumulated foreign earnings, provisional Income tax expense (benefit)								$ 3.8
Income tax expense (benefit), continuing operations, adjustment of deferred tax (asset) liability		$ (12.1)						2.4
Deferred tax assets relating to operating loss carryforwards			26.2					21.2	26.2
Increase (decrease) in valuation allowance								(26.1)	9.7
Unrecognized income tax benefits			11.5					10.9	11.5	$ 12.2	$ 7.2
Accrued interest included in unrecognized income tax benefits								1
Unrecognized tax benefits if recognized would impact the reported effective tax rate								10.9
Expected change in unrecognized tax benefits								2.8
Accrued Interest Included
Income Tax Examination [Line Items]
Unrecognized income tax benefits								10.9
Future Utilization of Foreign Tax Credits
Income Tax Examination [Line Items]
Increase (decrease) in valuation allowance								(24.8)	7.6
Foreign Operating Loss Carryforwards
Income Tax Examination [Line Items]
Increase (decrease) in valuation allowance								(1.3)	2.1
UGI Utilities
Income Tax Examination [Line Items]
PUC temporary rates order, reduction in revenue									24.1
Flaga
Income Tax Examination [Line Items]
Deferred tax assets relating to operating loss carryforwards								2
UGI France
Income Tax Examination [Line Items]
Deferred tax assets relating to operating loss carryforwards								6.8
UGI International
Income Tax Examination [Line Items]
Incentive distribution, distribution									12.8	47.6
Operating loss carryforwards								14.3
Deferred tax assets relating to operating loss carryforwards								3
Other Subsidiaries
Income Tax Examination [Line Items]
Deferred tax assets relating to operating loss carryforwards								9.4
Income Tax Benefits | UGI Utilities
Income Tax Examination [Line Items]
PUC temporary rates order, reduction in revenue							$ 17.1
Future Amortization Of Regulatory Liabilities | UGI Utilities
Income Tax Examination [Line Items]
PUC temporary rates order, reduction in revenue									7
Merger Sub
Income Tax Examination [Line Items]
Incentive distribution, distribution	$ 2,227.7
Cost for income tax purposes	2,030.3
Deferred tax asset, step up in tax basis of the underlying assets	$ 512.3							512.3
Foreign | Flaga
Income Tax Examination [Line Items]
Operating loss carryforwards								10
Foreign | UGI France
Income Tax Examination [Line Items]
Operating loss carryforwards								22
State
Income Tax Examination [Line Items]
Decrease in income tax expense due to state tax flow through of accelerated depreciation								7.4	4.2	$ 2.5
Operating loss carryforwards								$ 147.9
French Parliament
Income Tax Examination [Line Items]
Increase (decrease) in income tax liabilities			$ 1.4	$ 0.1	$ 3.7	$ (17.3)
French Parliament | Foreign
Income Tax Examination [Line Items]
Increase (decrease) in income tax liabilities									$ 0.6

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of U.S. Federal Statutory Tax Rate to Effective Tax Rate (Details)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
U.S. federal statutory tax rate	21.00%	24.50%	35.00%
Difference in tax rate due to:
Effect of tax rate changes - TJCA	0.002	(0.209)	0
Effect of tax rate changes - International	(0.50%)	(2.10%)	(4.10%)
Noncontrolling interests not subject to tax	(2.70%)	(3.00%)	(4.30%)
State income taxes, net of federal benefit	3.60%	2.90%	2.90%
Valuation allowance adjustments	0.00%	1.10%	(1.10%)
Effects of foreign operations	1.80%	3.10%	(1.10%)
Excess tax benefits on share-based payments	(1.00%)	(1.10%)	(1.30%)
Other, net	0.70%	(0.70%)	(0.70%)
Effective tax rate	23.10%	3.80%	25.30%

Income Taxes - Deferred Tax Lia

Income Taxes - Deferred Tax Liabilities (Assets) (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Excess book basis over tax basis of property, plant and equipment	$ 804.5	$ 807.8
Investment in AmeriGas Partners	0	219.2
Utility regulatory assets	107.6	86.7
Intangible assets and goodwill	70.5	67.6
Derivative instruments	0	30.4
Other	8.3	10.6
Gross deferred tax liabilities	990.9	1,222.3
Investment in AmeriGas Partners	(303.5)	0
Pension plan liabilities	(49.9)	(20)
Employee-related benefits	(43.8)	(43.6)
Operating loss carryforwards	(21.2)	(26.2)
Foreign tax credit carryforwards	(81.4)	(106.1)
Utility regulatory liabilities	(94.3)	(118.6)
Derivative instruments	(15.3)	0
Utility environmental liabilities	(15.3)	(14.7)
Other	(33.4)	(29)
Gross deferred tax assets	(658.1)	(358.2)
Deferred tax assets valuation allowance	90.7	116.8
Net deferred tax liabilities	$ 423.5	$ 980.9

Income Taxes - Reconciliation_2

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Reconciliation of Unrecognized Tax Benefits
Unrecognized tax benefits — beginning of year	$ 11.5	$ 12.2	$ 7.2
Additions for tax positions of the current year	0.9	1.5	1.9
Additions for tax positions taken in prior years	0.4	0.6	4.6
Settlements with tax authorities/statute lapses	(1.9)	(2.8)	(1.5)
Unrecognized tax benefits — end of year	$ 10.9	$ 11.5	$ 12.2

Employee Retirement Plans - Ch

Employee Retirement Plans - Change in Pension Benefits and Other Postretirement Benefits Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Pension Benefits
Change in benefit obligations:
Benefit obligations — beginning of year	$ 669.2	$ 697.8
Service cost	9.8	11.2	$ 11.9
Interest cost	27.3	26.3	25
Actuarial loss (gain)	89	(37)
Plan amendments	0.3	0
Curtailment	(1.3)	(0.6)
Settlements	(13.1)	0
Foreign currency	(3.1)	(1)
Benefits paid	(28)	(27.5)
Benefit obligations — end of year	750.1	669.2	697.8
Change in plan assets:
Fair value of plan assets — beginning of year	563.3	529.2
Actual gain on plan assets	13	44.9
Foreign currency	(1.5)	(0.6)
Employer contributions	12.4	16.2
Settlements	(13.1)	0
Benefits paid	(27.3)	(26.4)
Fair value of plan assets — end of year	546.8	563.3	529.2
Funded status of the plans — end of year	(203.3)	(105.9)
Assets (liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	0	0
Unfunded liabilities — included in other noncurrent liabilities	(203.3)	(105.9)
Net amount recognized	(203.3)	(105.9)
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
Prior service cost (benefit)	1.3	0.6
Net actuarial loss (gain)	25.4	14
Total	26.7	14.6
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (benefit)	0.5	0.7
Net actuarial loss (gain)	177.4	85.7
Total	177.9	86.4
Other Postretirement Benefits
Change in benefit obligations:
Benefit obligations — beginning of year	19.3	27
Service cost	0.2	0.5	1
Interest cost	0.7	0.8	0.8
Actuarial loss (gain)	3.6	(2.1)
Plan amendments	0	(5.8)
Curtailment	0	(0.1)
Settlements	0	0
Foreign currency	(0.2)	0
Benefits paid	(0.9)	(1)
Benefit obligations — end of year	22.7	19.3	27
Change in plan assets:
Fair value of plan assets — beginning of year	15.3	14.8
Actual gain on plan assets	0.9	0.9
Foreign currency	0	0
Employer contributions	0.4	0.4
Settlements	0	0
Benefits paid	(0.4)	(0.8)
Fair value of plan assets — end of year	16.2	15.3	$ 14.8
Funded status of the plans — end of year	(6.5)	(4)
Assets (liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	2.8	6.7
Unfunded liabilities — included in other noncurrent liabilities	(9.3)	(10.7)
Net amount recognized	(6.5)	(4)
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
Prior service cost (benefit)	(1.2)	(1.3)
Net actuarial loss (gain)	0.5	(0.4)
Total	(0.7)	(1.7)
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (benefit)	(0.7)	(1.2)
Net actuarial loss (gain)	1.4	(0.1)
Total	$ 0.7	$ (1.3)

Employee Retirement Plans - Na

Employee Retirement Plans - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan Disclosure
Amortization of prior service credits	$ 0.3
Pension Benefits
Defined Benefit Plan Disclosure
Expected amortization of net actuarial losses	15
ABO for the pension plans	658.5	$ 572.8
Contribution made to Pension Plan	12.4	16.2
Projected benefit obligations of unfunded and non qualified supplemental executive retirement plans	750.1	669.2	$ 697.8
Pre-tax cost to sponsor unfunded and non-qualified supplemental executive retirement plans	8.5	16	18.9
Net actuarial loss	25.4	14
Fair value of pension and other postretirement benefit contributions	0	0
Supplemental Employee Retirement Plans
Defined Benefit Plan Disclosure
Expected amortization of net actuarial losses	0.9
Projected benefit obligations of unfunded and non qualified supplemental executive retirement plans	52.9	48.3
Pre-tax cost to sponsor unfunded and non-qualified supplemental executive retirement plans	2.2	4.3	3.1
Settlement		2.1
Net actuarial loss	9.1	4.3
Fair value of pension and other postretirement benefit contributions	33.8	34.3
U.S. | Pension Benefits
Defined Benefit Plan Disclosure
Contribution made to Pension Plan	$ 11.5	$ 15.1	$ 11.4

Employee Retirement Plans - Ac

Employee Retirement Plans - Actuarial Assumptions for Domestic Plans (Details)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Pension Benefits
Weighted-average assumptions:
Discount rate – benefit obligations	3.30%	4.40%	4.00%
Discount rate – benefit cost	4.40%	4.00%	3.80%
Expected return on plan assets	7.30%	7.40%	7.50%
Rate of increase in salary levels	3.25%	3.25%	3.25%
Other Postretirement Benefits
Weighted-average assumptions:
Discount rate – benefit obligations	3.30%	4.40%	4.00%
Discount rate – benefit cost	4.40%	4.00%	3.80%
Expected return on plan assets	5.00%	5.00%	5.00%
Rate of increase in salary levels	3.25%	3.25%	3.25%

Employee Retirement Plans - Ne

Employee Retirement Plans - Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 9.8	$ 11.2	$ 11.9
Interest cost	27.3	26.3	25
Expected return on assets	(36.3)	(35)	(33.6)
Curtailment gain	(0.4)	(0.2)	(1.4)
Amortization of:
Prior service cost (benefit)	0.3	0.3	0.3
Actuarial loss (gain)	7.8	13.4	16.7
Net benefit cost (benefit)	8.5	16	18.9
Change in associated regulatory liabilities	0	0	0
Net benefit cost (benefit) after change in regulatory liabilities	8.5	16	18.9
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	0.2	0.5	1
Interest cost	0.7	0.8	0.8
Expected return on assets	(0.8)	(0.7)	(0.7)
Curtailment gain	0	0	0
Amortization of:
Prior service cost (benefit)	(0.5)	(6.3)	(0.6)
Actuarial loss (gain)	(0.1)	(0.1)	0.3
Net benefit cost (benefit)	(0.5)	(5.8)	0.8
Change in associated regulatory liabilities	(1.4)	(0.5)	(0.5)
Net benefit cost (benefit) after change in regulatory liabilities	$ (1.9)	$ (6.3)	$ 0.3

Employee Retirement Plans - Ex

Employee Retirement Plans - Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits (Details) $ in Millions	Sep. 30, 2019USD ($)
Pension Benefits
Defined Benefit Plan Disclosure
Fiscal 2020	$ 32.7
Fiscal 2021	31.7
Fiscal 2022	33
Fiscal 2023	35.6
Fiscal 2024	37.2
Fiscal 2025 - 2029	204.3
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Fiscal 2020	1
Fiscal 2021	1
Fiscal 2022	1
Fiscal 2023	0.9
Fiscal 2024	0.9
Fiscal 2025 - 2029	$ 4.9

Employee Retirement Plans - Pe

Employee Retirement Plans - Pension Plans (Details)	Sep. 30, 2019	Sep. 30, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans
Percentage of common stock represented pension plan assets	7.70%	8.50%
Pension Benefits | U.S.
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual	100.00%	100.00%
Target Asset Allocation	100.00%
Pension Benefits | U.S. | Total domestic equity investments
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual	54.80%	58.20%
Target Asset Allocation	52.50%
Pension Benefits | U.S. | Total domestic equity investments | Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	40.00%
Pension Benefits | U.S. | Total domestic equity investments | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	65.00%
Pension Benefits | U.S. | International index equity mutual funds
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual	11.80%	11.80%
Target Asset Allocation	12.50%
Pension Benefits | U.S. | International index equity mutual funds | Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	7.50%
Pension Benefits | U.S. | International index equity mutual funds | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	17.50%
Pension Benefits | U.S. | Equity investments
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual	66.60%	70.00%
Target Asset Allocation	65.00%
Pension Benefits | U.S. | Equity investments | Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	60.00%
Pension Benefits | U.S. | Equity investments | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	70.00%
Pension Benefits | U.S. | Fixed income funds & cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual	33.40%	30.00%
Target Asset Allocation	35.00%
Pension Benefits | U.S. | Fixed income funds & cash equivalents | Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	30.00%
Pension Benefits | U.S. | Fixed income funds & cash equivalents | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	40.00%
VEBA
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual	100.00%	100.00%
Target Asset Allocation	100.00%
VEBA | Total domestic equity investments
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual	64.90%	65.60%
Target Asset Allocation	65.00%
VEBA | Total domestic equity investments | Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	60.00%
VEBA | Total domestic equity investments | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	70.00%
VEBA | Equity investments | Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	30.00%
VEBA | Equity investments | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans
Target Asset Allocation	40.00%
VEBA | Fixed income funds & cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual	35.10%	34.40%
Target Asset Allocation	35.00%

Employee Retirement Plans - Fa

Employee Retirement Plans - Fair Value of U.S. Pension Plan and VEBA Trust Assets (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Pension Benefits
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 546.8	$ 563.3	$ 529.2
Pension Benefits | U.S.
Defined Benefit Plan Disclosure
Fair value of plan assets	529.1	531.7
Pension Benefits | U.S. | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	176.4	188.4
Pension Benefits | U.S. | Small and midcap equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	72.8	75.7
Pension Benefits | U.S. | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	40.9	45.2
Pension Benefits | U.S. | Total domestic equity investments
Defined Benefit Plan Disclosure
Fair value of plan assets	290.1	309.3
Pension Benefits | U.S. | International index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	62.1	62.9
Pension Benefits | U.S. | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	170.5	154.3
Pension Benefits | U.S. | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	6.4	5.2
Pension Benefits | U.S. | Fixed income funds & cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	176.9	159.5
Pension Benefits | U.S. | Level 1
Defined Benefit Plan Disclosure
Fair value of plan assets	522.7	526.5
Pension Benefits | U.S. | Level 1 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	176.4	188.4
Pension Benefits | U.S. | Level 1 | Small and midcap equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	72.8	75.7
Pension Benefits | U.S. | Level 1 | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	40.9	45.2
Pension Benefits | U.S. | Level 1 | Total domestic equity investments
Defined Benefit Plan Disclosure
Fair value of plan assets	290.1	309.3
Pension Benefits | U.S. | Level 1 | International index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	62.1	62.9
Pension Benefits | U.S. | Level 1 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	170.5	154.3
Pension Benefits | U.S. | Level 1 | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 1 | Fixed income funds & cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	170.5	154.3
Pension Benefits | U.S. | Level 2 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 2 | Small and midcap equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 2 | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 2 | Total domestic equity investments
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 2 | International index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 2 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 3
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 3 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 3 | Small and midcap equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 3 | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 3 | Total domestic equity investments
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 3 | International index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 3 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 3 | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Level 3 | Fixed income funds & cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Other
Defined Benefit Plan Disclosure
Fair value of plan assets	6.4	5.2
Pension Benefits | U.S. | Other | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Other | Small and midcap equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Other | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Other | Total domestic equity investments
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Other | International index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Other | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Pension Benefits | U.S. | Other | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	6.4	5.2
Pension Benefits | U.S. | Other | Fixed income funds & cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	6.4	5.2
VEBA
Defined Benefit Plan Disclosure
Fair value of plan assets	16.2	15.3
VEBA | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	10.5	10.1
VEBA | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	5.5	4.9
VEBA | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0.2	0.3
VEBA | Level 1
Defined Benefit Plan Disclosure
Fair value of plan assets	16	15
VEBA | Level 1 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	10.5	10.1
VEBA | Level 1 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	5.5	4.9
VEBA | Level 1 | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA | Level 2 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA | Level 2 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA | Level 3
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA | Level 3 | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA | Level 3 | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA | Level 3 | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA | Other
Defined Benefit Plan Disclosure
Fair value of plan assets	0.2	0.3
VEBA | Other | S&P 500 Index equity mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA | Other | Bond index mutual funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
VEBA | Other | Cash equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 0.2	$ 0.3

Employee Retirement Plans - De

Employee Retirement Plans - Defined Contribution Plans (Details) - Other Pension, Postretirement and Supplemental Plans - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Defined Contribution Plan Disclosure [Line Items]
Costs of benefits under savings plans	$ 19.3	$ 17.1	$ 15.1
Total fair values of grantor trust investment assets	$ 5.9	$ 6.5

Utility Regulatory Assets and_3

Utility Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Utilities (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018
Regulatory Assets [Line Items]
Regulatory assets	$ 3.7	$ 6.3
UGI Utilities
Regulatory Assets [Line Items]
Regulatory assets	395.6	301
Regulatory Liabilities [Line Items]
Regulatory liabilities	358.8	390.2
UGI Utilities | Postretirement benefit overcollections
Regulatory Liabilities [Line Items]
Regulatory liabilities	14.5	17.8
UGI Utilities | Deferred fuel and power refunds
Regulatory Liabilities [Line Items]
Regulatory liabilities	6.1	36.7
UGI Utilities | State income tax benefits — distribution system repairs
Regulatory Liabilities [Line Items]
Regulatory liabilities	25	22.6
UGI Utilities | PAPUC Temporary Rates Order
Regulatory Liabilities [Line Items]
Regulatory liabilities	31.3	24.4
UGI Utilities | Excess federal deferred income taxes
Regulatory Liabilities [Line Items]
Regulatory liabilities	279.5	285.2
UGI Utilities | Other
Regulatory Liabilities [Line Items]
Regulatory liabilities	2.4	3.5
UGI Utilities | Income taxes recoverable
Regulatory Assets [Line Items]
Regulatory assets	115.2	110.1
UGI Utilities | Underfunded pension and postretirement plans
Regulatory Assets [Line Items]
Regulatory assets	178.6	87.1
UGI Utilities | Environmental costs
Regulatory Assets [Line Items]
Regulatory assets	59.5	58.8
UGI Utilities | Removal costs, net
Regulatory Assets [Line Items]
Regulatory assets	28.3	32
UGI Utilities | Other
Regulatory Assets [Line Items]
Regulatory assets	$ 14	$ 13

Utility Regulatory Assets and_4

Utility Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) - USD ($) $ in Millions	Oct. 11, 2019	Jan. 28, 2019	Oct. 27, 2018	Oct. 25, 2018	May 17, 2018	Jan. 26, 2018	Jun. 30, 2017	Oct. 19, 2016	Jun. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Regulatory Assets [Line Items]
Regulatory asset, amortization period			20 years
UGI South
Regulatory Assets [Line Items]
PUC temporary rates order, percent of reduction in base rate revenues					4.71%
UGI North
Regulatory Assets [Line Items]
PUC temporary rates order, percent of reduction in base rate revenues					2.87%
UGI Central
Regulatory Assets [Line Items]
PUC temporary rates order, percent of reduction in base rate revenues					6.34%
Pennsylvania Public Utility Commission | UGI Gas
Regulatory Assets [Line Items]
Requested operating revenue increase		$ 71.1
Proposed negative surcharge		4.50%
Tax benefit to be returned									$ 24
Pennsylvania Public Utility Commission | Electric Utility
Regulatory Assets [Line Items]
Requested operating revenue increase				$ 3.2		$ 7.7
Requested annual base distribution revenue increase						$ 9.2
Tax Cuts and Jobs Act Of 2017, customer billing credit			$ 0.2
Pennsylvania Public Utility Commission | PNG
Regulatory Assets [Line Items]
Base distribution rate increase							$ 11.3
Postretirement benefit overcollections
Regulatory Assets [Line Items]
Regulatory liability, amortization period								10 years
Gas Utility
Regulatory Assets [Line Items]
Fair value of unrealized gains (losses)										$ (2.2)	$ 2.9
Minimum
Regulatory Assets [Line Items]
Average remaining depreciable lives of the associated property										1 year
Maximum
Regulatory Assets [Line Items]
Average remaining depreciable lives of the associated property										65 years
Maximum | Removal Costs, Net
Regulatory Assets [Line Items]
Regulatory asset, amortization period										5 years
Subsequent Event | Pennsylvania Public Utility Commission | UGI Gas
Regulatory Assets [Line Items]
Energy Efficiency and Conservation and Growth extension tariff, extension term	5 years
Base distribution rate increase	$ 30

Inventories - Schedule of Inve

Inventories - Schedule of Inventories (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018
Public Utilities, Inventory
Total inventories	$ 229.9	$ 318.2
Non-utility LPG and natural gas
Public Utilities, Inventory
Total inventories	150.2	231.7
Gas Utility natural gas
Public Utilities, Inventory
Total inventories	26.6	37.3
Materials, supplies and other
Public Utilities, Inventory
Total inventories	$ 53.1	$ 49.2

Inventories - Narrative (Detai

Inventories - Narrative (Details) - UGI Utilities $ in Millions	12 Months Ended
	Sep. 30, 2019storage_agreement	Sep. 30, 2018USD ($)Bcf
Public Utilities, Inventory
Number of storage agreements | storage_agreement	4
Storage agreement term (up to)	3 years
Volume of gas storage inventories released under SCAAs with non-affiliates (in cubic feet) | Bcf		2.3
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $		$ 5.4

Property, Plant and Equipment

Property, Plant and Equipment - (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018
Property, Plant and Equipment
Utility	$ 3,938.1	$ 3,616.3
Non-utility	6,134.9	5,345.8
Total property, plant and equipment	10,073	8,962.1
Distribution
Property, Plant and Equipment
Utility	3,366.2	3,106.6
Transmission
Property, Plant and Equipment
Utility	106	97.1
General and other
Property, Plant and Equipment
Utility	389.3	281.7
Work in process
Property, Plant and Equipment
Utility	76.6	130.9
Non-utility	101.7	57.9
Land
Property, Plant and Equipment
Non-utility	183.5	191.4
Buildings and improvements
Property, Plant and Equipment
Non-utility	403.8	364.9
Transportation equipment
Property, Plant and Equipment
Non-utility	258.3	257.1
Equipment, primarily cylinders and tanks
Property, Plant and Equipment
Non-utility	3,455.2	3,375.4
Electric generation
Property, Plant and Equipment
Non-utility	326.9	319.5
Pipeline and related assets
Property, Plant and Equipment
Non-utility	1,150.2	473
Other
Property, Plant and Equipment
Non-utility	$ 255.3	$ 306.6

Goodwill and Intangible Asset_2

Goodwill and Intangible Assets - Changes in the Carrying Amount of Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Goodwill
Balance at beginning of period	$ 3,160.4	$ 3,107.2
Acquisitions	355.5	59.4
Dispositions		(2.8)
Purchase accounting adjustments		13.6
Foreign currency translation	(59.5)	(17)
Balance at end of period	3,456.4	3,160.4
AmeriGas Propane
Goodwill
Balance at beginning of period	2,003	2,001.3
Acquisitions		4.5
Dispositions		(2.8)
Foreign currency translation	0	0
Balance at end of period	2,003	2,003
UGI International
Goodwill
Balance at beginning of period	963.7	912.2
Acquisitions	25.6	54.9
Dispositions		0
Purchase accounting adjustments		13.6
Foreign currency translation	(59.5)	(17)
Balance at end of period	929.8	963.7
Midstream & Marketing
Goodwill
Balance at beginning of period	11.6	11.6
Acquisitions	329.9	0
Dispositions		0
Purchase accounting adjustments		0
Foreign currency translation	0	0
Balance at end of period	341.5	11.6
UGI Utilities
Goodwill
Balance at beginning of period	182.1	182.1
Acquisitions	0	0
Dispositions		0
Purchase accounting adjustments		0
Foreign currency translation	0	0
Balance at end of period	$ 182.1	$ 182.1

Goodwill and Intangible Asset_3

Goodwill and Intangible Assets - Components of Intangible Assets (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018	Apr. 30, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Customer relationships	$ 1,038.4	$ 790.4
Trademarks and tradenames	16.2	7.9	$ 7.9
Noncompete agreements and other	46.4	58.2
Accumulated amortization	(441.8)	(393.2)
Intangible assets, net (definite-lived)	659.2	463.3
Trademarks and tradenames (indefinite-lived)	49.4	50.3
Total intangible assets, net	$ 708.6	$ 513.6

Goodwill and Intangible Asset_4

Goodwill and Intangible Assets - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Apr. 30, 2018	Jun. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Expected aggregate amortization expense of intangible assets for the next five fiscal years:
Amortization expense of intangible assets			$ 59.6	$ 58.6	$ 50.8
Fiscal 2020			64.6
Fiscal 2021			61.4
Fiscal 2022			58.3
Fiscal 2023			56.8
Fiscal 2024			55.6
Useful life				3 years
Trademarks and tradenames	$ 7.9		$ 16.2	$ 7.9
Trademarks and tradenames
Expected aggregate amortization expense of intangible assets for the next five fiscal years:
Useful life	3 years
Impairment charge		$ 75

Series Preferred Stock (Details

Series Preferred Stock (Details) - shares	Sep. 30, 2019	Sep. 30, 2018
Class of Stock [Line Items]
Preferred Stock, shares authorized (in shares)	10,000,000
Preferred Stock, shares outstanding (in shares)	0	0
UGI Utilities
Class of Stock [Line Items]
Preferred Stock, shares authorized (in shares)	2,000,000
Preferred Stock, shares outstanding (in shares)	0	0

Common Stock and Equity-Based_3

Common Stock and Equity-Based Compensation - Narrative (Details) $ / shares in Units, $ in Millions	Aug. 21, 2019USD ($)shares	Jan. 28, 2019	Sep. 30, 2018USD ($)shares	Sep. 30, 2019USD ($)$ / sharesshares	Sep. 30, 2018USD ($)$ / sharesshares	Sep. 30, 2017USD ($)$ / sharesshares	Jan. 25, 2018shares
Share-based Compensation Arrangement by Share-based Payment Award
Treasury stock acquired | $			$ 19.7	$ 15.9	$ 19.7
Pre-tax equity-based compensation expense | $				18.1	22.5	$ 19.3
After tax equity-based compensation expense | $				13.2	15.7	11.8
Cash received from stock option exercises | $				19.5	43.4	17.7
Associated tax benefits | $				5.1	$ 12.6	$ 9.6
Unrecognized compensation cost associated with unvested unit awards | $				$ 8.3
Weighted-average period of recognition for unvested unit awards				2 years
UGI Stock Option Awards
Share-based Compensation Arrangement by Share-based Payment Award
Weighted-average fair value of stock option granted under stock plans (in dollars per share) | $ / shares				$ 8.70	$ 7.51	$ 7.62
UGI Performance Units
Share-based Compensation Arrangement by Share-based Payment Award
Weighted-average fair value of stock option granted under stock plans (in dollars per share) | $ / shares				$ 55.40	$ 55.26	$ 50.91
Award performance period				3 years
Expected term of Performance Unit awards				3 years
Expected volatility measurement period (in years)				3 years
UGI Units awarded (in shares)				128,910	52,314,000,000	42,079,000,000
Weighted average grant date fair value unit awards (in dollars per share) | $ / shares				$ 55.40
UGI Performance Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				0.00%
UGI Performance Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
Cash Settled Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Pre-tax equity-based compensation expense | $				$ 2.4
Weighted-average period of recognition for unvested unit awards				1 year 3 months 18 days
UGI Unit awards outstanding (in shares)				212,896
Cost not yet recognized | $				$ 4.6
UGI Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Unrecognized compensation cost associated with unvested unit awards | $				$ 7.6
Weighted-average period of recognition for unvested unit awards				1 year 10 months 24 days
UGI Units awarded (in shares)				158,694	196,114	185,379
Weighted average grant date fair value unit awards (in dollars per share) | $ / shares				$ 55.40	$ 53.36	$ 50.08
UGI Unit awards outstanding (in shares)			959,718	893,820	959,718
Fair value of unit awards vested | $				$ 4.9	$ 7.3	$ 7.1
Liabilities associated with share based compensation | $			$ 18.8	$ 10.2	$ 18.8
Amerigas Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
UGI Unit awards outstanding (in shares)			236,762	0	236,762
Fair value of unit awards vested | $				$ 0.9	$ 2.2	$ 2.1
Liabilities associated with share based compensation | $			$ 2.3		$ 2.3
Conversion ratio	0.6378
Accrued distribution equivalent | $	$ 1.8
AmeriGas Performance Units
Share-based Compensation Arrangement by Share-based Payment Award
Expected term of Performance Unit awards				3 years
UGI Units awarded (in shares)				79,980
Weighted average grant date fair value unit awards (in dollars per share) | $ / shares				$ 30.23
Units converted to UGI cash-settled restricted units (in shares)	137,472
AmeriGas Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
UGI Units awarded (in shares)				53,118
Weighted average grant date fair value unit awards (in dollars per share) | $ / shares				$ 31.10
UGI Unit awards outstanding (in shares)	263,561
Units converted to UGI cash-settled restricted units (in shares)	126,089			263,561
Amerigas Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Vested units (in shares)			71,148
Total Unitholder Return at 25th Percentile | UGI Performance Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				25.00%
Total Unitholder Return at 40th Percentile | UGI Performance Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				70.00%
Total Unitholder Return at 50th Percentile | UGI Performance Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				100.00%
Total Unitholder Return at 90th Percentile | UGI Performance Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
2010 Propane Plan | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Total unitholder return ranking				70.00%
2010 Propane Plan | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Total unitholder return ranking				130.00%
2010 Propane Plan | UGI Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
UGI Unit awards outstanding (in shares)				1,420,949
2010 Propane Plan | Amerigas Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Award performance period				3 years
2010 Propane Plan | AmeriGas Performance Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				0.00%
2010 Propane Plan | AmeriGas Performance Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
2010 Propane Plan | AmeriGas Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Weighted-average fair value of stock option granted under stock plans (in dollars per share) | $ / shares				$ 30.58	$ 50.05	$ 52.37
UGI Units awarded (in shares)				133,098	84,811	67,563
2010 Propane Plan | Total Unitholder Return at 25th Percentile | AmeriGas Performance Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				0.00%
2010 Propane Plan | Total Unitholder Return at 90th Percentile | AmeriGas Performance Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
Common Stock
Share-based Compensation Arrangement by Share-based Payment Award
Maximum number of shares authorized for repurchase (in shares)							8,000,000,000,000
Duration of stock repurchase program		4 years
Treasury stock acquired | $			$ 59.8	$ 16.9	$ 59.8	$ 43.3
Common Stock | 2013 Omnibus Incentive Compensation Plan (OICP)
Share-based Compensation Arrangement by Share-based Payment Award
Expiration period				10 years
Common Stock awards granted (in shares)				21,750,000
Number of common unit awards available for future grant (in shares)				8,700,734,000,000
Common Stock | Treasury Stock
Share-based Compensation Arrangement by Share-based Payment Award
Treasury stock acquired (in shares)				300,000	1,200,000	900,000
AmeriGas Performance Units | Cash Settled Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Issuance in period due to conversion (in shares)	215,957

Common Stock and Equity-Based_4

Common Stock and Equity-Based Compensation - Common Stock Share Activity (Details) - Common Stock - shares	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Common Stock Share Activity
Beginning balance - shares Issued/Treasury (in shares)	209,304,129	174,142,997	173,987,691	173,894,141
Beginning balance - shares Outstanding (in shares)	173,748,975	173,143,737	172,960,449
Employee and director plans - shares Issued/Treasury (in shares)	548,285	155,306	93,550
Employee and director plans - shares Outstanding (in shares)	979,132	1,960,018	1,145,254
Sale of reacquired common stock - Outstanding (in shares)	15,759		50,000
AmeriGas Merger -Issued (in shares)	34,612,847
AmeriGas Merger - Outstanding (in shares)	34,612,847
Reacquired common stock, employee and director plans - Outstanding (in shares)	(51,924)	(154,780)	(111,966)
Ending balance - shares Issued/Treasury (in shares)	209,304,129	174,142,997	173,987,691	173,894,141
Ending balance - shares Outstanding (in shares)	209,004,789	173,748,975	173,143,737
Treasury
Common Stock Share Activity
Beginning balance - shares Issued/Treasury (in shares)	(299,340)	(394,022)	(843,954)	(933,692)
Employee and director plans - shares Issued/Treasury (in shares)	430,847	1,804,712	1,051,704
Sale of reacquired common stock - Treasury (in shares)	15,759		50,000
Repurchases of common stock - Treasury (in shares)	(300,000)	(1,200,000)	(900,000)
Reacquired common stock, employee and director plans - Treasury (in shares)	(51,924)	(154,780)	(111,966)
Ending balance - shares Issued/Treasury (in shares)	(299,340)	(394,022)	(843,954)	(933,692)

Common Stock and Equity-Based_5

Common Stock and Equity-Based Compensation - Stock Option Awards (Details) - UGI Stock Option Awards - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Shares
Shares under option - beginning balance (in shares)	8,197,069	8,781,748	8,488,451
Granted (in shares)	1,197,100	1,401,400	1,343,800
Canceled (in shares)	(123,012)	(152,017)	(60,236)
Expired (in shares)	(13,699)	(1,666)
Exercised (in shares)	(779,353)	(1,832,396)	(990,267)
Shares under option - ending balance (in shares)	8,478,105	8,197,069	8,781,748	8,488,451
Weighted - Average Option Price
Shares under option - beginning balance (in dollars per share)	$ 33.93	$ 30.20	$ 26.68
Granted (in dollars per share)	53.27	47.85	46.51
Canceled (in dollars per share)	48.69	42.14	41.86
Exercised (in dollars per share)	25.75	26	21.40
Expired (in dollars per share)	47.49	35.80
Shares under option - ending balance (in dollars per share)	$ 37.18	$ 33.93	$ 30.20	$ 26.68
Total Intrinsic Value
Shares under option - beginning balance	$ 176.6	$ 146.7	$ 157.6
Exercised	22.8	44.5	26.7
Shares under option - beginning balance	$ 114.9	$ 176.6	$ 146.7	$ 157.6
Weighted - Average Contract Term (Years)
Weighted - Average Contract Term (Years)	5 years 10 months 24 days	6 years 2 months 12 days	6 years 3 months 18 days	6 years 7 months 6 days
Options Exercisable
Options exercisable (in shares)	5,963,530	5,498,330	5,973,668
Option exercisable (in dollars per share)	$ 32.02	$ 28.63	$ 25.53
Total Intrinsic Value	$ 109.3
Weighted - Average Contract Term (Years)	4 years 10 months 24 days
Options Not Exercisable
Options not exercisable (in shares)	2,514,575
Options not exercisable (in dollars per share)	$ 49.43
Total Intrinsic Value	$ 5.6
Weighted - Average Contract Term (Years)	7 years 4 months 24 days

Common Stock and Equity-Based_6

Common Stock and Equity-Based Compensation - Additional Information Relating to Stock Options Outstanding and Exercisable (Details) - UGI Stock Option Awards	12 Months Ended
	Sep. 30, 2019$ / sharesshares
Under $30.00
Share-based Compensation Arrangement by Share-based Payment Award
Range of exercise prices, lower limit (in dollars per share)	$ 0
Range of exercise prices, upper limit (in dollars per share)	$ 30
Number of options (in shares) | shares	2,879,501
Weighted average remaining contractual life (in years)	3 years 1 month 6 days
Weighted average exercise price (in dollars per share)	$ 23.24
Number of options (in shares) | shares	2,879,501
Weighted average exercise price (in dollars per share)	$ 23.24
$30.00 – $35.00
Share-based Compensation Arrangement by Share-based Payment Award
Range of exercise prices, lower limit (in dollars per share)	30
Range of exercise prices, upper limit (in dollars per share)	$ 35
Number of options (in shares) | shares	1,094,763
Weighted average remaining contractual life (in years)	6 years 1 month 6 days
Weighted average exercise price (in dollars per share)	$ 33.66
Number of options (in shares) | shares	995,313
Weighted average exercise price (in dollars per share)	$ 33.65
$35.01 – $40.00
Share-based Compensation Arrangement by Share-based Payment Award
Range of exercise prices, lower limit (in dollars per share)	35.01
Range of exercise prices, upper limit (in dollars per share)	$ 40
Number of options (in shares) | shares	870,115
Weighted average remaining contractual life (in years)	5 years 3 months 18 days
Weighted average exercise price (in dollars per share)	$ 37.81
Number of options (in shares) | shares	870,115
Weighted average exercise price (in dollars per share)	$ 37.81
$40.01 – $45.00
Share-based Compensation Arrangement by Share-based Payment Award
Range of exercise prices, lower limit (in dollars per share)	40.01
Range of exercise prices, upper limit (in dollars per share)	$ 40
Number of options (in shares) | shares	81,593
Weighted average remaining contractual life (in years)	7 years 1 month 6 days
Weighted average exercise price (in dollars per share)	$ 44.42
Number of options (in shares) | shares	76,593
Weighted average exercise price (in dollars per share)	$ 44.48
Over $45.00
Share-based Compensation Arrangement by Share-based Payment Award
Range of exercise prices, lower limit (in dollars per share)	$ 40
Number of options (in shares) | shares	3,552,133
Weighted average remaining contractual life (in years)	8 years 3 months 18 days
Weighted average exercise price (in dollars per share)	$ 49.25
Number of options (in shares) | shares	1,142,008
Weighted average exercise price (in dollars per share)	$ 47.48

Common Stock and Equity-Based_7

Common Stock and Equity-Based Compensation - Assumptions Used for Valuing Option Grants (Details) - UGI Stock Option Awards	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
Expected life of option	6 years	6 years	5 years 9 months
Weighted average volatility	17.20%	17.50%	19.80%
Weighted average dividend yield	1.80%	2.10%	2.10%
Expected volatility	17.20%	17.50%	19.80%
Expected dividend yield	1.80%	2.10%	2.10%
Minimum
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
Risk-free rate	1.50%	2.20%	1.80%
Maximum
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
Risk-free rate	2.60%	2.90%	2.10%

Common Stock and Equity-Based_8

Common Stock and Equity-Based Compensation - Weighted Average Assumptions Used to Determine the Fair Value of UGI Performance Unit Awards and Related Compensation Costs (Details) - UGI Performance Units	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award
Risk-free rate	2.50%	2.00%	1.50%
Expected life	3 years	3 years	3 years
Expected volatility	17.70%	18.90%	18.90%
Dividend yield	1.90%	2.10%	2.10%

Common Stock and Equity-Based_9

Common Stock and Equity-Based Compensation - UGI Performance Unit Award Activity (Details) - $ / shares	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
UGI Performance Units and Stock Units
UGI Units
Number of units - beginning balance (in shares)			959,718
Granted (in shares)			158,694	196,114	185,379
Number of units - ending balance (in shares)	893,820	959,718	893,820	959,718
Weighted-Average Grant-Date Fair Value (per Unit)
Weighted average grant date fair value - beginning balance (in dollars per share)			$ 32.38
Granted (in dollars per share)			55.40	$ 53.36	$ 50.08
Weighted average grant date fair value - ending balance (in dollars per share)	$ 36.39	$ 32.38	$ 36.39	$ 32.38
UGI Performance Units
UGI Units
Granted (in shares)			128,910	52,314,000,000	42,079,000,000
Forfeited (in shares)			(13,102)
Awards paid (in shares)			(144,521)
Weighted-Average Grant-Date Fair Value (per Unit)
Granted (in dollars per share)			$ 55.40
Forfeited (in dollars per share)			53.29
Awards paid (in dollars per share)			$ 34.62
UGI Stock Units
UGI Units
Granted (in shares)			29,784
Forfeited (in shares)			(4,900)
Awards paid (in shares)			(62,069)
Weighted-Average Grant-Date Fair Value (per Unit)
Granted (in dollars per share)			$ 55.39
Forfeited (in dollars per share)			51.22
Awards paid (in dollars per share)			$ 25.12
Shares granted under stock awards (percentage)			70.00%
UGI Restricted Stock Units
Weighted-Average Grant-Date Fair Value (per Unit)
Vested units (in shares)	616,319	660,795

Common Stock and Equity-Base_10

Common Stock and Equity-Based Compensation - Schedule of Payment for UGI Performance Unit and UGI Stock Unit Awards in Shares and Cash (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
UGI Performance Units
Share-based Compensation Arrangement by Share-based Payment Award
Number of original awards granted (in shares)	144,521	136,621	178,450
Performance period beginning January 1:	2016	2015	2014
Payment of awards:
Shares of UGI Common Stock issued, net of shares withheld for taxes	116,950	69,680	138,985
Cash paid	$ 9.9	$ 1.6	$ 10.9
UGI Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Number of original awards granted (in shares)	50,985	39,680	43,699
Payment of awards:
Shares of UGI Common Stock issued, net of shares withheld for taxes	43,479	29,095	15,990
Cash paid	$ 1	$ 0.6	$ 0.3

Common Stock and Equity-Base_11

Common Stock and Equity-Based Compensation - Weighted Average Assumption Used to Determine the Fair Value of AmeriGas Performance Unit Awards and Related Compensation Costs (Details) - AmeriGas Performance Units	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award
Risk-free rate	2.50%	2.00%	1.50%
Expected life	3 years	3 years	3 years
Expected volatility	22.40%	21.10%	21.70%
Dividend yield	12.50%	8.20%	7.80%

Common Stock and Equity-Base_12

Common Stock and Equity-Based Compensation - AmeriGas Common Unit Based Award Activity (Details) - $ / shares	Aug. 21, 2019	Sep. 30, 2018	Sep. 30, 2019
Amerigas Performance Units and Stock Units
AmeriGas Partners Common Units
Number of units - beginning balance (in shares)			236,762
Number of units - ending balance (in shares)		236,762	0
Weighted-Average Grant-Date Fair Value (per Unit)
Weighted average grant date fair value - beginning balance (in dollars per share)			$ 47.12
Weighted average grant date fair value - ending balance (in dollars per share)		$ 47.12	$ 0
AmeriGas Performance Units
AmeriGas Partners Common Units
Granted (in shares)			79,980
Forfeited (in shares)			(42,916)
Awards paid (in shares)			(17,133)
Performance criteria not met (in share)			(29,394)
Units converted to UGI cash-settled restricted units (in shares)	(137,472)
Weighted-Average Grant-Date Fair Value (per Unit)
Granted (in dollars per share)			$ 30.23
Forfeited (in dollars per share)			46.83
Awards paid (in dollars per share)			43.02
Performance criteria not met (in dollars per share)			$ 34.27
AmeriGas Stock Units
AmeriGas Partners Common Units
Granted (in shares)			53,118
Forfeited (in shares)			(800)
Awards paid (in shares)			(16,056)
Units converted to UGI cash-settled restricted units (in shares)	(126,089)		(263,561)
Number of units - ending balance (in shares)	263,561
Weighted-Average Grant-Date Fair Value (per Unit)
Granted (in dollars per share)			$ 31.10
Forfeited (in dollars per share)			45.30
Awards paid (in dollars per share)			40.98
Units converted to UGI cash-settled restricted units (in dollars per share)			$ (40.89)
Weighted average grant date fair value - ending balance (in dollars per share)	$ 40.89
Amerigas Restricted Stock Units
Weighted-Average Grant-Date Fair Value (per Unit)
Vested units (in shares)		71,148

Common Stock and Equity-Base_13

Common Stock and Equity-Based Compensation - AmeriGas Common Unit Based Awards in Common Units and Cash (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
AmeriGas Performance Unit awards
Share-based Compensation Arrangement by Share-based Payment Award
Number of Common Units subject to original awards granted (in shares)	52,495	65,525	53,800
Performance period beginning January 1:	2016	2015	2014
Payment of awards:
AmeriGas Partners Common Units issued, net of units withheld for taxes (in shares)	10,902	13,164	29,489
Cash paid	$ 0.8	$ 1.2	$ 2.9
AmeriGas Stock Unit awards
Share-based Compensation Arrangement by Share-based Payment Award
Number of Common Units subject to original awards granted (in shares)	20,585	14,811	32,658
Payment of awards:
AmeriGas Partners Common Units issued, net of units withheld for taxes (in shares)	9,706	5,322	3,932
Cash paid	$ 0.2	$ 0.1	$ 0.1

Partnership Distributions (Deta

Partnership Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Distribution Made to Limited Partner
Partnership distributions to partners (days following quarter end)	45 days
Percentage of limited partnership interest (as a percent)	98.00%
General Partner held a general partner interest (as a percent)	2.00%
Quarterly distribution (in dollars per share)	$ 0.55
First target distribution (in dollars per share)	0.055
Available cash for per common unit (more than) (in dollars per share)	0.605	$ 0.605	$ 0.605
Threshold for increased distribution to General Partner (in dollars per share)	$ 0.605
Pre-Incentive distribution of available cash to General Partners	2.00%	2.00%	2.00%
General Partners distribution based on ownership interest	$ 54.9	$ 54.9	$ 52.7
Incentive distributions received by the General Partner	$ 45.7	$ 45.3	$ 43.5
AmeriGas Partners
Distribution Made to Limited Partner
General Partner held a general partner interest (as a percent)	1.00%
AmeriGas OLP
Distribution Made to Limited Partner
General Partner held a general partner interest (as a percent)	1.01%

Commitments and Contingencies

Commitments and Contingencies - Minimum Future Payments Under Operating Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Aggregate rental expense for leases	$ 115.1	$ 106.2	$ 99.5
Operating Leased Assets [Line Items]
2020	100.4
2021	85.9
2022	71
2023	61.7
2024	53.6
After 2024	139.2
AmeriGas Propane
Operating Leased Assets [Line Items]
2020	82.1
2021	71.6
2022	60
2023	52.3
2024	45
After 2024	94.8
UGI Utilities
Operating Leased Assets [Line Items]
2020	1.2
2021	0.5
2022	0.4
2023	0.3
2024	0.3
After 2024	0
UGI International
Operating Leased Assets [Line Items]
2020	12.9
2021	10
2022	7
2023	5.7
2024	5.1
After 2024	6.5
Other
Operating Leased Assets [Line Items]
2020	4.2
2021	3.8
2022	3.6
2023	3.4
2024	3.2
After 2024	$ 37.9

Commitments and Contingencies_2

Commitments and Contingencies - Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017record_of_decision	Dec. 31, 2008lb	Dec. 31, 2007lb	Sep. 30, 2019USD ($)subsidiary	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)
Loss Contingencies [Line Items]
Environmental expenditures cap during year				$ 5.4
Amount of propane in cylinders being sold | lb			17
Reduced amount of propane in cylinders being sold | lb		15
CPG, PNG and UGI Gas COAs
Loss Contingencies [Line Items]
Accrued liabilities for environmental investigation and remediation costs related to CPG-COA and PNG-COA				$ 50.4	$ 51
UGI Utilities | CPG and PNG
Loss Contingencies [Line Items]
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 [Line Items]
Accrued liabilities for environmental investigation and remediation costs related to CPG-COA and PNG-COA						$ 7.5
Number of records of decisions drafted | record_of_decision	3
Estimated remediation plan cost						$ 27.7

Fair Value Measurements - Fina

Fair Value Measurements - Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 101.1	$ 232.5
Derivative financial instruments, liabilities	(191.6)	(58.8)
Recurring Basis
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-qualified supplemental postretirement grantor trust investments	39.7	40.8
Recurring Basis | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-qualified supplemental postretirement grantor trust investments	39.7	40.8
Recurring Basis | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-qualified supplemental postretirement grantor trust investments	0	0
Recurring Basis | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-qualified supplemental postretirement grantor trust investments	0	0
Recurring Basis | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	42.1	211
Derivative financial instruments, liabilities	(175)	(43.4)
Recurring Basis | Commodity contracts | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	32	93.5
Derivative financial instruments, liabilities	(62.3)	(33.6)
Recurring Basis | Commodity contracts | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	10.1	117.5
Derivative financial instruments, liabilities	(112.7)	(9.8)
Recurring Basis | Commodity contracts | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0	0
Derivative financial instruments, liabilities	0	0
Recurring Basis | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	59	20.6
Derivative financial instruments, liabilities	(4.3)	(14.4)
Recurring Basis | Foreign currency contracts | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0	0
Derivative financial instruments, liabilities	0	0
Recurring Basis | Foreign currency contracts | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	59	20.6
Derivative financial instruments, liabilities	(4.3)	(14.4)
Recurring Basis | Foreign currency contracts | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	0	0
Derivative financial instruments, liabilities	0	0
Recurring Basis | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities	(12.3)	(1)
Recurring Basis | Interest rate contracts | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities	0	0
Recurring Basis | Interest rate contracts | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities	(12.3)	(1)
Recurring Basis | Interest rate contracts | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities	$ 0	0
Recurring Basis | Cross-currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		0.9
Recurring Basis | Cross-currency contracts | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		0
Recurring Basis | Cross-currency contracts | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		0.9
Recurring Basis | Cross-currency contracts | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		$ 0

Fair Value Measurements - Narr

Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2018	Sep. 30, 2018	Sep. 30, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Useful life		3 years
Trademarks and tradenames	$ 7.9	$ 7.9	$ 16.2
Trademarks and tradenames
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Useful life	3 years

Fair Value Measurements - Long

Fair Value Measurements - Long-term Debt (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018
Carrying amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 5,856.6	$ 4,199.4
Estimated fair value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 6,189.3	$ 4,150.3

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Narrative (Details) € in Millions	Sep. 30, 2019USD ($)	Sep. 30, 2019EUR (€)	Oct. 25, 2018	Sep. 30, 2018USD ($)	Sep. 30, 2018EUR (€)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)
Derivative
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months	$ 3,500,000
Cash collateral pledged	29,300,000			$ 0
Cash collateral received	0			12,200,000
Restricted cash	63,700,000			9,600,000		$ 10,300,000	$ 15,600,000
IRPA
Derivative
Notional amount	$ 0			0
Foreign Exchange Forward
Derivative
Potential exposure coverage, percent	90.00%	90.00%
Foreign currency contracts
Derivative
Notional amount	$ 516,000,000			$ 512,200,000
Foreign currency contracts | Net Investment Hedging
Derivative
Notional amount	$ 0	€ 172.8			€ 0
Senior Notes | UGI International LLC | 3.25% Senior Unsecured Notes Due November 2025
Derivative
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	Sep. 30, 2019USD ($)DTHkWhgal	Sep. 30, 2019EUR (€)DTHkWhgal	Sep. 30, 2018USD ($)DTHkWhgal	Sep. 30, 2018EUR (€)DTHkWhgal
Commodity contracts | Propane
Derivative
Notional amount (in units) | gal	800.4	800.4	394.3	394.3
Commodity contracts | Electricity | Long
Derivative
Notional amount (in units) | kWh	3,098.1	3,098.1	4,307.6	4,307.6
Commodity contracts | Electricity | Short
Derivative
Notional amount (in units) | kWh	366.7	366.7	359.3	359.3
Natural gas futures, forward and pipeline contracts | Natural Gas
Derivative
Notional amount (in units)	196.1	196.1	159.7	159.7
Natural gas basis swap contracts | Natural Gas
Derivative
Notional amount (in units)	131.1	131.1	54.4	54.4
NYMEX natural gas storage futures contracts | Natural Gas
Derivative
Notional amount (in units)	0.3	0.3	1.8	1.8
NYMEX natural gas option contracts | Natural Gas
Derivative
Notional amount (in units)	2.4	2.4	0	0
NYMEX propane storage futures contracts | Propane
Derivative
Notional amount (in units) | gal	0.5	0.5	0.6	0.6
Interest rate swaps
Derivative
Notional amount	$ 1,357.3	€ 300	$ 114.1	€ 585.8
Forward foreign exchange contracts
Derivative
Notional amount | $	516		512.2
Cross-currency swaps
Derivative
Notional amount | $	$ 0		$ 49.9
Regulated Utility Operations | Commodity contracts | Natural Gas
Derivative
Notional amount (in units)	23.3	23.3	23.2	23.2
Net Investment Hedging | Forward foreign exchange contracts
Derivative
Notional amount	$ 0	€ 172.8		€ 0

Derivative Instruments and He_5

Derivative Instruments and Hedging Activities - Schedule of Derivative Assets, Liabilities and the Effects of Offsetting (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018
Derivative assets:
Total derivative assets – gross	$ 101.1	$ 232.5
Gross amounts offset in the balance sheet	(29)	(34.3)
Cash collateral received	0	(12.2)
Total derivative assets – net	72.1	186
Derivative liabilities:
Total derivative liabilities – gross	(191.6)	(58.8)
Gross amounts offset in the balance sheet	29	34.3
Cash collateral pledged	29.3	0
Total derivative liabilities – net	(133.3)	(24.5)
Commodity contract - subject to PGC and DS mechanisms
Derivative assets:
Total derivative assets – gross	1.4	3
Derivative liabilities:
Total derivative liabilities – gross	(3.7)	(0.1)
Derivatives designated as hedging instruments
Derivative assets:
Total derivative assets – gross	17.4	2.4
Derivative liabilities:
Total derivative liabilities – gross	(12.3)	(1.4)
Derivatives designated as hedging instruments | Foreign currency contracts
Derivative assets:
Total derivative assets – gross	17.4	1.5
Derivative liabilities:
Total derivative liabilities – gross	0	(0.4)
Derivatives designated as hedging instruments | Cross-currency swaps
Derivative assets:
Total derivative assets – gross	0	0.9
Derivatives designated as hedging instruments | Interest rate contracts
Derivative liabilities:
Total derivative liabilities – gross	(12.3)	(1)
Derivatives not designated as hedging instruments
Derivative assets:
Total derivative assets – gross	82.3	227.1
Derivative liabilities:
Total derivative liabilities – gross	(175.6)	(57.3)
Derivatives not designated as hedging instruments | Foreign currency contracts
Derivative assets:
Total derivative assets – gross	41.6	19.1
Derivative liabilities:
Total derivative liabilities – gross	(4.3)	(14)
Derivatives not designated as hedging instruments | Commodity contracts
Derivative assets:
Total derivative assets – gross	40.7	208
Derivative liabilities:
Total derivative liabilities – gross	$ (171.3)	$ (43.3)

Derivative Instruments and He_6

Derivative Instruments and Hedging Activities - Effects of Derivative Instruments on Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Derivatives Not Designated as Hedging Instruments:
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	$ (299.5)	$ 166.6	$ 140.4
Derivatives Not Designated as Hedging Instruments: | Foreign currency contracts | Other non-operating income (expense), net
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	37.7	16.2	(23.8)
Derivatives Not Designated as Hedging Instruments: | Commodity contracts | Cost of sales
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(344.1)	155.4	166
Derivatives Not Designated as Hedging Instruments: | Commodity contracts | Revenues
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	7.2	(5.3)	(2)
Derivatives Not Designated as Hedging Instruments: | Commodity contracts | Operating and administrative expenses
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(0.3)	0.3	0.2
Cash Flow Hedges:
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	(10.5)	1.8	2.2
Gain (Loss) Reclassified from AOCI into Income	(2.4)	(6.9)	13.8
Cash Flow Hedges: | Foreign currency contracts
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	1.2	0.4	0.2
Cash Flow Hedges: | Foreign currency contracts | Cost of sales
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	2.4	(3)	17.8
Cash Flow Hedges: | Cross-currency swaps
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	(0.1)	1.2	0.5
Cash Flow Hedges: | Cross-currency swaps | Interest expense /other operating income, net
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	(0.3)	1.1	(0.1)
Cash Flow Hedges: | Interest rate contracts
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	(11.6)	0.2	1.5
Cash Flow Hedges: | Interest rate contracts | Interest expense
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	(4.5)	(5)	(3.9)
Net Investment Hedges: | Foreign currency contracts
Derivative Instruments, Gain (Loss)
Foreign currency contracts	$ 17.4	$ 0	$ 0

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
AOCI Including Portion Attributable to NCI [Roll Forward]:
Balance, beginning of year	$ 4,100	$ 3,740.9
Other comprehensive income (loss) before reclassification adjustments (after-tax)	(102.5)	(19.1)	$ 67.6
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	4.1	3.6	(8.3)
Reclassification adjustments tax expense (benefit)	(1.2)	(1.5)	2
Reclassification adjustments (after-tax)	2.9	2.1	(6.3)
Other comprehensive income (loss) attributable to UGI	(99.6)	(17)	61.3
Balance, end of year	3,827.2	4,100	3,740.9
Postretirement Benefit Plans
AOCI Including Portion Attributable to NCI [Roll Forward]:
Balance, beginning of year	(11)	(19.2)	(29.1)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	(13)	10.4	6.5
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	1.7	(3.3)	5.5
Reclassification adjustments tax expense (benefit)	(0.5)	1.1	(2.1)
Reclassification adjustments (after-tax)	1.2	(2.2)	3.4
Other comprehensive income (loss) attributable to UGI	(11.8)	8.2	9.9
Reclassification of stranded income tax effects related to TCJA	(2.9)
Balance, end of year	(25.7)	(11)	(19.2)
Derivative Instruments
AOCI Including Portion Attributable to NCI [Roll Forward]:
Balance, beginning of year	(16.1)	(21.4)	(13.4)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	(7.3)	1	1.7
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	2.4	6.9	(13.8)
Reclassification adjustments tax expense (benefit)	(0.7)	(2.6)	4.1
Reclassification adjustments (after-tax)	1.7	4.3	(9.7)
Other comprehensive income (loss) attributable to UGI	(5.6)	5.3	(8)
Reclassification of stranded income tax effects related to TCJA	(3.7)
Balance, end of year	(25.4)	(16.1)	(21.4)
Foreign Currency
AOCI Including Portion Attributable to NCI [Roll Forward]:
Balance, beginning of year	(83.3)	(52.8)	(112.2)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	(82.2)	(30.5)	59.4
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	0	0	0
Reclassification adjustments tax expense (benefit)	0	0	0
Reclassification adjustments (after-tax)	0	0	0
Other comprehensive income (loss) attributable to UGI	(82.2)	(30.5)	59.4
Reclassification of stranded income tax effects related to TCJA	0
Balance, end of year	(165.5)	(83.3)	(52.8)
Accumulated other comprehensive income (loss)
AOCI Including Portion Attributable to NCI [Roll Forward]:
Balance, beginning of year	(110.4)	(93.4)	(154.7)
Amounts reclassified from AOCI:
Reclassification of stranded income tax effects related to TCJA	(6.6)	0	0
Balance, end of year	$ (216.6)	$ (110.4)	$ (93.4)

Other Operating Income, Net (De

Other Operating Income, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Component of Operating Income [Abstract]
Finance charges	$ 16.5	$ 16.4	$ 11.8
AFUDC associated with pipeline projects	0	0	5.5
Interest and interest-related income	5.6	3.2	1.7
Utility non-tariff service income	0.7	2.8	1.5
Loss on private equity partnership investment	(1.5)	0	(11)
Gains (losses) on sales of fixed assets, net	2.9	5.3	(3.9)
Other, net	6.9	3.6	4.9
Total other operating income, net	$ 31.1	$ 31.3	$ 10.5

Quarterly Data (unaudited) (Det

Quarterly Data (unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	Aug. 21, 2019	Aug. 01, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Quarterly Financial Data [Abstract]
Revenues			$ 1,150.4	$ 1,363.7	$ 2,606.1	$ 2,200.2	$ 1,273.1	$ 1,440.9	$ 2,812	$ 2,125.2	$ 7,320.4	$ 7,651.2	$ 6,120.7
Operating income (loss)			(99)	9.6	538.8	167.7	49.2	29.5	591	395	617.1	1,064.7	1,010
Net income (loss) including noncontrolling interests			(130.8)	(46.5)	396.7	88.5	(7.8)	(11.7)	407.7	434.2	307.9	822.4	523.8
Net income (loss) attributable to UGI Corporation			$ (51.5)	$ (1.9)	$ 245.4	$ 64.2	$ 24.4	$ 52.4	$ 276	$ 365.9	$ 256.2	$ 718.7	$ 436.6
Earnings (loss) per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)			$ (0.27)	$ (0.01)	$ 1.41	$ 0.37	$ 0.14	$ 0.30	$ 1.59	$ 2.11	$ 1.44	$ 4.13	$ 2.51
Diluted (in dollars per share)			$ (0.27)	$ (0.01)	$ 1.38	$ 0.36	$ 0.14	$ 0.30	$ 1.57	$ 2.07	$ 1.41	$ 4.06	$ 2.46
Weighted-average common shares outstanding (thousands):
Basic (in shares)			189,905,000	174,759,000	174,501,000	174,413,000	174,391,000	173,991,000	173,570,000	173,670,000	178,417,000	173,908,000	173,662,000
Diluted (in shares)			189,905,000	174,759,000	177,318,000	177,566,000	177,506,000	176,807,000	176,350,000	176,948,000	181,111,000	176,905,000	177,159,000
Effect of Fourth Quarter Events [Line Items]
Loss on extinguishments of debt						$ 4.2					$ 6.1	$ 0	$ 59.7
Tax Cuts And Jobs Act Of 2017, increase (decrease) in net income							$ (5.8)	$ 0.8	$ 5.3	$ 166
2017 French Finance Bills which increased (decreased) net income												52.1
Impairment of intangible assets, finite-lived											$ 0	$ 75	$ 0
Trademarks and tradenames
Effect of Fourth Quarter Events [Line Items]
Impairment of intangible assets, finite-lived								14.5
French Parliament
Effect of Fourth Quarter Events [Line Items]
2017 French Finance Bills which increased (decreased) net income							$ (1.4)	$ (0.1)	$ (3.7)	$ 17.3
Common Stock | Merger Sub
Effect of Fourth Quarter Events [Line Items]
Consideration paid (in shares)	34,612,847	34,612,847									34,613,000

Segment Information - Narrativ

Segment Information - Narrative (Details) $ in Millions	3 Months Ended								12 Months Ended
	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Sep. 30, 2019USD ($)countystatesegment	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)
Segment Reporting [Abstract]
Number of reportable segments | segment									4
Number of states to which product sale with propane revenue | state									50
Segment Reporting Information
Operating income (loss) | $	$ (99)	$ 9.6	$ 538.8	$ 167.7	$ 49.2	$ 29.5	$ 591	$ 395	$ 617.1	$ 1,064.7	$ 1,010
Number of counties									1
UGI Utilities
Segment Reporting Information
Number of counties									2
France | Geographic Concentration Risk | Revenues
Segment Reporting Information
Concentration risk, percentage									20.00%
France | Geographic Concentration Risk | Long-lived Assets
Segment Reporting Information
Concentration risk, percentage									10.00%

Segment Information - Schedule

Segment Information - Schedule of Segment Reporting (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information
Revenues	$ 1,150.4	$ 1,363.7	$ 2,606.1	$ 2,200.2	$ 1,273.1	$ 1,440.9	$ 2,812	$ 2,125.2	$ 7,320.4	$ 7,651.2	$ 6,120.7
Cost of sales									4,323.1	4,074.9	2,837.3
Operating income (loss)	(99)	9.6	538.8	167.7	49.2	29.5	591	395	617.1	1,064.7	1,010
Income from equity investees									9.1	4.3	4.3
Loss on extinguishments of debt				(4.2)					(6.1)	0	(59.7)
Other non-operating income (expense), net									38.2	15.6	(29.7)
Earnings (losses) before interest expense and income taxes									658.3	1,084.6	924.9
Interest expense									(257.8)	(230.1)	(223.5)
Income tax (expense) benefit									(92.6)	(32.1)	(177.6)
Noncontrolling interests’ net (income) loss									(51.7)	(103.7)	(87.2)
Net income attributable to UGI	(51.5)	$ (1.9)	$ 245.4	$ 64.2	24.4	$ 52.4	$ 276	$ 365.9	256.2	718.7	436.6
Depreciation and amortization									448.1	455.1	416.3
Total assets	13,346.6				11,980.9				13,346.6	11,980.9	11,582.2
Short-term borrowings	796.3				424.9				796.3	424.9	366.9
Capital expenditures (including the effects of accruals)									707.6	597	624.3
Investments in equity investees	189.6				87.6				189.6	87.6	59.1
Goodwill	3,456.4				3,160.4				3,456.4	3,160.4	3,107.2
AmeriGas Propane
Segment Reporting Information
Goodwill	2,003				2,003				2,003	2,003	2,001.3
UGI International
Segment Reporting Information
Goodwill	929.8				963.7				929.8	963.7	912.2
Midstream & Marketing
Segment Reporting Information
Goodwill	341.5				11.6				341.5	11.6	11.6
Eliminations
Segment Reporting Information
Revenues									(305.4)	(370.8)	(222.7)
Cost of sales									(301.7)	(366.6)	(218.3)
Operating income (loss)									0.5	0.3	0.3
Income from equity investees									0	0	0
Loss on extinguishments of debt									0		0
Other non-operating income (expense), net									0	0	0
Earnings (losses) before interest expense and income taxes									0.5	0.3	0.3
Interest expense									0	0	0
Income tax (expense) benefit									(0.2)	(1.4)	(0.2)
Noncontrolling interests’ net (income) loss									0	0	0
Net income attributable to UGI									0.3	(1.1)	0.1
Depreciation and amortization									(0.2)	(0.3)	(0.2)
Total assets	(352.8)				(125.3)				(352.8)	(125.3)	(51.5)
Short-term borrowings	0				0				0	0	0
Capital expenditures (including the effects of accruals)									0	0	0
Investments in equity investees	0				0				0	0	0
Goodwill	0				0				0	0	0
Eliminations | AmeriGas Propane
Segment Reporting Information
Revenues									0	0	0
Eliminations | UGI International
Segment Reporting Information
Revenues									0	0	0
Eliminations | Midstream & Marketing
Segment Reporting Information
Revenues									234.6	272.6	178.2
Eliminations | UGI Utilities
Segment Reporting Information
Revenues									67.9	93.9	40.1
Operating Segments | AmeriGas Propane
Segment Reporting Information
Revenues									2,682	2,823	2,453.5
Cost of sales									1,191.3	1,314.7	1,002.9
Operating income (loss)									404	422.2	355.3
Income from equity investees									0	0	0
Loss on extinguishments of debt									0		0
Other non-operating income (expense), net									0	0	0
Earnings (losses) before interest expense and income taxes									404	422.2	355.3
Interest expense									(167.4)	(163.1)	(160.2)
Income tax (expense) benefit									(25.7)	(30.5)	(32.5)
Noncontrolling interests’ net (income) loss									(142.7)	(152.3)	(108.4)
Net income attributable to UGI									68.2	76.3	54.2
Depreciation and amortization									179.4	185.8	190.5
Total assets	4,095.3				3,933.9				4,095.3	3,933.9	4,069.4
Short-term borrowings	328				232				328	232	140
Capital expenditures (including the effects of accruals)									107.3	101.3	98.1
Investments in equity investees	0				0				0	0	0
Goodwill	2,003				2,003				2,003	2,003	2,001.3
Operating Segments | UGI International
Segment Reporting Information
Revenues									2,372.2	2,683.8	1,877.5
Cost of sales									1,416.4	1,620.1	935.3
Operating income (loss)									228.9	247.9	234.3
Income from equity investees									0	(0.5)	0
Loss on extinguishments of debt									0		0
Other non-operating income (expense), net									5.4	(7)	1.2
Earnings (losses) before interest expense and income taxes									234.3	240.4	235.5
Interest expense									(25)	(21.1)	(20.6)
Income tax (expense) benefit									(64.6)	(69.2)	(58.9)
Noncontrolling interests’ net (income) loss									0.1	3	(0.2)
Net income attributable to UGI									144.8	153.1	155.8
Depreciation and amortization									123.8	140.6	117.4
Total assets	2,975.2				3,279				2,975.2	3,279	3,132
Short-term borrowings	210.9				1.4				210.9	1.4	17.9
Capital expenditures (including the effects of accruals)									106.4	111.4	90.3
Investments in equity investees	11.6				12.8				11.6	12.8	8.1
Goodwill	929.8				963.7				929.8	963.7	912.2
Operating Segments | Midstream & Marketing
Segment Reporting Information
Revenues									1,515.7
Revenues from external customers									1,281.1	1,149.1	943
Cost of sales									1,241.2	1,090.8	856.7
Operating income (loss)									105	175.1	139.4
Income from equity investees									9.1	4.8	4.3
Loss on extinguishments of debt									0		0
Other non-operating income (expense), net									0	(1.2)	(0.2)
Earnings (losses) before interest expense and income taxes									114.1	178.7	143.5
Interest expense									(9)	(2.4)	(2.1)
Income tax (expense) benefit									(27.1)	(49.6)	(54.5)
Noncontrolling interests’ net (income) loss									0	0	0
Net income attributable to UGI									78	126.7	86.9
Depreciation and amortization									51.4	43.5	35.4
Total assets	2,744.5				1,328.9				2,744.5	1,328.9	1,165.5
Short-term borrowings	91.4				2				91.4	2	39
Capital expenditures (including the effects of accruals)									137.7	43.1	117.5
Investments in equity investees	178				74.8				178	74.8	51
Goodwill	341.5				11.6				341.5	11.6	11.6
Operating Segments | UGI Utilities
Segment Reporting Information
Revenues									1,048.6
Revenues from external customers									980.7	998.5	847.5
Cost of sales									481.3	522.9	367.3
Operating income (loss)									224.2	239.9	232.7
Income from equity investees									0	0	0
Loss on extinguishments of debt									0		0
Other non-operating income (expense), net									1.5	(2.4)	(4.4)
Earnings (losses) before interest expense and income taxes									225.7	237.5	228.3
Interest expense									(49.6)	(42.9)	(40.2)
Income tax (expense) benefit									(42.9)	(53.7)	(72.1)
Noncontrolling interests’ net (income) loss									0	0	0
Net income attributable to UGI									133.2	140.9	116
Depreciation and amortization									92.8	84.6	72.3
Total assets	3,559.5				3,266.6				3,559.5	3,266.6	2,994
Short-term borrowings	166				189.5				166	189.5	170
Capital expenditures (including the effects of accruals)									355.3	338.5	317.7
Investments in equity investees	0				0				0	0	0
Goodwill	182.1				182.1				182.1	182.1	182.1
Corporate & Other
Segment Reporting Information
Revenues									7.3
Revenues from external customers									4.4	(3.2)	(0.8)
Cost of sales									294.6	(107)	(106.6)
Operating income (loss)									(345.5)	(20.7)	48
Income from equity investees									0	0	0
Loss on extinguishments of debt									(6.1)		(59.7)
Other non-operating income (expense), net									31.3	26.2	(26.3)
Earnings (losses) before interest expense and income taxes									(320.3)	5.5	(38)
Interest expense									(6.8)	(0.6)	(0.4)
Income tax (expense) benefit									67.9	172.3	40.6
Noncontrolling interests’ net (income) loss									90.9	45.6	21.4
Net income attributable to UGI									(168.3)	222.8	23.6
Depreciation and amortization									0.9	0.9	0.9
Total assets	324.9				297.8				324.9	297.8	272.8
Short-term borrowings	0				0				0	0	0
Capital expenditures (including the effects of accruals)									0.9	2.7	0.7
Investments in equity investees	0				0				0	0	0
Goodwill	$ 0				$ 0				0	0	0
Corporate & Other | AmeriGas Propane
Segment Reporting Information
Loss on extinguishments of debt									0		(59.7)
Corporate & Other | UGI International
Segment Reporting Information
Loss on extinguishments of debt									(6.1)		0
Corporate & Other | Midstream & Marketing
Segment Reporting Information
Loss on extinguishments of debt									0		0
Corporate, Intersegment Eliminations & Other
Segment Reporting Information
Revenues									2.9	$ 4.3	$ 4.4
Scenario, Adjustment | AmeriGas Propane
Segment Reporting Information
Operating income (loss)									(112.9)
Scenario, Adjustment | UGI International
Segment Reporting Information
Operating income (loss)									(4)			$ (29)
Scenario, Adjustment | Midstream & Marketing
Segment Reporting Information
Operating income (loss)									(70.1)
Scenario, Adjustment | UGI Utilities
Segment Reporting Information
Operating income (loss)									$ (8)

Segment Information - Corporat

Segment Information - Corporate and Other segment information (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2018	Jun. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting Information
Loss on extinguishments of debt	$ (4.2)		$ (6.1)	$ 0	$ (59.7)
Impairment of Partnership tradenames and trademarks			0	(75)	0
Corporate & Other
Segment Reporting Information
Loss on extinguishments of debt			(6.1)		(59.7)
Corporate & Other | AmeriGas Propane
Segment Reporting Information
Loss on extinguishments of debt			0		(59.7)
Acquisition costs				0	0
LPG business transformation costs			(14.5)
Corporate & Other | UGI International
Segment Reporting Information
Loss on extinguishments of debt			(6.1)		0
Acquisition costs				(30.5)	(39.9)
LPG business transformation costs			(9.3)
Corporate & Other | Midstream & Marketing
Segment Reporting Information
Loss on extinguishments of debt			0		0
Acquisition costs				0	0
LPG business transformation costs			0
Commodity contracts | Corporate & Other | AmeriGas Propane
Segment Reporting Information
Net income (loss) on derivative instruments			(116.8)	12.5	31.1
Commodity contracts | Corporate & Other | UGI International
Segment Reporting Information
Net income (loss) on derivative instruments			(142.5)	92.9	19
Commodity contracts | Corporate & Other | Midstream & Marketing
Segment Reporting Information
Net income (loss) on derivative instruments			(31)	(1.5)	55.7
Foreign currency contracts | Corporate & Other | AmeriGas Propane
Segment Reporting Information
Net income (loss) on derivative instruments			0	0	0
Foreign currency contracts | Corporate & Other | UGI International
Segment Reporting Information
Net income (loss) on derivative instruments			32.2	28.9	(23.8)
Foreign currency contracts | Corporate & Other | Midstream & Marketing
Segment Reporting Information
Net income (loss) on derivative instruments			0	0	$ 0
Merger Sub | Corporate & Other | AmeriGas Propane
Segment Reporting Information
Acquisition costs			(6.3)
Merger Sub | Corporate & Other | UGI International
Segment Reporting Information
Acquisition costs			0
Merger Sub | Corporate & Other | Midstream & Marketing
Segment Reporting Information
Acquisition costs			0
Trademarks and tradenames
Segment Reporting Information
Impairment of Partnership tradenames and trademarks		$ (14.5)
Trademarks and tradenames | Corporate & Other | AmeriGas Propane
Segment Reporting Information
Impairment of Partnership tradenames and trademarks				(75)
Trademarks and tradenames | Corporate & Other | UGI International
Segment Reporting Information
Impairment of Partnership tradenames and trademarks				0
Trademarks and tradenames | Corporate & Other | Midstream & Marketing
Segment Reporting Information
Impairment of Partnership tradenames and trademarks				$ 0
Affiliated Entity | CMG | Pennant | Corporate & Other | AmeriGas Propane
Segment Reporting Information
Acquisition costs			0
Affiliated Entity | CMG | Pennant | Corporate & Other | UGI International
Segment Reporting Information
Acquisition costs			0
Affiliated Entity | CMG | Pennant | Corporate & Other | Midstream & Marketing
Segment Reporting Information
Acquisition costs			$ (15.6)

Global LPG Business Transform_2

Global LPG Business Transformation Initiatives (Details) $ in Millions	12 Months Ended
	Sep. 30, 2019USD ($)
Restructuring and Related Activities [Abstract]
Costs principally comprising consulting, advisory and employee-related costs	$ 23.8

SCHEDULE I _ CONDENSED FINANC_2

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY) - BALANCE SHEETS (Details) - USD ($) $ in Millions	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Current assets
Cash and cash equivalents	$ 447.1	$ 452.6	$ 558.4	$ 502.8
Prepaid expenses and other current assets	60	61.6
Total current assets	1,566.2	1,888.1
Property, plant and equipment, net	6,687.8	5,808.2
Other assets	497.9	273.6
Total assets	13,346.6	11,980.9	$ 11,582.2
Current liabilities
Total current liabilities	2,026.9	1,732.1
Long-term debt	5,779.9	4,146.5
Total liabilities	9,519.4	7,880.9
Commitments and contingencies (Note 1)
Common stockholders’ equity:
Common Stock, without par value (authorized – 450,000,000 shares; issued – 209,304,129 and 174,142,997 shares, respectively)	1,396.9	1,200.8
Retained earnings	2,653.1	2,610.7
Accumulated other comprehensive loss	(216.6)	(110.4)
Treasury stock, at cost	(15.9)	(19.7)
Total UGI Corporation stockholders’ equity	3,817.5	3,681.4
Total liabilities and equity	$ 13,346.6	$ 11,980.9
Condensed Financial Information of Registrant [Abstract]
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	209,304,129	174,142,997
Parent Company
Current assets
Cash and cash equivalents	$ 53.7	$ 13.4
Accounts receivable – related parties	5.4	12.8
Prepaid expenses and other current assets	22.8	10.5
Total current assets	81.9	36.7
Property, plant and equipment, net	3	2.6
Investments in subsidiaries	4,585.1	3,652
Other assets	77.4	71.9
Total assets	4,747.4	3,763.2
Current liabilities
Accounts and notes payable	15.4	14.9
Accrued liabilities	9.1	6.7
Total current liabilities	24.5	21.6
Long-term debt	846	0
Other noncurrent liabilities	59.4	60.2
Total liabilities	929.9	81.8
Commitments and contingencies (Note 1)
Common stockholders’ equity:
Common Stock, without par value (authorized – 450,000,000 shares; issued – 209,304,129 and 174,142,997 shares, respectively)	1,396.9	1,200.8
Retained earnings	2,653.1	2,610.7
Accumulated other comprehensive loss	(216.6)	(110.4)
Treasury stock, at cost	(15.9)	(19.7)
Total UGI Corporation stockholders’ equity	3,817.5	3,681.4
Total liabilities and equity	$ 4,747.4	$ 3,763.2
Condensed Financial Information of Registrant [Abstract]
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	209,304,129	174,142,997

SCHEDULE I _ CONDENSED FINANC_3

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY) - Narrative (Details)	12 Months Ended
	Sep. 30, 2019USD ($)
Guarantee Obligations
Debt repayment in year 2022	$ 335,500,000
Debt repayment in year 2023	146,100,000
Debt repayment in year 2024	1,521,500,000
Parent Company
Guarantee Obligations
Surety bonds indemnified	84,400,000
Maximum amount authorized to guarantee obligations to suppliers and customers (up to)	475,000,000
Current carrying value	378,400,000
Debt repayment in year 2022	300,000,000
Debt repayment in year 2023	37,500,000
Debt repayment in year 2024	$ 512,500,000

SCHEDULE I _ CONDENSED FINANC_4

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY) - STATEMENTS OF INCOME (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended								12 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Condensed Financial Statements, Captions
Revenues	$ 1,150.4	$ 1,363.7	$ 2,606.1	$ 2,200.2	$ 1,273.1	$ 1,440.9	$ 2,812	$ 2,125.2	$ 7,320.4	$ 7,651.2	$ 6,120.7
Costs and expenses:
Operating and administrative expenses									1,963.2	2,012.8	1,867.6
Other operating income, net									(31.1)	(31.3)	(10.5)
Total costs and expenses									6,703.3	6,586.5	5,110.7
Operating income	(99)	9.6	538.8	167.7	49.2	29.5	591	395	617.1	1,064.7	1,010
Pension and other postretirement plans non-service expense									0.5	(0.6)	(5.8)
Interest expense									(257.8)	(230.1)	(223.5)
Income tax (benefit) expense									92.6	32.1	177.6
Equity in income of unconsolidated subsidiaries									9.1	4.3	4.3
Net income attributable to UGI Corporation	$ (51.5)	$ (1.9)	$ 245.4	$ 64.2	$ 24.4	$ 52.4	$ 276	$ 365.9	256.2	718.7	436.6
Comprehensive income attributable to UGI Corporation									$ 156.6	$ 701.7	$ 497.9
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)	$ (0.27)	$ (0.01)	$ 1.41	$ 0.37	$ 0.14	$ 0.30	$ 1.59	$ 2.11	$ 1.44	$ 4.13	$ 2.51
Diluted (in dollars per share)	$ (0.27)	$ (0.01)	$ 1.38	$ 0.36	$ 0.14	$ 0.30	$ 1.57	$ 2.07	$ 1.41	$ 4.06	$ 2.46
Weighted - average common shares outstanding (thousands):
Basic (in shares)	189,905	174,759	174,501	174,413	174,391	173,991	173,570	173,670	178,417	173,908	173,662
Diluted (in shares)	189,905	174,759	177,318	177,566	177,506	176,807	176,350	176,948	181,111	176,905	177,159
Parent Company
Condensed Financial Statements, Captions
Revenues									$ 0	$ 0	$ 0
Costs and expenses:
Operating and administrative expenses									50	63.4	44.5
Other operating income, net									(49.7)	(52.2)	(45.9)
Total costs and expenses									0.3	11.2	(1.4)
Operating income									(0.3)	(11.2)	1.4
Pension and other postretirement plans non-service expense									(0.9)	(1.3)	(1.8)
Interest expense									(6.4)
Intercompany interest income									0.3	0.1	0
Loss before income taxes									(7.3)	(12.4)	(0.4)
Income tax (benefit) expense									(2.8)	6.1	(5.7)
(Loss) income before equity in income of unconsolidated subsidiaries									(4.5)	(18.5)	5.3
Equity in income of unconsolidated subsidiaries									260.7	737.2	431.3
Net income attributable to UGI Corporation									256.2	718.7	436.6
Other comprehensive (loss) income									(3.3)	3.4	1.3
Equity in other comprehensive (loss) income of unconsolidated subsidiaries									(96.3)	(20.4)	60
Comprehensive income attributable to UGI Corporation									$ 156.6	$ 701.7	$ 497.9
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)									$ 1.44	$ 4.13	$ 2.51
Diluted (in dollars per share)									$ 1.41	$ 4.06	$ 2.46
Weighted - average common shares outstanding (thousands):
Basic (in shares)									178,417	173,908	173,662
Diluted (in shares)									181,111	176,905	177,159

SCHEDULE I _ CONDENSED FINANC_5

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT (PARENT COMPANY) - STATEMENTS OF CASH FLOWS (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Condensed Financial Statements, Captions
NET CASH PROVIDED BY OPERATING ACTIVITIES	$ 1,078.1	$ 1,085.3	$ 964.4
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(704.6)	(574.4)	(638.9)
Net cash used by investing activities	(2,055.3)	(748.6)	(768.7)
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of dividends on Common Stock	(199.5)	(176.9)	(168.9)
Issuances of debt, net of issuance costs	2,411.7	124.4	1,307.1
Issuances of Common Stock	16.8	34.9	11
Repurchases of UGI Common Stock	(16.9)	(59.8)	(43.3)
Other	(11.5)	(5.2)	(0.8)
Net cash provided (used) by financing activities	1,042.2	(438.2)	(146.6)
Cash, cash equivalents and restricted cash increase (decrease)	48.6	(106.5)	50.3
Cash and cash equivalents:
Cash, cash equivalents and restricted cash at end of period	510.8	462.2	568.7
Cash, cash equivalents and restricted cash at beginning of period	462.2	568.7	518.4
Cash and cash equivalents increase (decrease)	48.6	(106.5)	50.3
Parent Company
Condensed Financial Statements, Captions
NET CASH PROVIDED BY OPERATING ACTIVITIES	169.8	208.2	253.2
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	0	(2.3)	(0.4)
Net investments in unconsolidated subsidiaries	(768.1)	(6.5)	(40.7)
Net cash used by investing activities	(768.1)	(8.8)	(41.1)
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of dividends on Common Stock	(199.5)	(176.9)	(168.9)
Issuances of debt, net of issuance costs	845.9	0	0
Issuances of Common Stock	16.8	34.9	11
Repurchases of UGI Common Stock	(16.9)	(59.8)	(43.3)
Other	(7.7)	0	0.1
Net cash provided (used) by financing activities	638.6	(201.8)	(201.1)
Cash, cash equivalents and restricted cash increase (decrease)	40.3	(2.4)	11
Cash and cash equivalents:
Cash, cash equivalents and restricted cash at end of period	53.7	13.4	15.8
Cash, cash equivalents and restricted cash at beginning of period	13.4	15.8	4.8
Cash and cash equivalents increase (decrease)	40.3	(2.4)	11
Dividends from unconsolidated subsidiaries	$ 162.5	$ 190.5	$ 241.9

SCHEDULE II _ VALUATION AND Q_2

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Allowance for doubtful accounts
Valuation and Qualifying Account
Balance at beginning of year	$ 35.1	$ 26.9	$ 27.3
Charged (credited) to costs and expenses	28.6	35.6	30.7
Other	(32.1)	(27.4)	(31.1)
Balance at end of year	31.6	35.1	26.9
Deferred tax assets valuation allowance
Valuation and Qualifying Account
Balance at beginning of year	116.8	107.1	114.3
Charged (credited) to costs and expenses	(26.1)	9.7	(7.6)
Other	0	0	0.4
Balance at end of year	$ 90.7	$ 116.8	$ 107.1

Uncategorized Items - ugi-93020

Label	Element	Value
Accounting Standards Update 2016-09 [Member] | Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 4,900,000
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 0