UGI (UGI) 10-Q 3 Feb 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Dec. 31, 2016	Jan. 31, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	UGI CORP /PA/
Entity Central Index Key	884,614
Document Type	10-Q
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--09-30
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		172,931,104

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 515.2	$ 502.8	$ 403
Restricted cash	7.9	15.6	55.5
Accounts receivable (less allowances for doubtful accounts of $29.2, $27.3 and $30.6, respectively)	917.3	551.6	803.1
Accrued utility revenues	55.6	12.8	30.8
Inventories	228.2	210.3	246.8
Utility regulatory assets	1.6	3.2	3.9
Derivative instruments	87	30.9	29.1
Prepaid expenses and other current assets	97.1	96.6	101.8
Total current assets	1,909.9	1,423.8	1,674
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $3,139.8, $3,107.3 and $2,896.9, respectively)	5,244.3	5,238	5,012.9
Goodwill	2,935.8	2,989	2,965.1	[1]
Intangible assets, net	558.9	580.3	602.4
Utility regulatory assets	391.3	391.9	297.9
Derivative instruments	24.2	6.5	13.7
Other assets	236.1	217.7	183.7
Total assets	11,300.5	10,847.2	10,749.7	[1]
Current liabilities:
Current maturities of long-term debt	48.5	29.5	186.8
Short-term borrowings	234.4	291.7	456.8	[1]
Accounts payable	573.6	391.2	423.3
Derivative instruments	16.2	48.5	123.1
Other current liabilities	702.2	681.1	721.6
Total current liabilities	1,574.9	1,442	1,911.6
Long-term debt	3,994.2	3,766	3,391.8
Deferred income taxes	1,204.7	1,216.2	1,140.4
Deferred investment tax credits	3.2	3.3	3.5
Derivative instruments	16.6	21.9	33.6
Other noncurrent liabilities	773.8	796	676.3
Total liabilities	7,567.4	7,245.4	7,157.2
Commitments and contingencies (Note 9)
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized — 450,000,000 shares; issued — 173,903,191, 173,894,141 and 173,825,741 shares, respectively)	1,203.4	1,201.6	1,215.7
Retained earnings	2,035.4	1,840.9	1,712.3
Accumulated other comprehensive loss	(216.8)	(154.7)	(142.9)
Treasury stock, at cost	(34.3)	(36.9)	(65.7)
Total UGI Corporation stockholders’ equity	2,987.7	2,850.9	2,719.4
Noncontrolling interests, principally in AmeriGas Partners	745.4	750.9	873.1
Total equity	3,733.1	3,601.8	3,592.5
Total liabilities and equity	$ 11,300.5	$ 10,847.2	$ 10,749.7
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI International and Midstream & Marketing reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2).

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Accounts receivable, allowances for doubtful accounts	$ 29.2	$ 27.3	$ 30.6
Property, plant and equipment, accumulated depreciation and amortization	$ 3,139.8	$ 3,107.3	$ 2,896.9
UGI Common Stock, without par value, shares authorized	450,000,000	450,000,000	450,000,000
UGI Common Stock, without par value, shares issued	173,903,191	173,894,141	173,825,741

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Revenues	$ 1,679.5	$ 1,606.6	[1]
Costs and expenses:
Cost of sales (excluding depreciation shown below)	647.4	734	[1]
Operating and administrative expenses	464.8	464.1
Utility taxes other than income taxes	3.7	3.8
Depreciation	83.7	85.7
Amortization	14.4	14.9
Other operating income, net	(0.7)	(1.4)
Total costs and expenses	1,213.3	1,301.1
Operating income	466.2	305.5	[1]
Loss from equity investees	(0.2)	(0.1)	[1]
Loss on extinguishment of debt	(33.2)	0
Gains on foreign currency contracts, net	1.3	0
Interest expense	(55.4)	(57.9)	[1]
Income before income taxes	378.7	247.5	[1]
Income tax expense	(87.8)	(79.6)
Net income including noncontrolling interests	290.9	167.9
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners	(60.2)	(53.3)	[1]
Net income attributable to UGI Corporation	$ 230.7	$ 114.6
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)	$ 1.33	$ 0.66
Diluted (in dollars per share)	$ 1.30	$ 0.65
Weighted average common shares outstanding (thousands):
Basic (in shares)	173,512	172,862
Diluted (in shares)	176,984	175,218
Dividends declared per common share (in dollars per share)	$ 0.2375	$ 0.2275
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI International and Midstream & Marketing reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2).

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income including noncontrolling interests	$ 290.9	$ 167.9
Other comprehensive income (loss):
Net gains on derivative instruments (net of tax of $(6.0) and $(4.2), respectively)	12.3	6.8
Reclassifications of net gains on derivative instruments (net of tax of $2.1 and $3.2, respectively)	(4.5)	(5.3)
Foreign currency adjustments	(70.9)	(30.2)
Benefit plans (net of tax of $(0.6) and $(0.3), respectively)	1	0.4
Other comprehensive loss	(62.1)	(28.3)
Comprehensive income including noncontrolling interests	228.8	139.6
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	(60.2)	(53.3)
Comprehensive income attributable to UGI Corporation	$ 168.6	$ 86.3

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Tax on (loss) gain on derivative instruments	$ (6)	$ (4.2)
Tax on reclassification on derivative instruments	2.1	3.2
Tax on benefit plans	$ (0.6)	$ (0.3)

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income including noncontrolling interests	$ 290.9	$ 167.9
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization	98.1	100.6	[1]
Deferred income tax benefits	(5.9)	(20.9)
Provision for uncollectible accounts	6.7	6
Change in unrealized losses on derivative instruments	(104.2)	(1.1)
Loss on extinguishment of debt	33.2	0
Other, net	15.1	5.9
Net change in:
Accounts receivable and accrued utility revenues	(437)	(213.4)
Inventories	(22.4)	(9.1)
Utility deferred fuel and power costs, net of changes in unsettled derivatives	(1)	(6.8)
Accounts payable	221.4	33.7
Collateral deposits	0	2.5
Other current assets	(7.3)	2.6
Other current liabilities	39	59.6
Net cash provided by operating activities	126.6	127.5
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(197.1)	(132)
Acquisitions of businesses, net of cash acquired	(0.8)	(41.7)
Decrease in restricted cash	7.7	13.8
Other, net	(2.2)	4.6
Net cash used by investing activities	(192.4)	(155.3)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(41.2)	(39.2)
Distributions on AmeriGas Partners publicly held Common Units	(65)	(63.6)
Issuances of debt, net of issuance costs	789.6	0
Repayments of debt, including redemption premiums	(530.9)	(74.5)
(Decrease) increase in short-term borrowings	(66.7)	260.4
Receivables Facility net borrowings	9.5	6.5
Issuances of UGI Common Stock	3.3	2
Repurchases of UGI Common Stock	0	(23.6)
Other	0	0.4
Net cash provided by financing activities	98.6	68.4
EFFECT OF EXCHANGE RATE CHANGES ON CASH	(20.4)	(7.3)
Cash and cash equivalents increase	12.4	33.3
CASH AND CASH EQUIVALENTS
End of period	515.2	403
Beginning of period	502.8	369.7
Increase	$ 12.4	$ 33.3
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI International and Midstream & Marketing reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2).

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Changes in Equity (unaudited) - USD ($) $ in Millions	Total	Parent	Common stock, without par value	Retained earnings	Accumulated other comprehensive income (loss)	Treasury stock	Noncontrolling interests
Increase (Decrease) in Stockholders' Equity
Cumulative effect of change in accounting for employee share-based payments				$ 0
Balance, beginning of period at Sep. 30, 2015			$ 1,214.6	1,636.9	$ (114.6)	$ (44.9)	$ 880.4
Increase (Decrease) in Stockholders' Equity
Common Stock issued in connection with employee and director plans (including losses on treasury stock transactions), net of tax withheld			(0.9)
Excess tax benefits realized on equity-based compensation			0.4
Equity-based compensation expense			1.6
Sale of treasury stock			0			0
Net income	$ 167.9			114.6			53.3
Cash dividends on Common Stock				(39.2)
Net gains on derivative instruments	6.8				6.8
Reclassification of net gains on derivative instruments	(5.3)				(5.3)
Benefit plans	0.4				0.4
Foreign currency	(30.2)				(30.2)
Common stock issued in connection with employee and director plans, net of tax withheld						3
Repurchases of Common Stock						(23.6)
Reacquired common stock - employee and director plans						(0.2)
Dividends and distributions							(63.6)
Other							3
Balance, end of period at Dec. 31, 2015	3,592.5	$ 2,719.4	1,215.7	1,712.3	(142.9)	(65.7)	873.1
Increase (Decrease) in Stockholders' Equity
Cumulative effect of change in accounting for employee share-based payments				5
Balance, beginning of period at Sep. 30, 2016	3,601.8		1,201.6	1,840.9	(154.7)	(36.9)	750.9
Increase (Decrease) in Stockholders' Equity
Common Stock issued in connection with employee and director plans (including losses on treasury stock transactions), net of tax withheld			(1.2)
Excess tax benefits realized on equity-based compensation			0
Equity-based compensation expense			1.6
Sale of treasury stock			1.4			0.2
Net income	290.9			230.7			60.2
Cash dividends on Common Stock				(41.2)
Net gains on derivative instruments	12.3				12.3
Reclassification of net gains on derivative instruments	(4.5)				(4.5)
Benefit plans	1				1
Foreign currency	(70.9)				(70.9)
Common stock issued in connection with employee and director plans, net of tax withheld						2.8
Repurchases of Common Stock						0
Reacquired common stock - employee and director plans						(0.4)
Dividends and distributions							(65)
Other							(0.7)
Balance, end of period at Dec. 31, 2016	$ 3,733.1	$ 2,987.7	$ 1,203.4	$ 2,035.4	$ (216.8)	$ (34.3)	$ 745.4

Nature of Operations

Nature of Operations	3 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations	Note 1 — Nature of Operations UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; (3) own all or a portion of electricity generation facilities; and (4) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe. We refer to UGI and its consolidated subsidiaries collectively as “the Company,” “we” or “us.” We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”). AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”). AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the “General Partner”), serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as the “Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At December 31, 2016 , the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises Common Units held by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances as further described in Note 14 of our Annual Report on Form 10-K for the fiscal year ended September 30, 2016 (the “Company’s 2016 Annual Report”). Incentive distributions received by the General Partner during the three months ended December 31, 2016 and 2015 were $10.4 and $8.6 , respectively. Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries, conducts an LPG distribution business principally in France, the United Kingdom, and central, northern and eastern Europe. These businesses are conducted principally through our subsidiaries UGI France SAS, Flaga GmbH and AvantiGas Limited. We also conduct a natural gas marketing business principally in France. In March 2016, we sold our LPG business located in the Nantong region of China. We refer to the foreign operations collectively as “UGI International.” UGI Energy Services, LLC (“Energy Services, LLC”), a wholly owned subsidiary of Enterprises, conducts directly and through subsidiaries an energy marketing, midstream transmission, liquefied natural gas (“LNG”), storage, natural gas gathering, natural gas production, electricity generation and energy services business primarily in the Mid-Atlantic and Northeast U.S. Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. A first-tier subsidiary of Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region (“HVAC”). Energy Services, LLC and its subsidiaries’ storage, LNG and portions of its midstream transmission operations are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). We refer to the businesses of Energy Services, LLC and its subsidiaries and HVAC as “Midstream & Marketing.” UGI Utilities, Inc. (“UGI Utilities”) conducts a natural gas distribution utility business (“Gas Utility”) directly and through its wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission. Electric Utility is subject to regulation by the PUC. UGI Utilities is used herein as an abbreviated reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2 — Summary of Significant Accounting Policies The accompanying condensed consolidated financial statements are unaudited and have been prepared in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). They include all adjustments that we consider necessary for a fair statement of the results for the interim periods presented. Such adjustments consisted only of normal recurring items unless otherwise disclosed. The September 30, 2016 , condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by accounting principles generally accepted in the United States of America (“GAAP”). These financial statements should be read in conjunction with the financial statements and related notes included in the Company’s 2016 Annual Report. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year. Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation 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. Shares used in computing basic and diluted earnings per share are as follows: Three Months Ended 2016 2015 Denominator (thousands of shares): Weighted-average common shares outstanding — basic 173,512 172,862 Incremental shares issuable for stock options and awards 3,472 (a) 2,356 Weighted-average common shares outstanding — diluted 176,984 175,218 (a) See “ Adoption of New Accounting Standard - Employee Share-based Payments” below for the impact on the calculation of diluted shares resulting from the adoption of new accounting guidance regarding share-based payments. Derivative Instruments. Derivative instruments are reported on the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. Certain of our derivative instruments are designated and qualify as cash flow hedges and from time to time we also enter into net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities (for which NPNS has not been elected) are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. Beginning October 1, 2016, in order to reduce the volatility in net income associated with its foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we enter into forward foreign currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “gains on foreign currency contracts, net” on the Condensed Consolidated Statements of Income. Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, if any, are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges are included in cash flow from operating activities while cash flows from the currency portion of such hedges are included in cash flow from financing activities. For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 12 . Deferred Debt Issuance Costs. During the fourth quarter of Fiscal 2016, we adopted new accounting guidance regarding the classification of deferred debt issuance costs. 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 line of credit facilities continue to be classified as “other assets” on our Condensed Consolidated Balance Sheets. As a result of the retrospective application of the new accounting guidance, the Company has reflected $30.7 of such costs as a reduction to long-term debt, including current maturities, on the accompanying December 31, 2015 Condensed Consolidated Balance Sheet. Previously, these costs were presented within “other assets.” Income Taxes. UGI’s consolidated effective income tax rate, defined as total income taxes as a percentage of income (loss) before income taxes, includes amounts associated with noncontrolling interests in the Partnership, which principally comprises AmeriGas Partners and AmeriGas OLP. AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. As a result, UGI’s consolidated effective income tax rate is affected by the amount of income (loss) before income taxes attributable to noncontrolling interests in the Partnership not subject to income taxes. In December 2016, the French Parliament approved the Finance Bill for 2017 and amended the Finance Bill for 2016 (collectively, the “Finance Bills”). The Finance Bills, among other things, will reduce UGI France’s corporate income tax rate from the current 34.43% to 28.92% , effective for fiscal years starting after January 1, 2020 (Fiscal 2021). As a result of the future income tax rate reduction, during the three months ended December 31, 2016, the Company reduced its net deferred income tax liabilities and recognized an estimated deferred tax benefit of $27.4 (equal to $0.15 per basic and diluted share). Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions. Adoption of New Accounting Standard - Employee Share-based Payments. During the first quarter of Fiscal 2017, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, 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 and treated as discrete items in the reporting period in which they occur. In addition, assumed proceeds under the treasury stock method used for computing diluted shares outstanding do not include windfall tax benefits in the diluted shares calculation. In accordance with the required prospective method of transition relating to excess tax benefits, the Company recognized income tax benefits of $2.2 related to excess tax benefits for share-based awards that were exercised or vested during the three months ended December 31, 2016. This amount is reflected in “income tax expense” on the Condensed Consolidated Statements of Income. In addition, as of October 1, 2016, the Company recorded a $5.0 cumulative adjustment to increase retained earnings and decrease deferred income tax liabilities for excess tax benefits related to prior period unrecognized excess state tax benefits. The Company elected to use the prospective method of transition for classifying excess tax benefits as a cash flow from operating activity on the Condensed Consolidated Statement of Cash Flows and prior periods were not adjusted. The Company has historically presented employee taxes paid for net settled awards as a financing activity on the Condensed Consolidated Statement of Cash Flows and therefore there is no transition impact from this requirement. In addition, as provided by the new guidance, the Company has elected to account for forfeitures of share-based payments when they occur. Reclassifications. Certain prior period amounts have been reclassified to conform to the current-period presentation.

Accounting Changes

Accounting Changes	3 Months Ended
	Dec. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Changes	Note 3 — Accounting Changes Adoption of New Accounting Standards Employee Share-based Payments. During the first quarter of Fiscal 2017, the Company adopted new accounting guidance regarding share-based payments. See Note 2 for a detailed description of the impact of the new guidance. Equity Method Accounting. During the first quarter of Fiscal 2017, the Company adopted new accounting guidance regarding the accounting for an investment that qualifies for use of the equity method as a result of an increase in an investor’s level of ownership or influence. The guidance requires that the equity method investor add the cost of acquiring an additional interest to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date such investment qualifies for equity method accounting. The new guidance eliminates the previous requirement in such circumstances to apply the effects of the equity method of accounting retrospectively. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements. Accounting Standards Not Yet Adopted Goodwill Impairment. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2017-04, “Simplifying the Test for Goodwill Impairment.” Under the new accounting guidance, an entity will no longer determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Instead, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. In addition, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment, if applicable. The provisions of the new accounting guidance are required to be applied prospectively. The new accounting guidance is effective for the Company for goodwill impairment tests performed in fiscal years beginning after December 15, 2019 (Fiscal 2021). Early adoption is permitted for goodwill impairment tests performed after January 1, 2017. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Cash Flow Classification. In August 2016, the FASB issued ASU No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” This ASU provides guidance on the classification of certain cash receipts and payments in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact on our financial statements of adopting this guidance.

Inventories

Inventories	3 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Inventories	Note 4 — Inventories Inventories comprise the following: December 31, September 30, December 31, Non-utility LPG and natural gas $ 150.9 $ 129.8 $ 148.6 Gas Utility natural gas 25.8 29.2 35.9 Materials, supplies and other 51.5 51.3 62.3 Total inventories $ 228.2 $ 210.3 $ 246.8 At December 31, 2016 , UGI Utilities was a party to four principal storage contract administrative agreements (“SCAAs”) having terms ranging from one to three years. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above. As of December 31, 2016 , UGI Utilities had SCAAs with Energy Services and a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at December 31, 2016 , September 30, 2016 and December 31, 2015 , comprising 1.9 billion cubic feet (“bcf”), 3.5 bcf and 3.8 bcf of natural gas, was $4.8 , $7.6 and $9.4 , respectively.

Goodwill and Intangible Assets

Goodwill and Intangible Assets	3 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	Note 5 — Goodwill and Intangible Assets Goodwill and intangible assets comprise the following: December 31, September 30, December 31, Goodwill (not subject to amortization) $ 2,935.8 $ 2,989.0 $ 2,965.1 Intangible assets: Customer relationships, noncompete agreements and other $ 759.4 $ 773.5 $ 764.6 Accumulated amortization (329.0 ) (324.8 ) (292.2 ) Intangible assets, net (definite-lived) 430.4 448.7 472.4 Trademarks and tradenames (indefinite-lived) 128.5 131.6 130.0 Total intangible assets, net $ 558.9 $ 580.3 $ 602.4 The changes in goodwill and intangible assets are primarily due to acquisitions and the effects of currency translation. Amortization expense of intangible assets was $12.5 and $12.8 for the three months ended December 31, 2016 and 2015 , respectively. Amortization expense included in “cost of sales” on the Condensed Consolidated Statements of Income is not material. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 2017 and for the next four fiscal years is as follows: remainder of Fiscal 2017 — $36.1 ; Fiscal 2018 — $46.7 ; Fiscal 2019 — $44.8 ; Fiscal 2020 — $43.5 ; Fiscal 2021 — $41.6 .

Utility Regulatory Assets and L

Utility Regulatory Assets and Liabilities and Regulatory Matters	3 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Utility Regulatory Assets and Liabilities and Regulatory Matters	Note 6 — Utility Regulatory Assets and Liabilities and Regulatory Matters For a description of the Company’s regulatory assets and liabilities other than those described below, see Note 8 in the Company’s 2016 Annual Report. Other than removal costs, UGI Utilities currently does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets: December 31, September 30, December 31, Regulatory assets: Income taxes recoverable $ 117.8 $ 115.7 $ 117.4 Underfunded pension and postretirement plans 179.4 183.1 138.3 Environmental costs 61.4 59.4 17.6 Removal costs, net 27.1 27.9 22.3 Other 7.2 9.0 6.2 Total regulatory assets $ 392.9 $ 395.1 $ 301.8 Regulatory liabilities (a): Postretirement benefits $ 17.3 $ 17.5 $ 20.3 Deferred fuel and power refunds 23.8 22.3 28.1 State tax benefits—distribution system repairs 15.6 15.1 13.7 Other 2.0 0.7 1.1 Total regulatory liabilities $ 58.7 $ 55.6 $ 63.2 (a) Regulatory liabilities are recorded in “other current liabilities” and “other noncurrent liabilities” on the Condensed Consolidated Balance Sheets. Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability. Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at December 31, 2016 , September 30, 2016 and December 31, 2015 were $6.9 , $4.3 and $(4.5) , respectively. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At December 31, 2016 , September 30, 2016 and December 31, 2015 , substantially all Electric Utility forward electricity purchase contracts were subject to the NPNS exception (see Note 12 ). In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at December 31, 2016 , September 30, 2016 , and December 31, 2015 , were not material. Base Rate Filings. On January 19, 2017, PNG filed a rate request with the PUC to increase PNG’s annual base operating revenues for residential, commercial and industrial customers by $21.7 . The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. PNG requested that the new gas rates become effective March 20, 2017. However, the PUC typically suspends the effective date for general base rate proceedings to allow for investigation and public hearings. Although this review process is expected to last up to nine months , the Company cannot predict the timing or the ultimate outcome of the rate case review process. On October 14, 2016, the PUC approved a previously filed Joint Petition for Approval of Settlement of all issues providing for a $27.0 annual base distribution rate increase for UGI Gas. The increase became effective on October 19, 2016. Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at five percent of distribution charges billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero , in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. To date, no action has been taken by the PUC on either of these petitions. On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism effective January 1, 2017. Revenue collected pursuant to the mechanism will be subject to refund and recoupment based on the PUC’s final resolution of certain matters set aside for hearing before an administrative law judge. To commence recovery of revenue under the mechanism, UGI Gas must first place into service a threshold level of DSIC-eligible plant agreed upon in the settlement of its recent base rate case. Achievement of that threshold is not likely to occur prior to September 30, 2017.

Energy Services Accounts Receiv

Energy Services Accounts Receivable Securitization Facility	3 Months Ended
	Dec. 31, 2016
Transfers and Servicing [Abstract]
Energy Services Accounts Receivable Securitization Facility	Note 7 — Energy Services Accounts Receivable Securitization Facility Energy Services, LLC has an accounts receivable securitization facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2017. The Receivables Facility 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, LLC uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes. Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold and, subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a major bank. Amounts sold to the bank are reflected as “short-term borrowings” on the Condensed Consolidated Balance Sheets. ESFC was created and has been structured to isolate its assets from creditors of Energy Services LLC and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable. Losses on sales of receivables to the bank during the three months ended December 31, 2016 and 2015 , which are included in “interest expense” on the Condensed Consolidated Statements of Income, were not material. Information regarding the trade receivables transferred to ESFC and the amounts sold to the bank for the three months ended December 31, 2016 and 2015 , as well as the balance of ESFC trade receivables at December 31, 2016 , September 30, 2016 and December 31, 2015 , is as follows: Three Months Ended December 31, 2016 2015 Trade receivables transferred to ESFC during the period $ 246.4 $ 199.3 ESFC trade receivables sold to the bank during the period $ 66.0 $ 61.5 December 31, 2016 September 30, 2016 December 31, 2015 ESFC trade receivables - end of period (a) $ 81.4 $ 35.7 $ 55.4 (a) At December 31, 2016 , September 30, 2016 and December 31, 2015 , the amounts of ESFC trade receivables sold to the bank were $35.0 , $25.5 and $26.0 , respectively, and are reflected as “short-term borrowings” on the Condensed Consolidated Balance Sheets.

Debt

Debt	3 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt	Note 8 — Debt UGI Utilities Pursuant to a Note Purchase Agreement, in October 2016, UGI Utilities issued $100 aggregate principal amount of 4.12% Senior Notes due October 2046 (the “UGI Utilities 4.12% Senior Notes”). The net proceeds of the issuance of the UGI Utilities 4.12% Senior Notes were used (1) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and information technology initiatives; and (2) for general corporate purposes. The UGI Utilities 4.12% Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. AmeriGas Propane In December 2016, AmeriGas Partners issued, in an underwritten offering, $700 principal amount of 5.50% Senior Notes due May 2025 (the “AmeriGas Partners’ 5.50% Senior Notes”). The AmeriGas Partners’ 5.50% Senior Notes rank equally with AmeriGas Partners’ existing outstanding senior notes. The net proceeds from the issuance of the AmeriGas Partners’ 5.50% Senior Notes were used for (1) the early repayment, pursuant to a tender offer, of a portion of AmeriGas Partners’ 7.00% Senior Notes having an aggregate principal balance of $500.0 plus accrued and unpaid interest and early redemption premiums, (2) repayment of short-term borrowings and (3) general corporate purposes. For the three months ended December 31, 2016, the Partnership recognized a loss of $33.2 associated with the early repayment of a portion of the AmeriGas Partners’ 7.00% Senior Notes, comprising $28.7 of early redemption premiums and the write-off of $4.5 of unamortized debt issuance costs. The loss is reflected in “Loss on extinguishment of debt” on the Condensed Consolidated Statements of Income.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 9 — Commitments and Contingencies UGI Utilities From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility. UGI Utilities also has two acquired subsidiaries (CPG and PNG) with similar histories of owning, and in some cases operating, MGPs in Pennsylvania. Each of UGI Utilities and its subsidiaries, CPG and PNG, has entered into an agreement with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania (each, a “COA”). The UGI Gas COA was executed in May 2016 and has an effective date of October 1, 2016. The COAs require UGI Gas, CPG and PNG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP related facilities were previously operated (“MGP Properties”) and, in the case of CPG, to plug a minimum number of non-producing natural gas wells per year. Under these agreements, in any calendar year, required environmental expenditures relating to the MGP Properties and, with respect to CPG, the natural gas wells, are capped at $2.5 , $1.8 , and $1.1 , for UGI Gas, CPG and PNG, respectively. The COAs for UGI Gas, CPG and PNG are scheduled to terminate at the end of 2031, 2018, and 2019, respectively, but each COA may be terminated by either party at the end of any two -year period beginning with the original effective date of the COA. At December 31, 2016 , September 30, 2016 and December 31, 2015 , our estimated accrued liabilities for environmental investigation and remediation costs related to the COAs for UGI Gas, CPG and PNG totaled $55.3 , $55.1 and $11.7 , respectively. UGI Gas, CPG, and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 6). 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 Gas, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by its former subsidiaries. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At December 31, 2016 , September 30, 2016 and December 31, 2015 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities MGP sites outside of Pennsylvania was material. Other Matters Purported Class Action Lawsuits. In connection with the Partnership’s 2012 acquisition of the subsidiaries of Energy Transfer Partners, L.P. (“ETP”) that operated ETP’s propane distribution business (“Heritage Propane”), the Partnership became party to a class action lawsuit that was filed against Heritage Operating, L.P. in 2005 by Alfred L. Williams, II, on behalf of himself and all others similarly situated. The class action lawsuit alleged, among other things, wrongful collection of tank rental payments from legacy customers of People’s Gas, which was acquired by Heritage Propane in 2000. In 2010, the Florida District Court certified the class and in January 2015, the Florida District Court awarded the class approximately $18.0 . In April 2016, the Partnership appealed the verdict to the Florida Second District Court of Appeals (the “Second DCA”) and, in September 2016, the Second DCA affirmed the verdict without opinion. Prior to the Second DCA’s action in the case, we believed that the likelihood of the Second DCA affirming the Florida District Court’s decision was remote. As a result of the Second DCA’s actions, in September 2016, the Partnership recorded a $15.0 adjustment to its litigation accrual to reflect the full amount of the award plus associated interest. In October 2016, the Partnership filed a Motion for Written Opinion and for Rehearing En Banc with the Second DCA, which motions are still pending. We believe we have strong arguments to support the aforementioned motions. Between May and October of 2014, more than 35 purported class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI Corporation and a competitor by certain of their direct and indirect customers. The class action lawsuits allege, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce the fill level of portable propane cylinders from 17 pounds to 15 pounds and combined to persuade their common customer, Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in violation of federal and certain state antitrust laws. The claims seek treble damages, injunctive relief, attorneys’ fees and costs on behalf of the putative classes. On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to the Western Division of the United States District Court for the Western District of Missouri (“District Court”). In July 2015, the District Court dismissed all claims brought by direct customers and all claims other than those for injunctive relief brought by indirect customers. The direct customers filed an appeal with the United States Court of Appeals for the Eighth Circuit (“Eighth Circuit”) and in August 2016, the Eighth Circuit affirmed the District Court’s dismissal of the direct customer’s claims against the Partnership/UGI Corporation. The direct customers filed a petition requesting an en banc review of the Eighth Circuit, which was granted. The indirect customers filed an amended complaint with the District Court claiming injunctive relief and state law claims under Wisconsin, Maine and Vermont law. In September 2016, the District Court dismissed the amended complaint in its entirety. The indirect purchasers appealed this decision to the Eighth Circuit; this appeal has been stayed pending the en banc review of the direct purchasers’ claims. On July 21, 2016, several new indirect purchaser plaintiffs filed an antitrust class action lawsuit against the Partnership in the Western District of Missouri. This new indirect purchaser class action lawsuit was dismissed in September 2016 and certain indirect purchaser plaintiffs appealed this decision, consolidating their appeal with the indirect purchaser appeal still pending in the Eighth Circuit. We are unable to reasonably estimate the impact, if any, arising from such litigation. We believe we have strong defenses to the claims and intend to vigorously defend against them. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our financial position, results of operations or cash flows.

Defined Benefit Pension and Oth

Defined Benefit Pension and Other Postretirement Plans	3 Months Ended
	Dec. 31, 2016
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Defined Benefit Pension and Other Postretirement Plans	Note 10 — Defined Benefit Pension and Other Postretirement Plans In the U.S., we sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“U.S. Pension Plan”). We also provide postretirement health care benefits to certain retirees and active employees and postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, UGI France employees are covered by certain defined benefit pension and postretirement plans. Net periodic pension expense and other postretirement benefit costs include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended December 31, 2016 2015 2016 2015 Service cost $ 3.0 $ 2.5 $ 0.2 $ 0.2 Interest cost 6.2 6.6 0.2 0.2 Expected return on assets (8.3 ) (8.0 ) (0.2 ) (0.2 ) Amortization of: Prior service cost (benefit) 0.1 0.1 (0.1 ) (0.1 ) Actuarial loss 4.1 2.7 0.1 — Net benefit cost 5.1 3.9 0.2 0.1 Change in associated regulatory liabilities — — (0.1 ) 0.9 Net expense $ 5.1 $ 3.9 $ 0.1 $ 1.0 The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. During the three months ended December 31, 2016 and 2015 , the Company made cash contributions to the U.S. Pension Plan of $2.8 and $2.5 , respectively. The Company expects to make additional discretionary cash contributions of approximately $8.5 to the U.S. Pension Plan during the remainder of Fiscal 2017 . UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. There were no required contributions to the VEBA during the three months ended December 31, 2016 and 2015 . We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans. Net periodic costs associated with these plans for the three months ended December 31, 2016 and 2015 were not material.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 11 — Fair Value Measurements Recurring Fair Value Measurements The following table presents on a gross basis our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of December 31, 2016 , September 30, 2016 and December 31, 2015 : Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2016: Derivative instruments: Assets: Commodity contracts $ 62.7 $ 61.8 $ — $ 124.5 Foreign currency contracts $ — $ 26.0 $ — $ 26.0 Cross-currency swaps $ — $ 3.5 $ — $ 3.5 Liabilities: Commodity contracts $ (53.1 ) $ (12.4 ) $ — $ (65.5 ) Foreign currency contracts $ — $ (0.2 ) $ — $ (0.2 ) Interest rate contracts $ — $ (2.8 ) $ — $ (2.8 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 34.2 $ — $ — $ 34.2 September 30, 2016: Derivative instruments: Assets: Commodity contracts $ 28.9 $ 26.0 $ — $ 54.9 Foreign currency contracts $ — $ 17.8 $ — $ 17.8 Liabilities: Commodity contracts $ (76.8 ) $ (21.8 ) $ — $ (98.6 ) Foreign currency contracts $ — $ (2.4 ) $ — $ (2.4 ) Interest rate contracts $ — $ (3.9 ) $ — $ (3.9 ) Cross-currency swaps $ — $ (0.5 ) $ — $ (0.5 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 33.0 $ — $ — $ 33.0 December 31, 2015: Derivative instruments: Assets: Commodity contracts $ 19.7 $ 10.8 $ — $ 30.5 Foreign currency contracts $ — $ 25.4 $ — $ 25.4 Interest rate contracts $ — $ 0.6 $ — $ 0.6 Cross-currency swaps $ — $ 1.9 $ — $ 1.9 Liabilities: Commodity contracts $ (70.5 ) $ (97.5 ) $ — $ (168.0 ) Interest rate contracts $ — $ (9.8 ) $ — $ (9.8 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 31.7 $ — $ — $ 31.7 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans. The fair values of our Level 1 exchange-traded commodity futures and option contracts and non-exchange-traded commodity futures and forward contracts are based upon actively quoted market prices for identical assets and liabilities. The remainder of our derivative instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 that are not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of our Level 2 interest rate contracts, foreign currency contracts and cross-currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. There were no transfers between Level 1 and Level 2 during the periods presented. Other Financial Instruments The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. At December 31, 2016 , the carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) were $4,083.8 and $4,171.0 , respectively. At September 30, 2016 , the carrying amount and estimated fair value of our long-term debt (including current maturities but excluding debt issuance costs) were $3,832.3 and $4,052.3 , respectively. At December 31, 2015 , the carrying amount and estimated fair value of our long-term debt (including current maturities but excluding debt issuance costs) were $3,609.3 and $3,590.4 , respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2). Financial instruments other than derivative instruments, such as 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 12 . Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	3 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 12 — Derivative Instruments and Hedging Activities We are exposed to certain market risks related to our ongoing business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk, (2) interest rate risk, and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies, which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Although our commodity derivative instruments extend over a number of years, a significant portion of our commodity derivative instruments economically hedge commodity price risk during the next twelve months. Commodity Price Risk Regulated Utility Operations Natural Gas Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. Gains and losses on Gas Utility’s natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 6 ). Electricity Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At December 31, 2016 , September 30, 2016 and December 31, 2015 , substantially all Electric Utility forward electricity purchase contracts were subject to the NPNS exception. In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities on the Condensed Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6 ). 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 and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. The Partnership from time to time enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility. Also, in addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of propane. Natural Gas In order to manage market price risk relating to fixed-price sales contracts for natural gas, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and forward contracts and Intercontinental Exchange (“ICE”) natural gas basis swap contracts. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas. Electricity In order to manage market price risk relating to fixed-price sales contracts for electricity, Midstream & Marketing enters into electricity futures and forward contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. From time to time, Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and from time to time also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Interest Rate Risk UGI France SAS’s and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. UGI France SAS and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rates of interest on their variable-rate term loans. Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). We account for interest rate swaps and IRPAs as cash flow hedges. At December 31, 2016 , the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3.5 . Foreign Currency Exchange Rate Risk Forward foreign currency exchange contracts In order to reduce exposure to foreign exchange rate volatility related to our foreign LPG operations, through September 30, 2016, we hedged a portion of their anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October through March through the use of forward foreign currency exchange contracts. We account for these foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At December 31, 2016 , the amount of net gains associated with currency rate risk expected to be reclassified into earnings during the next twelve months based upon current fair values is $15.2 . Beginning October 1, 2016, in order to reduce the volatility in net income associated with its foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we enter into forward foreign currency exchange contracts. The fair value of these forward foreign currency contracts are recorded as assets or liabilities on the Condensed Consolidated Balance Sheets. Changes in the fair value of these foreign currency exchange contracts are recorded in “gains on foreign currency contracts, net” on the Condensed Consolidated Statements of Income. From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our International Propane euro-denominated net investments. Cross-Currency Swaps From time to time, Flaga enters into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of U.S. dollar-denominated debt. These cross-currency hedges include initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. These cross-currency swaps also include interest rate swaps of a fixed foreign-denominated interest rate to a fixed U.S. dollar-denominated interest rate. We designate these cross-currency swaps as cash flow hedges. At December 31, 2016 , the amount of net losses associated with such cross-currency swaps expected to be reclassified into earnings during the next twelve months is not material. Quantitative Disclosures Related to Derivative Instruments The following table summarizes by derivative type the gross notional amounts related to open derivative contracts and the final settlement date of the Company's open derivative transactions as of December 31, 2016 , September 30, 2016 and December 31, 2015 , and the final settlement date of the Company's open derivative transactions as of December 31, 2016 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through December 31, 2016 September 30, 2016 December 31, 2015 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms September 2017 11.7 18.4 12.4 Electric Utility forward electricity purchase contracts Kilowatt hours N/A — — 55.9 FTRs Kilowatt hours May 2017 36.2 58.3 172.6 Non-utility operations LPG swaps & options Gallons September 2019 325.9 396.9 481.9 Natural gas futures, forward and pipeline contracts Dekatherms December 2020 70.2 71.1 104.9 Natural gas basis swap contracts Dekatherms December 2020 120.1 118.3 86.1 NYMEX natural gas storage Dekatherms April 2017 1.3 1.9 1.6 NYMEX propane storage Gallons N/A — — 1.8 Electricity long forward and futures contracts Kilowatt hours January 2020 685.5 761.2 547.8 Electricity short forward and futures contracts Kilowatt hours January 2020 352.5 264.6 252.9 FTRs Kilowatt hours N/A — — 51.1 Interest Rate Risk: Interest rate swaps Euro October 2020 € 645.8 € 645.8 € 645.8 IRPAs USD N/A $ — $ — $ 290.0 Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2020 $ 416.7 $ 314.3 $ 280.5 Cross-currency swaps USD September 2018 $ 59.1 $ 59.1 $ 59.1 Derivative Instrument Credit Risk We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2016 , September 30, 2016 and December 31, 2015 , restricted cash in brokerage accounts totaled $7.9 , $15.6 and $55.5 , respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss we would incur if these counterparties failed to perform according to the terms of their contracts, based upon the gross fair values of the derivative instruments, was not material at December 31, 2016 . Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At December 31, 2016 , 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 (and cash collateral received and pledged) are presented net by counterparty on the Condensed Consolidated Balance Sheets if the right of offset exists. Our derivative instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange or clearinghouse to enter, execute or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions. In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on the Condensed Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements. Fair Value of Derivative Instruments The following table presents the Company’s derivative assets and liabilities by type, as well as the effects of offsetting, as of December 31, 2016 , September 30, 2016 and December 31, 2015 : December 31, September 30, December 31, Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 24.6 $ 17.8 $ 25.4 Cross-currency contracts 3.5 — 1.9 Interest rate contracts — — 0.6 28.1 17.8 27.9 Derivatives subject to PGC and DS mechanisms: Commodity contracts 6.9 4.5 0.2 Derivatives not designated as hedging instruments: Commodity contracts 117.6 50.4 30.3 Foreign currency contracts 1.4 — — 119.0 50.4 30.3 Total derivative assets — gross 154.0 72.7 58.4 Gross amounts offset in the balance sheet (35.7 ) (35.0 ) (15.6 ) Cash collateral received (7.1 ) (0.3 ) — Total derivative assets — net $ 111.2 $ 37.4 $ 42.8 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ — $ (2.4 ) $ — Cross-currency contracts — (0.5 ) — Interest rate contracts (2.8 ) (3.9 ) (9.8 ) (2.8 ) (6.8 ) (9.8 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (0.3 ) (0.5 ) (6.3 ) Derivatives not designated as hedging instruments: Commodity contracts (65.2 ) (98.1 ) (161.7 ) Foreign currency contracts (0.2 ) — — (65.4 ) (98.1 ) (161.7 ) Total derivative liabilities — gross (68.5 ) (105.4 ) (177.8 ) Gross amounts offset in the balance sheet 35.7 35.0 15.6 Cash collateral pledged — — 5.5 Total derivative liabilities — net $ (32.8 ) $ (70.4 ) $ (156.7 ) Effect of Derivative Instruments The following tables provide information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for the three months ended December 31, 2016 and 2015 : Three Months Ended December 31,: Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Cash Flow Hedges: 2016 2015 2016 2015 Foreign currency contracts 17.2 5.4 7.9 9.1 Cost of sales Cross-currency contracts (0.1 ) — (0.3 ) — Interest expense/other operating income, net Interest rate contracts 1.2 5.6 (1.0 ) (0.6 ) Interest expense Total $ 18.3 $ 11.0 $ 6.6 $ 8.5 Gain (Loss) Location of Gain (Loss) Derivatives Not Designated as Hedging Instruments: 2016 2015 Commodity contracts $ 108.5 $ (46.2 ) Cost of sales Commodity contracts 0.1 1.6 Revenues Commodity contracts (0.1 ) (0.1 ) Operating and administrative expenses Foreign currency contracts 1.3 — Gains on foreign currency contracts, net Total $ 109.8 $ (44.7 ) For the three months ended December 31, 2016 , 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. For the three months ended December 31, 2015 , 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 was a loss of $3.4 , which is recorded in “other operating income, net,” on the Condensed Consolidated Statements of Income and is related to interest rate contracts at UGI France SAS. 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 under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	3 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Accumulated Other Comprehensive Income	Note 13 — Accumulated Other Comprehensive Income The tables below present changes in AOCI during the three months ended December 31, 2016 and 2015 : Three Months Ended December 31, 2016 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2016 $ (29.1 ) $ (13.4 ) $ (112.2 ) $ (154.7 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) — 12.3 (70.9 ) (58.6 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 1.6 (6.6 ) — (5.0 ) Reclassification adjustments tax (expense) benefit (0.6 ) 2.1 — 1.5 Reclassification adjustments (after-tax) 1.0 (4.5 ) — (3.5 ) Other comprehensive income (loss) attributable to UGI 1.0 7.8 (70.9 ) (62.1 ) AOCI - December 31, 2016 $ (28.1 ) $ (5.6 ) $ (183.1 ) $ (216.8 ) Three Months Ended December 31, 2015 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2015 $ (20.4 ) $ 11.2 $ (105.4 ) $ (114.6 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) — 6.8 (30.2 ) (23.4 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.7 (8.5 ) — (7.8 ) Reclassification adjustments tax (expense) benefit (0.3 ) 3.2 — 2.9 Reclassification adjustments (after-tax) 0.4 (5.3 ) — (4.9 ) Other comprehensive income (loss) attributable to UGI 0.4 1.5 (30.2 ) (28.3 ) AOCI - December 31, 2015 $ (20.0 ) $ 12.7 $ (135.6 ) $ (142.9 ) For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 12 .

Segment Information

Segment Information	3 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Segment Information	Note 14 — Segment Information Our operations comprise four reportable segments generally based upon products sold, geographic location and regulatory environment. As more fully described below, effective October 1, 2016, our former Energy Services and Electric Generation reportable segments were combined into one reportable segment called “Midstream & Marketing,” and our former UGI France and Flaga & Other reportable segments were combined into one reportable segment called “UGI International.” Our reportable segments comprise: (1) AmeriGas Propane; (2) UGI International; (3) Midstream & Marketing; and (4) UGI Utilities. As a result of changes in the composition of information reported to our chief operating decision maker (“CODM”), effective October 1, 2016, we combined our UGI France reportable segment with our Flaga & Other reportable segment, collectively referred to as “UGI International.” Also, as a result of changes in the composition of information reported to our CODM, effective October 1, 2016, we combined our Energy Services reportable segment with our Electric Generation reportable segment, collectively referred to as “Midstream & Marketing.” In accordance with GAAP, prior-period amounts have been restated to reflect these changes. The accounting policies of our reportable segments are the same as those described in Note 2, “Summary of Significant Accounting Policies,” in the Company’s 2016 Annual Report. We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization as adjusted for the effects of gains and losses on commodity derivative instruments not associated with current-period transactions and other gains and losses that competitors do not necessarily have (“Partnership Adjusted EBITDA”). Although we use Partnership Adjusted EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be different from that used by other companies. We evaluate the performance of our other reportable segments principally based upon their income before income taxes as adjusted for gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions. Net gains and losses on commodity and certain foreign currency derivative instruments not associated with current-period transactions are reflected in Corporate & Other because the Company’s CODM does not consider such items when evaluating the financial performance of our reportable segments. Three Months Ended Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 1,679.5 $ (68.5 ) (c) $ 677.2 $ 539.1 $ 269.8 $ 261.4 $ 0.5 Cost of sales $ 647.4 $ (67.7 ) (c) $ 260.7 $ 258.0 $ 191.8 $ 109.5 $ (104.9 ) Segment profit: Operating income $ 466.2 $ 0.1 $ 141.9 $ 88.9 $ 49.7 $ 82.2 $ 103.4 Loss from equity investees (0.2 ) — — (0.2 ) — — — Gains on foreign currency contracts, net 1.3 — — 0.1 — — 1.2 Loss on extinguishment of debt (33.2 ) — (33.2 ) — — — — Interest expense (55.4 ) — (40.0 ) (4.8 ) (0.6 ) (10.0 ) — Income before income taxes $ 378.7 $ 0.1 $ 68.7 $ 84.0 $ 49.1 $ 72.2 $ 104.6 Partnership Adjusted EBITDA (a) $ 185.1 Noncontrolling interests’ net income $ 60.2 $ — $ 41.2 $ 0.2 $ — $ — $ 18.8 Depreciation and amortization $ 98.1 $ — $ 44.6 $ 27.9 $ 8.0 $ 17.4 $ 0.2 Capital expenditures (including the effects of accruals) $ 173.6 $ — $ 26.4 $ 21.5 $ 61.5 $ 64.1 $ 0.1 As of December 31, 2016 Total assets $ 11,300.5 $ (107.9 ) $ 4,217.9 $ 2,853.4 $ 1,178.4 $ 2,898.5 $ 260.2 Short-term borrowings $ 234.4 $ — $ 77.5 $ 3.5 $ 55.0 $ 98.4 $ — Goodwill $ 2,935.8 $ — $ 1,978.5 $ 763.7 $ 11.5 $ 182.1 $ — Three Months Ended Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 1,606.6 $ (42.7 ) (c) $ 644.1 $ 578.2 $ 226.9 $ 198.0 $ 2.1 Cost of sales $ 734.0 $ (41.8 ) (c) $ 243.2 $ 302.8 $ 154.5 $ 75.4 $ (0.1 ) Segment profit: Operating income (loss) $ 305.5 $ 0.1 $ 129.6 $ 85.1 $ 42.9 $ 48.3 $ (0.5 ) Loss from equity investees (0.1 ) — — (0.1 ) — — — Interest expense (57.9 ) — (41.0 ) (6.5 ) (0.8 ) (9.5 ) (0.1 ) Income (loss) before income taxes $ 247.5 $ 0.1 $ 88.6 $ 78.5 $ 42.1 $ 38.8 $ (0.6 ) Partnership EBITDA (a) $ 177.7 Noncontrolling interests’ net income (loss) $ 53.3 $ — $ 57.3 $ 0.1 $ — $ — $ (4.1 ) Depreciation and amortization $ 100.6 $ — $ 49.2 $ 27.2 $ 7.4 $ 16.7 $ 0.1 Capital expenditures (including the effects of accruals) $ 132.9 $ — $ 28.0 $ 21.0 $ 22.4 $ 61.5 $ — As of December 31, 2015 Total assets $ 10,749.7 $ (106.2 ) $ 4,222.1 $ 2,905.8 $ 1,000.0 $ 2,604.2 $ 123.8 Short-term borrowings $ 456.8 $ — $ 182.0 $ 1.1 $ 56.0 $ 217.7 $ — Goodwill $ 2,965.1 $ — $ 1,971.3 $ 800.2 $ 11.5 $ 182.1 $ — (a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: Three Months Ended 2016 2015 Partnership Adjusted EBITDA $ 185.1 $ 177.7 Depreciation and amortization (44.6 ) (49.2 ) Interest expense (40.0 ) (41.0 ) Loss on extinguishment of debt (33.2 ) — Noncontrolling interest (i) 1.4 1.1 Income before income taxes $ 68.7 $ 88.6 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. (b) Corporate & Other results principally comprise (1) net expenses of UGI’s captive general liability insurance company and UGI’s corporate headquarters facility, and (2) UGI’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $105.5 and $1.1 during the three months ended December 31, 2016 and 2015 , respectively. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company; UGI corporate headquarters’ assets; and our investment in a private equity partnership. (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) Restated to reflect (1) the current-year changes in the presentation of our UGI International and Midstream & Marketing reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2).

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Earnings Per Common Share	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.
Derivative Instruments	Derivative Instruments. Derivative instruments are reported on the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. Certain of our derivative instruments are designated and qualify as cash flow hedges and from time to time we also enter into net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities (for which NPNS has not been elected) are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. Beginning October 1, 2016, in order to reduce the volatility in net income associated with its foreign operations, principally as a result of changes in the U.S. dollar exchange rate between the euro and British pound sterling, we enter into forward foreign currency exchange contracts. Because these contracts do not qualify for hedge accounting treatment, realized and unrealized gains and losses on these contracts are recorded in “gains on foreign currency contracts, net” on the Condensed Consolidated Statements of Income. Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, if any, are included in cash flows from operating activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Condensed Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges are included in cash flow from operating activities while cash flows from the currency portion of such hedges are included in cash flow from financing activities.
Deferred Debt Issuance Costs	Deferred Debt Issuance Costs. During the fourth quarter of Fiscal 2016, we adopted new accounting guidance regarding the classification of deferred debt issuance costs. 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 line of credit facilities continue to be classified as “other assets” on our Condensed Consolidated Balance Sheets.
Income Taxes	Income Taxes. UGI’s consolidated effective income tax rate, defined as total income taxes as a percentage of income (loss) before income taxes, includes amounts associated with noncontrolling interests in the Partnership, which principally comprises AmeriGas Partners and AmeriGas OLP. AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. As a result, UGI’s consolidated effective income tax rate is affected by the amount of income (loss) before income taxes attributable to noncontrolling interests in the Partnership not subject to income taxes.
Use of Estimates	Use of Estimates. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions.
Adoption of New Accounting Standards and Accounting Standards Not Yet Adopted	Adoption of New Accounting Standard - Employee Share-based Payments. During the first quarter of Fiscal 2017, the Company adopted new accounting guidance issued to simplify several aspects of accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, 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 and treated as discrete items in the reporting period in which they occur. In addition, assumed proceeds under the treasury stock method used for computing diluted shares outstanding do not include windfall tax benefits in the diluted shares calculation. Adoption of New Accounting Standards Employee Share-based Payments. During the first quarter of Fiscal 2017, the Company adopted new accounting guidance regarding share-based payments. See Note 2 for a detailed description of the impact of the new guidance. Equity Method Accounting. During the first quarter of Fiscal 2017, the Company adopted new accounting guidance regarding the accounting for an investment that qualifies for use of the equity method as a result of an increase in an investor’s level of ownership or influence. The guidance requires that the equity method investor add the cost of acquiring an additional interest to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date such investment qualifies for equity method accounting. The new guidance eliminates the previous requirement in such circumstances to apply the effects of the equity method of accounting retrospectively. The guidance is required to be applied prospectively. The adoption of the new guidance did not impact our consolidated financial statements. Accounting Standards Not Yet Adopted Goodwill Impairment. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") No. 2017-04, “Simplifying the Test for Goodwill Impairment.” Under the new accounting guidance, an entity will no longer determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Instead, an entity will perform its goodwill impairment tests by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value but not to exceed the total amount of the goodwill of the reporting unit. In addition, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment, if applicable. The provisions of the new accounting guidance are required to be applied prospectively. The new accounting guidance is effective for the Company for goodwill impairment tests performed in fiscal years beginning after December 15, 2019 (Fiscal 2021). Early adoption is permitted for goodwill impairment tests performed after January 1, 2017. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Cash Flow Classification. In August 2016, the FASB issued ASU No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” This ASU provides guidance on the classification of certain cash receipts and payments in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact on our financial statements of adopting this guidance.
Reclassifications	Reclassifications. Certain prior period amounts have been reclassified to conform to the current-period presentation.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Shares Used in Computing Basic and Diluted Earnings Per Share	Shares used in computing basic and diluted earnings per share are as follows: Three Months Ended 2016 2015 Denominator (thousands of shares): Weighted-average common shares outstanding — basic 173,512 172,862 Incremental shares issuable for stock options and awards 3,472 (a) 2,356 Weighted-average common shares outstanding — diluted 176,984 175,218 (a) See “ Adoption of New Accounting Standard - Employee Share-based Payments” below for the impact on the calculation of diluted shares resulting from the adoption of new accounting guidance regarding share-based payments.

Inventories (Tables)

Inventories (Tables)	3 Months Ended
	Dec. 31, 2016
Inventory Disclosure [Abstract]
Components of Inventories	Inventories comprise the following: December 31, September 30, December 31, Non-utility LPG and natural gas $ 150.9 $ 129.8 $ 148.6 Gas Utility natural gas 25.8 29.2 35.9 Materials, supplies and other 51.5 51.3 62.3 Total inventories $ 228.2 $ 210.3 $ 246.8

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	3 Months Ended
	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Components of Company's Goodwill and Intangible Assets	Goodwill and intangible assets comprise the following: December 31, September 30, December 31, Goodwill (not subject to amortization) $ 2,935.8 $ 2,989.0 $ 2,965.1 Intangible assets: Customer relationships, noncompete agreements and other $ 759.4 $ 773.5 $ 764.6 Accumulated amortization (329.0 ) (324.8 ) (292.2 ) Intangible assets, net (definite-lived) 430.4 448.7 472.4 Trademarks and tradenames (indefinite-lived) 128.5 131.6 130.0 Total intangible assets, net $ 558.9 $ 580.3 $ 602.4

Utility Regulatory Assets and27

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)	3 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Schedule of Regulatory Assets	The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets: December 31, September 30, December 31, Regulatory assets: Income taxes recoverable $ 117.8 $ 115.7 $ 117.4 Underfunded pension and postretirement plans 179.4 183.1 138.3 Environmental costs 61.4 59.4 17.6 Removal costs, net 27.1 27.9 22.3 Other 7.2 9.0 6.2 Total regulatory assets $ 392.9 $ 395.1 $ 301.8 Regulatory liabilities (a): Postretirement benefits $ 17.3 $ 17.5 $ 20.3 Deferred fuel and power refunds 23.8 22.3 28.1 State tax benefits—distribution system repairs 15.6 15.1 13.7 Other 2.0 0.7 1.1 Total regulatory liabilities $ 58.7 $ 55.6 $ 63.2 (a) Regulatory liabilities are recorded in “other current liabilities” and “other noncurrent liabilities” on the Condensed Consolidated Balance Sheets.
Schedule of Regulatory Liabilities	The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Condensed Consolidated Balance Sheets: December 31, September 30, December 31, Regulatory assets: Income taxes recoverable $ 117.8 $ 115.7 $ 117.4 Underfunded pension and postretirement plans 179.4 183.1 138.3 Environmental costs 61.4 59.4 17.6 Removal costs, net 27.1 27.9 22.3 Other 7.2 9.0 6.2 Total regulatory assets $ 392.9 $ 395.1 $ 301.8 Regulatory liabilities (a): Postretirement benefits $ 17.3 $ 17.5 $ 20.3 Deferred fuel and power refunds 23.8 22.3 28.1 State tax benefits—distribution system repairs 15.6 15.1 13.7 Other 2.0 0.7 1.1 Total regulatory liabilities $ 58.7 $ 55.6 $ 63.2 (a) Regulatory liabilities are recorded in “other current liabilities” and “other noncurrent liabilities” on the Condensed Consolidated Balance Sheets.

Energy Services Accounts Rece28

Energy Services Accounts Receivable Securitization Facility (Tables)	3 Months Ended
	Dec. 31, 2016
Transfers and Servicing [Abstract]
Schedule of Transfer of Trade Receivables	Information regarding the trade receivables transferred to ESFC and the amounts sold to the bank for the three months ended December 31, 2016 and 2015 , as well as the balance of ESFC trade receivables at December 31, 2016 , September 30, 2016 and December 31, 2015 , is as follows: Three Months Ended December 31, 2016 2015 Trade receivables transferred to ESFC during the period $ 246.4 $ 199.3 ESFC trade receivables sold to the bank during the period $ 66.0 $ 61.5 December 31, 2016 September 30, 2016 December 31, 2015 ESFC trade receivables - end of period (a) $ 81.4 $ 35.7 $ 55.4 (a) At December 31, 2016 , September 30, 2016 and December 31, 2015 , the amounts of ESFC trade receivables sold to the bank were $35.0 , $25.5 and $26.0 , respectively, and are reflected as “short-term borrowings” on the Condensed Consolidated Balance Sheets.

Defined Benefit Pension and O29

Defined Benefit Pension and Other Postretirement Plans (Tables)	3 Months Ended
	Dec. 31, 2016
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs	Net periodic pension expense and other postretirement benefit costs include the following components: Pension Benefits Other Postretirement Benefits Three Months Ended December 31, 2016 2015 2016 2015 Service cost $ 3.0 $ 2.5 $ 0.2 $ 0.2 Interest cost 6.2 6.6 0.2 0.2 Expected return on assets (8.3 ) (8.0 ) (0.2 ) (0.2 ) Amortization of: Prior service cost (benefit) 0.1 0.1 (0.1 ) (0.1 ) Actuarial loss 4.1 2.7 0.1 — Net benefit cost 5.1 3.9 0.2 0.1 Change in associated regulatory liabilities — — (0.1 ) 0.9 Net expense $ 5.1 $ 3.9 $ 0.1 $ 1.0

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	3 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Financial Assets and Financial Liabilities that are Measured at Fair Value on a Recurring Basis	The following table presents on a gross basis our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy, as of December 31, 2016 , September 30, 2016 and December 31, 2015 : Asset (Liability) Level 1 Level 2 Level 3 Total December 31, 2016: Derivative instruments: Assets: Commodity contracts $ 62.7 $ 61.8 $ — $ 124.5 Foreign currency contracts $ — $ 26.0 $ — $ 26.0 Cross-currency swaps $ — $ 3.5 $ — $ 3.5 Liabilities: Commodity contracts $ (53.1 ) $ (12.4 ) $ — $ (65.5 ) Foreign currency contracts $ — $ (0.2 ) $ — $ (0.2 ) Interest rate contracts $ — $ (2.8 ) $ — $ (2.8 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 34.2 $ — $ — $ 34.2 September 30, 2016: Derivative instruments: Assets: Commodity contracts $ 28.9 $ 26.0 $ — $ 54.9 Foreign currency contracts $ — $ 17.8 $ — $ 17.8 Liabilities: Commodity contracts $ (76.8 ) $ (21.8 ) $ — $ (98.6 ) Foreign currency contracts $ — $ (2.4 ) $ — $ (2.4 ) Interest rate contracts $ — $ (3.9 ) $ — $ (3.9 ) Cross-currency swaps $ — $ (0.5 ) $ — $ (0.5 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 33.0 $ — $ — $ 33.0 December 31, 2015: Derivative instruments: Assets: Commodity contracts $ 19.7 $ 10.8 $ — $ 30.5 Foreign currency contracts $ — $ 25.4 $ — $ 25.4 Interest rate contracts $ — $ 0.6 $ — $ 0.6 Cross-currency swaps $ — $ 1.9 $ — $ 1.9 Liabilities: Commodity contracts $ (70.5 ) $ (97.5 ) $ — $ (168.0 ) Interest rate contracts $ — $ (9.8 ) $ — $ (9.8 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 31.7 $ — $ — $ 31.7 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.

Derivative Instruments and He31

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Dec. 31, 2016
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 and the final settlement date of the Company's open derivative transactions as of December 31, 2016 , September 30, 2016 and December 31, 2015 , and the final settlement date of the Company's open derivative transactions as of December 31, 2016 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through December 31, 2016 September 30, 2016 December 31, 2015 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms September 2017 11.7 18.4 12.4 Electric Utility forward electricity purchase contracts Kilowatt hours N/A — — 55.9 FTRs Kilowatt hours May 2017 36.2 58.3 172.6 Non-utility operations LPG swaps & options Gallons September 2019 325.9 396.9 481.9 Natural gas futures, forward and pipeline contracts Dekatherms December 2020 70.2 71.1 104.9 Natural gas basis swap contracts Dekatherms December 2020 120.1 118.3 86.1 NYMEX natural gas storage Dekatherms April 2017 1.3 1.9 1.6 NYMEX propane storage Gallons N/A — — 1.8 Electricity long forward and futures contracts Kilowatt hours January 2020 685.5 761.2 547.8 Electricity short forward and futures contracts Kilowatt hours January 2020 352.5 264.6 252.9 FTRs Kilowatt hours N/A — — 51.1 Interest Rate Risk: Interest rate swaps Euro October 2020 € 645.8 € 645.8 € 645.8 IRPAs USD N/A $ — $ — $ 290.0 Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2020 $ 416.7 $ 314.3 $ 280.5 Cross-currency swaps USD September 2018 $ 59.1 $ 59.1 $ 59.1
Schedule of Derivative Assets, Liabilities and the Effects of Offsetting	The following table presents the Company’s derivative assets and liabilities by type, as well as the effects of offsetting, as of December 31, 2016 , September 30, 2016 and December 31, 2015 : December 31, September 30, December 31, Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 24.6 $ 17.8 $ 25.4 Cross-currency contracts 3.5 — 1.9 Interest rate contracts — — 0.6 28.1 17.8 27.9 Derivatives subject to PGC and DS mechanisms: Commodity contracts 6.9 4.5 0.2 Derivatives not designated as hedging instruments: Commodity contracts 117.6 50.4 30.3 Foreign currency contracts 1.4 — — 119.0 50.4 30.3 Total derivative assets — gross 154.0 72.7 58.4 Gross amounts offset in the balance sheet (35.7 ) (35.0 ) (15.6 ) Cash collateral received (7.1 ) (0.3 ) — Total derivative assets — net $ 111.2 $ 37.4 $ 42.8 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ — $ (2.4 ) $ — Cross-currency contracts — (0.5 ) — Interest rate contracts (2.8 ) (3.9 ) (9.8 ) (2.8 ) (6.8 ) (9.8 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (0.3 ) (0.5 ) (6.3 ) Derivatives not designated as hedging instruments: Commodity contracts (65.2 ) (98.1 ) (161.7 ) Foreign currency contracts (0.2 ) — — (65.4 ) (98.1 ) (161.7 ) Total derivative liabilities — gross (68.5 ) (105.4 ) (177.8 ) Gross amounts offset in the balance sheet 35.7 35.0 15.6 Cash collateral pledged — — 5.5 Total derivative liabilities — net $ (32.8 ) $ (70.4 ) $ (156.7 )
Effects of Derivative Instruments on Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest	The following tables provide information on the effects of derivative instruments on the Condensed Consolidated Statements of Income and changes in AOCI for the three months ended December 31, 2016 and 2015 : Three Months Ended December 31,: Gain (Loss) Gain (Loss) Location of Gain (Loss) Reclassified from Cash Flow Hedges: 2016 2015 2016 2015 Foreign currency contracts 17.2 5.4 7.9 9.1 Cost of sales Cross-currency contracts (0.1 ) — (0.3 ) — Interest expense/other operating income, net Interest rate contracts 1.2 5.6 (1.0 ) (0.6 ) Interest expense Total $ 18.3 $ 11.0 $ 6.6 $ 8.5 Gain (Loss) Location of Gain (Loss) Derivatives Not Designated as Hedging Instruments: 2016 2015 Commodity contracts $ 108.5 $ (46.2 ) Cost of sales Commodity contracts 0.1 1.6 Revenues Commodity contracts (0.1 ) (0.1 ) Operating and administrative expenses Foreign currency contracts 1.3 — Gains on foreign currency contracts, net Total $ 109.8 $ (44.7 )

Accumulated Other Comprehensi32

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income	The tables below present changes in AOCI during the three months ended December 31, 2016 and 2015 : Three Months Ended December 31, 2016 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2016 $ (29.1 ) $ (13.4 ) $ (112.2 ) $ (154.7 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) — 12.3 (70.9 ) (58.6 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 1.6 (6.6 ) — (5.0 ) Reclassification adjustments tax (expense) benefit (0.6 ) 2.1 — 1.5 Reclassification adjustments (after-tax) 1.0 (4.5 ) — (3.5 ) Other comprehensive income (loss) attributable to UGI 1.0 7.8 (70.9 ) (62.1 ) AOCI - December 31, 2016 $ (28.1 ) $ (5.6 ) $ (183.1 ) $ (216.8 ) Three Months Ended December 31, 2015 Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2015 $ (20.4 ) $ 11.2 $ (105.4 ) $ (114.6 ) Other comprehensive income (loss) before reclassification adjustments (after-tax) — 6.8 (30.2 ) (23.4 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 0.7 (8.5 ) — (7.8 ) Reclassification adjustments tax (expense) benefit (0.3 ) 3.2 — 2.9 Reclassification adjustments (after-tax) 0.4 (5.3 ) — (4.9 ) Other comprehensive income (loss) attributable to UGI 0.4 1.5 (30.2 ) (28.3 ) AOCI - December 31, 2015 $ (20.0 ) $ 12.7 $ (135.6 ) $ (142.9 )

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Schedule of Segment Reporting Information	Three Months Ended Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 1,679.5 $ (68.5 ) (c) $ 677.2 $ 539.1 $ 269.8 $ 261.4 $ 0.5 Cost of sales $ 647.4 $ (67.7 ) (c) $ 260.7 $ 258.0 $ 191.8 $ 109.5 $ (104.9 ) Segment profit: Operating income $ 466.2 $ 0.1 $ 141.9 $ 88.9 $ 49.7 $ 82.2 $ 103.4 Loss from equity investees (0.2 ) — — (0.2 ) — — — Gains on foreign currency contracts, net 1.3 — — 0.1 — — 1.2 Loss on extinguishment of debt (33.2 ) — (33.2 ) — — — — Interest expense (55.4 ) — (40.0 ) (4.8 ) (0.6 ) (10.0 ) — Income before income taxes $ 378.7 $ 0.1 $ 68.7 $ 84.0 $ 49.1 $ 72.2 $ 104.6 Partnership Adjusted EBITDA (a) $ 185.1 Noncontrolling interests’ net income $ 60.2 $ — $ 41.2 $ 0.2 $ — $ — $ 18.8 Depreciation and amortization $ 98.1 $ — $ 44.6 $ 27.9 $ 8.0 $ 17.4 $ 0.2 Capital expenditures (including the effects of accruals) $ 173.6 $ — $ 26.4 $ 21.5 $ 61.5 $ 64.1 $ 0.1 As of December 31, 2016 Total assets $ 11,300.5 $ (107.9 ) $ 4,217.9 $ 2,853.4 $ 1,178.4 $ 2,898.5 $ 260.2 Short-term borrowings $ 234.4 $ — $ 77.5 $ 3.5 $ 55.0 $ 98.4 $ — Goodwill $ 2,935.8 $ — $ 1,978.5 $ 763.7 $ 11.5 $ 182.1 $ — Three Months Ended Total Eliminations AmeriGas UGI International Midstream & Marketing UGI Corporate Revenues $ 1,606.6 $ (42.7 ) (c) $ 644.1 $ 578.2 $ 226.9 $ 198.0 $ 2.1 Cost of sales $ 734.0 $ (41.8 ) (c) $ 243.2 $ 302.8 $ 154.5 $ 75.4 $ (0.1 ) Segment profit: Operating income (loss) $ 305.5 $ 0.1 $ 129.6 $ 85.1 $ 42.9 $ 48.3 $ (0.5 ) Loss from equity investees (0.1 ) — — (0.1 ) — — — Interest expense (57.9 ) — (41.0 ) (6.5 ) (0.8 ) (9.5 ) (0.1 ) Income (loss) before income taxes $ 247.5 $ 0.1 $ 88.6 $ 78.5 $ 42.1 $ 38.8 $ (0.6 ) Partnership EBITDA (a) $ 177.7 Noncontrolling interests’ net income (loss) $ 53.3 $ — $ 57.3 $ 0.1 $ — $ — $ (4.1 ) Depreciation and amortization $ 100.6 $ — $ 49.2 $ 27.2 $ 7.4 $ 16.7 $ 0.1 Capital expenditures (including the effects of accruals) $ 132.9 $ — $ 28.0 $ 21.0 $ 22.4 $ 61.5 $ — As of December 31, 2015 Total assets $ 10,749.7 $ (106.2 ) $ 4,222.1 $ 2,905.8 $ 1,000.0 $ 2,604.2 $ 123.8 Short-term borrowings $ 456.8 $ — $ 182.0 $ 1.1 $ 56.0 $ 217.7 $ — Goodwill $ 2,965.1 $ — $ 1,971.3 $ 800.2 $ 11.5 $ 182.1 $ — (a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: Three Months Ended 2016 2015 Partnership Adjusted EBITDA $ 185.1 $ 177.7 Depreciation and amortization (44.6 ) (49.2 ) Interest expense (40.0 ) (41.0 ) Loss on extinguishment of debt (33.2 ) — Noncontrolling interest (i) 1.4 1.1 Income before income taxes $ 68.7 $ 88.6 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. (b) Corporate & Other results principally comprise (1) net expenses of UGI’s captive general liability insurance company and UGI’s corporate headquarters facility, and (2) UGI’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $105.5 and $1.1 during the three months ended December 31, 2016 and 2015 , respectively. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company; UGI corporate headquarters’ assets; and our investment in a private equity partnership. (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) Restated to reflect (1) the current-year changes in the presentation of our UGI International and Midstream & Marketing reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2).
Reconciliation of Adjusted EBITDA to (Loss) Income Before Income Taxes	The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: Three Months Ended 2016 2015 Partnership Adjusted EBITDA $ 185.1 $ 177.7 Depreciation and amortization (44.6 ) (49.2 ) Interest expense (40.0 ) (41.0 ) Loss on extinguishment of debt (33.2 ) — Noncontrolling interest (i) 1.4 1.1 Income before income taxes $ 68.7 $ 88.6 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

Nature of Operations (Details)

Nature of Operations (Details) $ in Millions	3 Months Ended
	Dec. 31, 2016USD ($)county	Dec. 31, 2015USD ($)
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General Partner held a general partner interest in AmeriGas Partners	1.00%
Percentage of limited partnership interest in AmeriGas Partners	25.30%
Effective ownership interest in AmeriGas OLP	27.10%
General public as limited partner interests in AmeriGas Partners	73.70%
General Partner incentive distribution | $	$ 10.4	$ 8.6
Number of counties of operation | county	1

Summary of Significant Accoun35

Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Denominator (thousands of shares):
Weighted-average common shares outstanding - basic (in shares)	173,512	172,862
Incremental shares issuable for stock options and awards (in shares)	3,472	2,356
Weighted-average common shares outstanding - diluted (in shares)	176,984	175,218

Summary of Significant Accoun36

Summary of Significant Accounting Policies - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Accounting Policies [Abstract]
Net deferred debt issuance costs			$ 30.7
Segment Reporting Information
Income tax benefits associated with share-based payments	$ 2.2
Retained Earnings [Member]
Segment Reporting Information
Cumulative effect of change in accounting for employee share-based payments		$ 5		$ 0
New Accounting Pronouncement, Early Adoption, Effect | Accounting Standards Update 2016-09
Segment Reporting Information
Decrease in deferred income tax liabilities for excess tax benefits related to prior periods		5
New Accounting Pronouncement, Early Adoption, Effect | Accounting Standards Update 2016-09 | Retained Earnings [Member]
Segment Reporting Information
Cumulative effect of change in accounting for employee share-based payments		$ 5
UGI France
Segment Reporting Information
Estimated deferred tax benefit resulting from future income tax reduction	$ 27.4
Reduction in per share, basic and diluted resulting from future income tax reduction (in dollars per share)	$ 0.15

Inventories - Components of Inv

Inventories - Components of Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Inventory
Total inventories	$ 228.2	$ 210.3	$ 246.8
Non-utility LPG and natural gas
Inventory
Total inventories	150.9	129.8	148.6
Gas Utility natural gas
Inventory
Total inventories	25.8	29.2	35.9
Materials, supplies and other
Inventory
Total inventories	$ 51.5	$ 51.3	$ 62.3

Inventories - Narrative (Detail

Inventories - Narrative (Details) - UGI Utilities $ in Millions	3 Months Ended
	Dec. 31, 2016USD ($)storage_agreementBcf	Sep. 30, 2016USD ($)Bcf	Dec. 31, 2015USD ($)Bcf
Inventory
Number of storage agreements | storage_agreement	4
Volume of gas storage inventories released under SCAAs with non-affiliates (in bcf) | Bcf	1.9	3.5	3.8
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $	$ 4.8	$ 7.6	$ 9.4
Minimum
Inventory
SCAA contract term (in years)	1 year
Maximum
Inventory
SCAA contract term (in years)	3 years

Goodwill and Intangible Asset39

Goodwill and Intangible Assets - Components of Company's Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill (not subject to amortization)	$ 2,935.8	$ 2,989	$ 2,965.1	[1]
Intangible assets:
Customer relationships, noncompete agreements and other	759.4	773.5	764.6
Accumulated amortization	(329)	(324.8)	(292.2)
Intangible assets, net (definite-lived)	430.4	448.7	472.4
Trademarks and tradenames (indefinite-lived)	128.5	131.6	130
Total intangible assets, net	$ 558.9	$ 580.3	$ 602.4
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI International and Midstream & Marketing reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2).

Goodwill and Intangible Asset40

Goodwill and Intangible Assets - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense of intangible assets	$ 12.5	$ 12.8
Remainder of Fiscal 2017	36.1
Fiscal 2,018	46.7
Fiscal 2,019	44.8
Fiscal 2,020	43.5
Fiscal 2,021	$ 41.6

Utility Regulatory Assets and41

Utility Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility (Details) - USD ($) $ in Millions		Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Regulatory Assets
Regulatory assets		$ 392.9	$ 395.1	$ 301.8
Regulatory Liabilities
Regulatory liabilities	[1]	58.7	55.6	63.2
Postretirement benefits
Regulatory Liabilities
Regulatory liabilities	[1]	17.3	17.5	20.3
Deferred fuel and power refunds
Regulatory Liabilities
Regulatory liabilities	[1]	23.8	22.3	28.1
State tax benefits—distribution system repairs
Regulatory Liabilities
Regulatory liabilities	[1]	15.6	15.1	13.7
Other
Regulatory Liabilities
Regulatory liabilities	[1]	2	0.7	1.1
Income taxes recoverable
Regulatory Assets
Regulatory assets		117.8	115.7	117.4
Underfunded pension and postretirement plans
Regulatory Assets
Regulatory assets		179.4	183.1	138.3
Environmental costs
Regulatory Assets
Regulatory assets		61.4	59.4	17.6
Removal costs, net
Regulatory Assets
Regulatory assets		27.1	27.9	22.3
Other
Regulatory Assets
Regulatory assets		$ 7.2	$ 9	$ 6.2
[1]	Regulatory liabilities are recorded in “other current liabilities” and “other noncurrent liabilities” on the Condensed Consolidated Balance Sheets.

Utility Regulatory Assets and42

Utility Regulatory Assets and Liabilities and Regulatory Matters - Narrative (Details) - USD ($) $ in Millions	Jan. 19, 2017	Oct. 14, 2016	Apr. 01, 2016	Apr. 01, 2015	Mar. 31, 2016	Dec. 31, 2016	Sep. 30, 2014	Sep. 30, 2016	Dec. 31, 2015
Pennsylvania Public Utility Commission | Subsequent Event
Regulatory Assets
Review process period	9 months
UGI Utilities | Pennsylvania Public Utility Commission
Regulatory Assets
Operating revenue increase		$ 27
Maximum period since petition to file a general rate filing						5 years
DSIC, percent of amount billed to customers							0.00%
UGI Utilities | Pennsylvania Public Utility Commission | PNG
Regulatory Assets
DSIC, percent of amount billed to customers				0.00%
UGI Utilities | Pennsylvania Public Utility Commission | CPG
Regulatory Assets
DSIC, percent of amount billed to customers			0.00%
UGI Utilities | Pennsylvania Public Utility Commission | Maximum
Regulatory Assets
DSIC, percent of amount billed to customers					5.00%	5.00%
UGI Utilities | Pennsylvania Public Utility Commission | Maximum | PNG
Regulatory Assets
DSIC, percent of amount billed to customers					10.00%
UGI Utilities | Pennsylvania Public Utility Commission | Maximum | CPG
Regulatory Assets
DSIC, percent of amount billed to customers					10.00%
UGI Utilities | Pennsylvania Public Utility Commission | Subsequent Event
Regulatory Assets
Requested operating revenue increase	$ 21.7
Gas Utility
Regulatory Assets
Fair value of unrealized gains (losses)						$ 6.9		$ 4.3	$ (4.5)

Energy Services Accounts Rece43

Energy Services Accounts Receivable Securitization Facility - Narrative (Details) - USD ($)	6 Months Ended
	Oct. 31, 2017	Apr. 30, 2017
Forecast | Maximum
Accounts, Notes, Loans and Financing Receivable
Receivables facility	$ 75,000,000	$ 150,000,000

Energy Services Accounts Rece44

Energy Services Accounts Receivable Securitization Facility - Trade Receivables Transferred and Sold (Details) - USD ($) $ in Millions		3 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2016
Energy Services
Accounts, Notes, Loans and Financing Receivable
Trade receivables transferred to ESFC during the period		$ 246.4	$ 199.3
Energy Services Funding Corporation
Accounts, Notes, Loans and Financing Receivable
ESFC trade receivables sold to the bank during the period		66	61.5
ESFC trade receivables - end of period	[1]	81.4	55.4	$ 35.7
Outstanding balance of trade receivables sold		$ 35	$ 26	$ 25.5
[1]	At December 31, 2016, September 30, 2016 and December 31, 2015, the amounts of ESFC trade receivables sold to the bank were $35.0, $25.5 and $26.0, respectively, and are reflected as “short-term borrowings” on the Condensed Consolidated Balance Sheets.

Debt (Details)

Debt (Details) - USD ($)	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Oct. 31, 2016
Line of Credit Facility
Loss on early repayment of notes	$ 33,200,000	$ 0
UGI Utilities | Senior Notes | Senior Notes due October 2046
Line of Credit Facility
Debt issued			$ 100,000,000
Stated interest rate			4.12%
Amerigas Propane | Senior Notes | 5.50% Senior Notes due May 2025
Line of Credit Facility
Debt issued	$ 700,000,000
Stated interest rate	5.50%
Amerigas Propane | Senior Notes | 7.00% Senior Notes
Line of Credit Facility
Stated interest rate	7.00%
Aggregate principal balance of notes redeemed	$ 500,000,000
Loss on early repayment of notes	33,200,000
Redemption premium	28,700,000
Write-off of unamortized debt issuance costs	$ 4,500,000

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	1 Months Ended		3 Months Ended	6 Months Ended
	Sep. 30, 2016USD ($)	Jan. 31, 2015USD ($)	Dec. 31, 2016USD ($)subsidiarylb	Oct. 31, 2014lawsuit	Dec. 31, 2015USD ($)
Loss Contingencies
Amount awarded		$ 18
Adjustment to litigation accrual	$ 15
Class action lawsuits (more than) | lawsuit				35
Amount of propane in cylinders before reduction (in pounds) | lb			17
Amount of propane in cylinders after reduction (in pounds) | lb			15
CPG MGP | Environmental Matters
Loss Contingencies
Environmental expenditures cap during calendar year			$ 1.8
PNG MGP | Environmental Matters
Loss Contingencies
Environmental expenditures cap during calendar year			1.1
UGI Gas | Environmental Matters
Loss Contingencies
Environmental expenditures cap during calendar year			$ 2.5
PNG-COA
Loss Contingencies
Loss contingency, settlement agreement, terms			2 years
UGI Utilities | CPG, PNG and UGI Gas COAs
Loss Contingencies
Accrual for environmental loss contingencies	$ 55.1		$ 55.3		$ 11.7
UGI Utilities | PNG and CPG
Loss Contingencies
Number of subsidiaries acquired with similar histories | subsidiary			2

Defined Benefit Pension and O47

Defined Benefit Pension and Other Postretirement Plans - Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$ 3	$ 2.5
Interest cost	6.2	6.6
Expected return on assets	(8.3)	(8)
Amortization of:
Prior service cost (benefit)	0.1	0.1
Actuarial loss	4.1	2.7
Net benefit cost	5.1	3.9
Change in associated regulatory liabilities	0	0
Net expense	5.1	3.9
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	0.2	0.2
Interest cost	0.2	0.2
Expected return on assets	(0.2)	(0.2)
Amortization of:
Prior service cost (benefit)	(0.1)	(0.1)
Actuarial loss	0.1	0
Net benefit cost	0.2	0.1
Change in associated regulatory liabilities	(0.1)	0.9
Net expense	$ 0.1	$ 1

Defined Benefit Pension and O48

Defined Benefit Pension and Other Postretirement Plans - Narrative (Details) - USD ($)	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans
Contribution made to Pension and Post-retirement Plans	$ 2,800,000	$ 2,500,000
Expected contribution to pension plan during remainder of fiscal year	8,500,000
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans
Contribution made to Pension and Post-retirement Plans	$ 0	$ 0

Fair Value Measurements - Finan

Fair Value Measurements - Financial Assets and Liabilities that are Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions		Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		$ 154	$ 72.7	$ 58.4
Derivative financial instruments, liabilities		(68.5)	(105.4)	(177.8)
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	[1]	34.2	33	31.7
Fair Value, Measurements, Recurring | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		124.5	54.9	30.5
Derivative financial instruments, liabilities		(65.5)	(98.6)	(168)
Fair Value, Measurements, Recurring | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		26	17.8	25.4
Derivative financial instruments, liabilities		(0.2)	(2.4)
Fair Value, Measurements, Recurring | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets				0.6
Derivative financial instruments, liabilities		(2.8)	(3.9)	(9.8)
Fair Value, Measurements, Recurring | Cross-currency swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		3.5		1.9
Derivative financial instruments, liabilities			(0.5)
Fair Value, Measurements, Recurring | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	[1]	34.2	33	31.7
Fair Value, Measurements, Recurring | Level 1 | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		62.7	28.9	19.7
Derivative financial instruments, liabilities		(53.1)	(76.8)	(70.5)
Fair Value, Measurements, Recurring | Level 1 | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0	0	0
Derivative financial instruments, liabilities		0	0
Fair Value, Measurements, Recurring | Level 1 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets				0
Derivative financial instruments, liabilities		0	0	0
Fair Value, Measurements, Recurring | Level 1 | Cross-currency swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0		0
Derivative financial instruments, liabilities			0
Fair Value, Measurements, Recurring | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	[1]	0	0	0
Fair Value, Measurements, Recurring | Level 2 | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		61.8	26	10.8
Derivative financial instruments, liabilities		(12.4)	(21.8)	(97.5)
Fair Value, Measurements, Recurring | Level 2 | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		26	17.8	25.4
Derivative financial instruments, liabilities		(0.2)	(2.4)
Fair Value, Measurements, Recurring | Level 2 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets				0.6
Derivative financial instruments, liabilities		(2.8)	(3.9)	(9.8)
Fair Value, Measurements, Recurring | Level 2 | Cross-currency swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		3.5		1.9
Derivative financial instruments, liabilities			(0.5)
Fair Value, Measurements, Recurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments	[1]	0	0	0
Fair Value, Measurements, Recurring | Level 3 | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0	0	0
Derivative financial instruments, liabilities		0	0	0
Fair Value, Measurements, Recurring | Level 3 | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		0	0	0
Derivative financial instruments, liabilities		0	0
Fair Value, Measurements, Recurring | Level 3 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets				0
Derivative financial instruments, liabilities		0	0	0
Fair Value, Measurements, Recurring | Level 3 | Cross-currency swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets		$ 0		$ 0
Derivative financial instruments, liabilities			$ 0
[1]	Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Carrying value of long-term debt	$ 4,083.8	$ 3,832.3	$ 3,609.3
Estimated fair value of long-term debt	$ 4,171	$ 4,052.3	$ 3,590.4

Derivative Instruments and He51

Derivative Instruments and Hedging Activities - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2015	Dec. 31, 2016	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months		$ (3.5)
Amount of net gains associated with currency rate risk to be reclassified into earnings during the next 12 months		15.2
Restricted cash	$ 55.5	$ 7.9	$ 15.6
Loss on ineffectiveness and excluded derivatives recognized in income	$ 3.4

Derivative Instruments and He52

Derivative Instruments and Hedging Activities - Schedule of Notional Amounts (Details) € in Millions, kWh in Millions, gal in Millions, MMBTU in Millions, $ in Millions	Dec. 31, 2016EUR (€)galMMBTUkWh	Dec. 31, 2016USD ($)galMMBTUkWh	Sep. 30, 2016EUR (€)galMMBTUkWh	Sep. 30, 2016USD ($)galMMBTUkWh	Dec. 31, 2015EUR (€)galMMBTUkWh	Dec. 31, 2015USD ($)galMMBTUkWh
Commodity contracts | Electricity | Long
Derivative
Notional amount (in units)	685.5	685.5	761.2	761.2	547.8	547.8
Commodity contracts | Electricity | Short
Derivative
Notional amount (in units)	352.5	352.5	264.6	264.6	252.9	252.9
Commodity contracts | Propane
Derivative
Notional amount (in units) | gal	325.9	325.9	396.9	396.9	481.9	481.9
Natural gas futures, forward and pipeline contracts | Natural Gas
Derivative
Notional amount (in units) | MMBTU	70.2	70.2	71.1	71.1	104.9	104.9
Natural gas basis swap contracts | Natural Gas
Derivative
Notional amount (in units) | MMBTU	120.1	120.1	118.3	118.3	86.1	86.1
NYMEX natural gas and propane storage | Natural Gas
Derivative
Notional amount (in units) | MMBTU	1.3	1.3	1.9	1.9	1.6	1.6
NYMEX natural gas and propane storage | Propane
Derivative
Notional amount (in units) | gal	0	0	0	0	1.8	1.8
FTRs | Electricity
Derivative
Notional amount (in units)	0	0	0	0	51.1	51.1
Interest rate swaps
Derivative
Notional amount | €	€ 645.8		€ 645.8		€ 645.8
IRPAs
Derivative
Notional amount | $		$ 0		$ 0		$ 290
Forward foreign currency exchange contracts
Derivative
Notional amount | $		416.7		314.3		280.5
Cross-currency swaps
Derivative
Notional amount | $		$ 59.1		$ 59.1		$ 59.1
Regulated Utility Operations | Commodity contracts | Natural Gas
Derivative
Notional amount (in units) | MMBTU	11.7	11.7	18.4	18.4	12.4	12.4
Regulated Utility Operations | Commodity contracts | Electricity
Derivative
Notional amount (in units)	0	0	0	0	55.9	55.9
Regulated Utility Operations | FTRs | Electricity
Derivative
Notional amount (in units)	36.2	36.2	58.3	58.3	172.6	172.6

Derivative Instruments and He53

Derivative Instruments and Hedging Activities - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Derivative assets:
Derivative asset, gross	$ 154	$ 72.7	$ 58.4
Gross amounts offset in the balance sheet	(35.7)	(35)	(15.6)
Cash collateral received	(7.1)	(0.3)	0
Total derivative assets — net	111.2	37.4	42.8
Derivative liabilities:
Derivative liability, gross	(68.5)	(105.4)	(177.8)
Gross amounts offset in the balance sheet	35.7	35	15.6
Cash collateral pledged	0	0	5.5
Total derivative liabilities — net	(32.8)	(70.4)	(156.7)
Derivatives designated as hedging instruments
Derivative assets:
Derivative asset, gross	28.1	17.8	27.9
Derivative liabilities:
Derivative liability, gross	(2.8)	(6.8)	(9.8)
Derivatives designated as hedging instruments | Foreign currency contracts
Derivative assets:
Derivative asset, gross	24.6	17.8	25.4
Derivative liabilities:
Derivative liability, gross	0	(2.4)	0
Derivatives designated as hedging instruments | Cross-currency contracts
Derivative assets:
Derivative asset, gross	3.5	0	1.9
Derivative liabilities:
Derivative liability, gross	0	(0.5)	0
Derivatives designated as hedging instruments | Interest rate contracts
Derivative assets:
Derivative asset, gross	0	0	0.6
Derivative liabilities:
Derivative liability, gross	(2.8)	(3.9)	(9.8)
Derivatives subject to PGC and DS mechanisms | Commodity contracts
Derivative assets:
Derivative asset, gross	6.9	4.5	0.2
Derivative liabilities:
Derivative liability, gross	(0.3)	(0.5)	(6.3)
Derivatives not designated as hedging instruments
Derivative assets:
Derivative asset, gross	119	50.4	30.3
Derivative liabilities:
Derivative liability, gross	(65.4)	(98.1)	(161.7)
Derivatives not designated as hedging instruments | Foreign currency contracts
Derivative assets:
Derivative asset, gross	1.4	0	0
Derivative liabilities:
Derivative liability, gross	(0.2)	0	0
Derivatives not designated as hedging instruments | Commodity contracts
Derivative assets:
Derivative asset, gross	117.6	50.4	30.3
Derivative liabilities:
Derivative liability, gross	$ (65.2)	$ (98.1)	$ (161.7)

Derivative Instruments and He54

Derivative Instruments and Hedging Activities - Effects of Derivative Instruments on the Condensed Consolidated Statements of Income and Changes in AOCI (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Derivatives Not Designated as Hedging Instruments
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	$ 109.8	$ (44.7)
Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	18.3	11
Gain (Loss) Reclassified from AOCI into Income	6.6	8.5
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Cost of sales
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	108.5	(46.2)
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Revenues
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	0.1	1.6
Commodity contracts | Derivatives Not Designated as Hedging Instruments | Operating and administrative expenses
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	(0.1)	(0.1)
Foreign currency contracts | Derivatives Not Designated as Hedging Instruments | Gains on foreign currency contracts, net
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in Income	1.3	0
Foreign currency contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	17.2	5.4
Foreign currency contracts | Cash Flow Hedges | Cost of sales
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	7.9	9.1
Cross-currency contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	(0.1)	0
Cross-currency contracts | Cash Flow Hedges | Interest expense/other operating income, net
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	(0.3)	0
Interest rate contracts | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (Loss) Recognized in AOCI	1.2	5.6
Interest rate contracts | Cash Flow Hedges | Interest expense
Derivative Instruments, Gain (Loss)
Gain (Loss) Reclassified from AOCI into Income	$ (1)	$ (0.6)

Accumulated Other Comprehensi55

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	$ 3,601.8
Other comprehensive income (loss) before reclassification adjustments (after-tax)	(58.6)	$ (23.4)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	(5)	(7.8)
Reclassification adjustments tax (expense) benefit	1.5	2.9
Reclassification adjustments (after-tax)	(3.5)	(4.9)
Other comprehensive income (loss) attributable to UGI	(62.1)	(28.3)
Balance, end of period	3,733.1	3,592.5
Postretirement Benefit Plans
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(29.1)	(20.4)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	0	0
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	1.6	0.7
Reclassification adjustments tax (expense) benefit	(0.6)	(0.3)
Reclassification adjustments (after-tax)	1	0.4
Other comprehensive income (loss) attributable to UGI	1	0.4
Balance, end of period	(28.1)	(20)
Derivative Instruments
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(13.4)	11.2
Other comprehensive income (loss) before reclassification adjustments (after-tax)	12.3	6.8
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	(6.6)	(8.5)
Reclassification adjustments tax (expense) benefit	2.1	3.2
Reclassification adjustments (after-tax)	(4.5)	(5.3)
Other comprehensive income (loss) attributable to UGI	7.8	1.5
Balance, end of period	(5.6)	12.7
Foreign Currency
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(112.2)	(105.4)
Other comprehensive income (loss) before reclassification adjustments (after-tax)	(70.9)	(30.2)
Amounts reclassified from AOCI:
Reclassification adjustments (pre-tax)	0	0
Reclassification adjustments tax (expense) benefit	0	0
Reclassification adjustments (after-tax)	0	0
Other comprehensive income (loss) attributable to UGI	(70.9)	(30.2)
Balance, end of period	(183.1)	(135.6)
Total
AOCI Attributable to Parent, Net of Tax
Balance, beginning of period	(154.7)	(114.6)
Amounts reclassified from AOCI:
Balance, end of period	$ (216.8)	$ (142.9)

Segment Information - Narrative

Segment Information - Narrative (Details)	3 Months Ended
	Dec. 31, 2016segment
Segment Reporting [Abstract]
Number of reportable segments	4

Segment Information - Schedule

Segment Information - Schedule of Segment Reporting Information (Details) - USD ($) $ in Millions		3 Months Ended
		Dec. 31, 2016	Dec. 31, 2015		Sep. 30, 2016
Segment Reporting Information
Revenues		$ 1,679.5	$ 1,606.6	[1]
Cost of sales		647.4	734	[1]
Segment profit:
Operating income (loss)		466.2	305.5	[1]
Loss from equity investees		(0.2)	(0.1)	[1]
Gains on foreign currency contracts, net		1.3	0
Loss on extinguishment of debt		(33.2)	0
Interest expense		(55.4)	(57.9)	[1]
Income before income taxes		378.7	247.5	[1]
Noncontrolling interests’ net income (loss)		60.2	53.3	[1]
Depreciation and amortization		98.1	100.6	[1]
Capital expenditures (including the effects of accruals)		173.6	132.9	[1]
Total assets		11,300.5	10,749.7	[1]	$ 10,847.2
Short-term borrowings		234.4	456.8	[1]	291.7
Goodwill		2,935.8	2,965.1	[1]	$ 2,989
Eliminations
Segment Reporting Information
Revenues	[2]	(68.5)	(42.7)	[1]
Cost of sales	[2]	(67.7)	(41.8)	[1]
Segment profit:
Operating income (loss)		0.1	0.1	[1]
Loss from equity investees		0	0	[1]
Gains on foreign currency contracts, net		0
Loss on extinguishment of debt		0
Interest expense		0	0	[1]
Income before income taxes		0.1	0.1	[1]
Noncontrolling interests’ net income (loss)		0	0	[1]
Depreciation and amortization		0	0	[1]
Capital expenditures (including the effects of accruals)		0	0	[1]
Total assets		(107.9)	(106.2)	[1]
Short-term borrowings		0	0	[1]
Goodwill		0	0	[1]
Operating Segments | AmeriGas Propane
Segment Reporting Information
Revenues		677.2	644.1	[1]
Cost of sales		260.7	243.2	[1]
Segment profit:
Operating income (loss)		141.9	129.6	[1]
Loss from equity investees		0	0	[1]
Gains on foreign currency contracts, net		0
Loss on extinguishment of debt		(33.2)	0
Interest expense		(40)	(41)	[1]
Income before income taxes		68.7	88.6	[1]
Partnership Adjusted EBITDA	[3]	185.1	177.7	[1]
Noncontrolling interests’ net income (loss)		41.2	57.3	[1]
Depreciation and amortization		44.6	49.2	[1]
Capital expenditures (including the effects of accruals)		26.4	28	[1]
Total assets		4,217.9	4,222.1	[1]
Short-term borrowings		77.5	182	[1]
Goodwill		1,978.5	1,971.3	[1]
Operating Segments | UGI International
Segment Reporting Information
Revenues		539.1	578.2	[1]
Cost of sales		258	302.8	[1]
Segment profit:
Operating income (loss)		88.9	85.1	[1]
Loss from equity investees		(0.2)	(0.1)	[1]
Gains on foreign currency contracts, net		0.1
Loss on extinguishment of debt		0
Interest expense		(4.8)	(6.5)	[1]
Income before income taxes		84	78.5	[1]
Noncontrolling interests’ net income (loss)		0.2	0.1	[1]
Depreciation and amortization		27.9	27.2	[1]
Capital expenditures (including the effects of accruals)		21.5	21	[1]
Total assets		2,853.4	2,905.8	[1]
Short-term borrowings		3.5	1.1	[1]
Goodwill		763.7	800.2	[1]
Operating Segments | Midstream & Marketing
Segment Reporting Information
Revenues		269.8	226.9	[1]
Cost of sales		191.8	154.5	[1]
Segment profit:
Operating income (loss)		49.7	42.9	[1]
Loss from equity investees		0	0	[1]
Gains on foreign currency contracts, net		0
Loss on extinguishment of debt		0
Interest expense		(0.6)	(0.8)	[1]
Income before income taxes		49.1	42.1	[1]
Noncontrolling interests’ net income (loss)		0	0	[1]
Depreciation and amortization		8	7.4	[1]
Capital expenditures (including the effects of accruals)		61.5	22.4	[1]
Total assets		1,178.4	1,000	[1]
Short-term borrowings		55	56	[1]
Goodwill		11.5	11.5	[1]
Operating Segments | UGI Utilities
Segment Reporting Information
Revenues		261.4	198	[1]
Cost of sales		109.5	75.4	[1]
Segment profit:
Operating income (loss)		82.2	48.3	[1]
Loss from equity investees		0	0	[1]
Gains on foreign currency contracts, net		0
Loss on extinguishment of debt		0
Interest expense		(10)	(9.5)	[1]
Income before income taxes		72.2	38.8	[1]
Noncontrolling interests’ net income (loss)		0	0	[1]
Depreciation and amortization		17.4	16.7	[1]
Capital expenditures (including the effects of accruals)		64.1	61.5	[1]
Total assets		2,898.5	2,604.2	[1]
Short-term borrowings		98.4	217.7	[1]
Goodwill		182.1	182.1	[1]
Corporate & Other
Segment Reporting Information
Revenues	[4]	0.5	2.1	[1]
Cost of sales	[4]	(104.9)	(0.1)	[1]
Segment profit:
Operating income (loss)	[4]	103.4	(0.5)	[1]
Loss from equity investees	[4]	0	0	[1]
Gains on foreign currency contracts, net		1.2
Loss on extinguishment of debt	[4]	0
Interest expense	[4]	0	(0.1)	[1]
Income before income taxes	[4]	104.6	(0.6)	[1]
Noncontrolling interests’ net income (loss)	[4]	18.8	(4.1)	[1]
Depreciation and amortization	[4]	0.2	0.1	[1]
Capital expenditures (including the effects of accruals)	[4]	0.1	0	[1]
Total assets	[4]	260.2	123.8	[1]
Short-term borrowings	[4]	0	0	[1]
Goodwill	[4]	0	0	[1]
Gains (losses) on unsettled commodity derivative instruments, net		$ 105.5	$ 1.1
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI International and Midstream & Marketing reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2).
[2]	Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.
[3]	The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: Three Months EndedDecember 31, 2016 2015Partnership Adjusted EBITDA $185.1 $177.7Depreciation and amortization (44.6) (49.2)Interest expense (40.0) (41.0)Loss on extinguishment of debt (33.2) —Noncontrolling interest (i) 1.4 1.1Income before income taxes $68.7 $88.6(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
[4]	Corporate & Other results principally comprise (1) net expenses of UGI’s captive general liability insurance company and UGI’s corporate headquarters facility, and (2) UGI’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains on commodity and certain foreign currency derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $105.5 and $1.1 during the three months ended December 31, 2016 and 2015, respectively. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company; UGI corporate headquarters’ assets; and our investment in a private equity partnership.

Segment Information - Reconcili

Segment Information - Reconciliation of Partnership Adjusted EBITDA (Details) - USD ($) $ in Millions		3 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information
Depreciation and amortization		$ (98.1)	$ (100.6)	[1]
Interest expense		(55.4)	(57.9)	[1]
Loss on extinguishment of debt		(33.2)	0
Income before income taxes		$ 378.7	$ 247.5	[1]
General Partnership interest in AmeriGas OLP (percentage)		1.01%	1.01%
Operating Segments | Amerigas Propane
Segment Reporting Information
Partnership Adjusted EBITDA	[2]	$ 185.1	$ 177.7	[1]
Depreciation and amortization		(44.6)	(49.2)	[1]
Interest expense		(40)	(41)	[1]
Loss on extinguishment of debt		(33.2)	0
Noncontrolling interest	[3]	1.4	1.1
Income before income taxes		$ 68.7	$ 88.6	[1]
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI International and Midstream & Marketing reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2).
[2]	The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: Three Months EndedDecember 31, 2016 2015Partnership Adjusted EBITDA $185.1 $177.7Depreciation and amortization (44.6) (49.2)Interest expense (40.0) (41.0)Loss on extinguishment of debt (33.2) —Noncontrolling interest (i) 1.4 1.1Income before income taxes $68.7 $88.6(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
[3]	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.