UGI (UGI) 10-Q 6 Feb 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Dec. 31, 2014	Jan. 31, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	UGI CORP /PA/
Entity Central Index Key	884614
Document Type	10-Q
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	-21
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		172,787,331

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (unaudited) (USD $)	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Current assets:
Cash and cash equivalents	$410.10	$419.50	$418.10
Restricted cash	54.6	16.6	4.5
Accounts receivable (less allowances for doubtful accounts of $37.9, $39.1 and $43.8, respectively)	960.6	684.7	1,204
Accrued utility revenues	52.7	14.3	66.4
Inventories	391	423	412.4
Deferred income taxes	46.1	10.1	23
Utility regulatory assets	16.8	13.2	0.4
Derivative instruments	19.7	14.5	51.6
Prepaid expenses and other current assets	88	67.1	47.1
Total current assets	2,039.60	1,663	2,227.50
Property, plant and equipment, at cost (less accumulated depreciation and amortization of $2,664.2, $2,633.0 and $2,630.9, respectively)	4,552.70	4,543.70	4,517.10
Goodwill	2,806.80	2,833.40	2,884.50
Intangible assets, net	563.7	576.4	598.8
Derivative instruments	16.1	12.5	2.2
Other assets	451.1	464	433.4
Total assets	10,430	10,093	10,663.50
Current liabilities:
Current maturities of long-term debt	147.1	77.2	67.2
Short-term borrowings	458.5	210.8	421.5
Accounts payable	556.5	459.8	691.4
Derivative instruments	157	40.2	20.8
Other current liabilities	649.7	642.9	678.6
Total current liabilities	1,968.80	1,430.90	1,879.50
Long-term debt	3,341.20	3,433.60	3,549.10
Deferred income taxes	976.3	1,005.10	980.2
Deferred investment tax credits	3.8	3.9	4.2
Derivative instruments	39.9	16.6	22.4
Other noncurrent liabilities	545.3	539.7	509.4
Total liabilities	6,875.30	6,429.80	6,944.80
Commitments and contingencies (Note 8)
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized—450,000,000 shares; issued—173,772,391, 173,770,641 and 173,675,691 shares, respectively)	1,215.70	1,215.60	1,210
Retained earnings	1,506	1,509.40	1,397.90
Accumulated other comprehensive (loss) income	-40.1	-21.2	32.2
Treasury stock, at cost	-35.3	-44.7	-30.5
Total UGI Corporation stockholders’ equity	2,646.30	2,659.10	2,609.60
Noncontrolling interests, principally in AmeriGas Partners	908.4	1,004.10	1,109.10
Total equity	3,554.70	3,663.20	3,718.70
Total liabilities and equity	$10,430	$10,093	$10,663.50

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) (USD $)	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]
Accounts receivable, allowances for doubtful accounts	$37.90	$39.10	$43.80
Property, plant and equipment, accumulated depreciation and amortization	$2,664.20	$2,633	$2,630.90
UGI Common Stock, without par value (in shares)
UGI Common Stock, without par value, shares authorized (in shares)	450,000,000	450,000,000	450,000,000
UGI Common Stock, without par value, shares issued (in shares)	173,772,391	173,770,641	173,675,691

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Income (unaudited) (USD $)	3 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Revenues	$2,004.60	$2,315.90
Costs and expenses:
Cost of sales (excluding depreciation shown below)	1,404.60	1,429.90
Operating and administrative expenses	435.7	431.5
Utility taxes other than income taxes	4.1	4.2
Depreciation	75.8	78.6
Amortization	15.2	15.4
Other operating income, net	-14.1	-7.4
Total costs and expenses	1,921.30	1,952.20
Operating income	83.3	363.7
Loss from equity investees	-1	0
Interest expense	-59	-59.3
Income before income taxes	23.3	304.4
Income tax expense	-23.1	-86.9
Net income	0.2	217.5
Add net loss (deduct net income) attributable to noncontrolling interests, principally in AmeriGas Partners	33.9	-95.5
Net income attributable to UGI Corporation	$34.10	$122
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)	$0.20	$0.71
Diluted (in dollars per share)	$0.19	$0.70
Average common shares outstanding (thousands):
Basic (in shares)	172,945	172,238
Diluted (in shares)	175,786	174,705
Dividends declared per common share (in dollars per share)	$0.22	$0.19

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Comprehensive Income (unaudited) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income	$0.20	$217.50
Other comprehensive income (loss):
Net gains on derivative instruments (net of tax of $(3.9) and $(7.5), respectively)	7.7	40.5
Reclassifications of net losses (gains) on derivative instruments (net of tax of $(1.5) and $2.0, respectively)	2.1	-13.8
Foreign currency adjustments (net of tax of $15.6 and $(3.7), respectively)	-30.5	12.3
Benefit plans (net of tax of $(0.4) and $0.1, respectively)	0.6	0.4
Other comprehensive (loss) income	-20.1	39.4
Comprehensive (loss) income	-19.9	256.9
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	35	-111.1
Comprehensive income attributable to UGI Corporation	$15.10	$145.80

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Tax on (loss) gain on derivative instruments	($3.90)	($7.50)
Tax on reclassification on derivative instruments	-1.5	2
Tax on foreign currency adjustments	15.6	-3.7
Tax on benefit plans	($0.40)	$0.10

Condensed_Consolidated_Stateme3

Condensed Consolidated Statements of Cash Flows (unaudited) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$0.20	$217.50
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	91	94
Deferred income tax benefit, net	-59.8	-19.7
Provision for uncollectible accounts	7	8.9
Unrealized losses (gains) on derivative instruments	229.7	-5.2
Other, net	-0.9	0.8
Net change in:
Accounts receivable and accrued utility revenues	-341.8	-508.2
Inventories	27.6	-45.1
Utility deferred fuel and power costs, net of changes in unsettled derivatives	4.4	2.1
Accounts payable	119.3	245.9
Collateral deposits	-90.9	0
Other current assets	-14.9	5.2
Other current liabilities	48.1	76.7
Net cash provided by operating activities	19	72.9
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	-132.1	-133.1
Acquisitions of businesses, net of cash acquired	-7.2	-20.8
(Increase) decrease in restricted cash	-38	3.8
Other, net	7	1.3
Net cash used by investing activities	-170.3	-148.8
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	-37.5	-32.4
Distributions on AmeriGas Partners publicly held Common Units	-60.8	-58
Repayments of debt	-2.6	-4.1
Increase in short-term borrowings	213	188.2
Receivables Facility net borrowings	35.5	5.5
Issuances of UGI Common Stock	5.5	1.7
Other	-3.3	0.2
Net cash provided by financing activities	149.8	101.1
EFFECT OF EXCHANGE RATE CHANGES ON CASH	-7.9	3.6
Cash and cash equivalents (decrease) increase	-9.4	28.8
Cash and cash equivalents:
End of period	410.1	418.1
Beginning of period	419.5	389.3
(Decrease) increase	($9.40)	$28.80

Condensed_Consolidated_Stateme4

Condensed Consolidated Statements of Changes in Equity (unaudited) (USD $)	Total	Parent	Common Stock, Without Par Value	Retained Earnings	Accumulated Other Comprehensive (Loss) Income	Treasury Stock	Noncontrolling Interests
In Millions, unless otherwise specified
Balance, beginning of period at Sep. 30, 2013			$1,208.10	$1,308.30	$8.40	($32.30)	$1,055.40
Increase (Decrease) in Stockholders' Equity
Common Stock issued in connection with employee and director plans (including (losses) gains on treasury stock transactions), net of tax withheld			0.2
Common stock issued in connection with employee and director plans, net of tax withheld						1.9
Excess tax benefits realized on equity-based compensation			0.3
Equity-based compensation expense			1.4
Net income attributable to UGI Corporation	122			122
Cash dividends on Common Stock				-32.4
Net gains on derivative instruments, net of tax	40.5				15.3
Reclassification of net losses (gains) on derivative instruments, net of tax	-13.8				-4.2
Benefit plans (net of tax of $(0.4) and $0.1, respectively)	0.4				0.4
Foreign currency, net of tax	12.3				12.3
Reacquired common stock - employee and director plans						-0.1
Net (loss) income attributable to noncontrolling interests, principally in AmeriGas Partners	95.5						95.5
Net gains on derivative instruments							25.2
Reclassification of net gains on derivative instruments							-9.6
Dividends and distributions							-58
Other							0.6
Balance, end of period at Dec. 31, 2013	3,718.70	2,609.60	1,210	1,397.90	32.2	-30.5	1,109.10
Balance, beginning of period at Sep. 30, 2014	3,663.20		1,215.60	1,509.40	-21.2	-44.7	1,004.10
Increase (Decrease) in Stockholders' Equity
Common Stock issued in connection with employee and director plans (including (losses) gains on treasury stock transactions), net of tax withheld			-3.9
Common stock issued in connection with employee and director plans, net of tax withheld						9.8
Excess tax benefits realized on equity-based compensation			1.8
Equity-based compensation expense			2.2
Net income attributable to UGI Corporation	34.1			34.1
Cash dividends on Common Stock				-37.5
Net gains on derivative instruments, net of tax	7.7				7.7
Reclassification of net losses (gains) on derivative instruments, net of tax	2.1				3.3
Benefit plans (net of tax of $(0.4) and $0.1, respectively)	0.6				0.6
Foreign currency, net of tax	-30.5				-30.5
Reacquired common stock - employee and director plans						-0.4
Net (loss) income attributable to noncontrolling interests, principally in AmeriGas Partners	-33.9						-33.9
Net gains on derivative instruments							0
Reclassification of net gains on derivative instruments							-1.2
Dividends and distributions							-60.8
Other							0.2
Balance, end of period at Dec. 31, 2014	$3,554.70	$2,646.30	$1,215.70	$1,506	($40.10)	($35.30)	$908.40

Nature_of_Operations

Nature of Operations	3 Months Ended
	Dec. 31, 2014
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 and China. We refer to UGI and its consolidated subsidiaries collectively as “the Company” or “we.”
	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”), which is referred to herein as the “Operating Partnership.” 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, 2014, the General Partner held a 1% general partner interest and 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 23,756,882 AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises 69,117,556 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 15 of our Annual Report on Form 10-K for the fiscal year ended September 30, 2014 (the “Company’s 2014 Annual Report”). Incentive distributions received by the General Partner during the three months ended December 31, 2014 and 2013 were $6.5 and $5.4, respectively.
	Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“Antargaz”); (2)  an LPG distribution business in central, northern and eastern Europe (“Flaga”); (3) an LPG distribution business in the United Kingdom (“AvantiGas”); and (4) an LPG distribution business in the Nantong region of China. We refer to our foreign LPG operations collectively as “UGI International.”
	Enterprises, through UGI Energy Services, LLC and its subsidiaries, conducts an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business primarily in the Mid-Atlantic and Northeast U.S. In addition, UGI Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. These businesses are referred to herein collectively as “Midstream & Marketing.” UGI Energy Services, LLC is referred to herein as “Energy Services.” Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region through first-tier subsidiaries.
	Our natural gas distribution utility business (“Gas Utility”) is conducted through our wholly owned subsidiary, UGI Utilities, Inc. (“UGI Utilities”), and its 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. Gas Utility and Electric Utility are collectively referred to as “Utilities.”

Summary_of_Significant_Account

Summary of Significant Accounting Policies	3 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2 — Summary of Significant Accounting Policies
	Our condensed consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the public’s limited partner interests in the Partnership, and outside ownership interests in other consolidated but less than 100%-owned subsidiaries, as noncontrolling interests. We eliminate intercompany accounts and transactions when we consolidate. Entities in which we do not have control but have significant influence over operating and financial policies are accounted for by the equity method. Investments in business entities that are not publicly traded and in which we hold less than 20% of voting rights are accounted for using the cost method. Undivided interests in natural gas production assets and an electricity generation facility are consolidated on a proportionate basis.
	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, 2014, 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 2014 Annual Report. Due to the seasonal nature of our businesses, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.
	Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
	Shares used in computing basic and diluted earnings per share are as follows:
		Three Months Ended
		December 31,
		2014	2013
	Denominator (thousands of shares):
	Average common shares outstanding for basic computation	172,945	172,238
	Incremental shares issuable for stock options and awards	2,841	2,467
	Average common shares outstanding for diluted computation	175,786	174,705
	Derivative Instruments. Derivative instruments are reported in the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exemption 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 or net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (“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 the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on certain commodity derivative instruments used by Gas Utility and Electric Utility are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers.
	Effective October 1, 2014, UGI International determined that on a prospective basis it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Midstream & Marketing has not applied cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues. For additional information on our derivative instruments, see Note 11.
	Reclassifications. Certain prior period amounts have been reclassified to conform to current period presentation.
	Consolidated Effective Income Tax Rate. UGI’s consolidated effective income tax rate, defined as total income tax (expense) or benefit 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. 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.

Accounting_Changes

Accounting Changes	3 Months Ended
	Dec. 31, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Changes	Note 3 — Accounting Changes
	Accounting Standards Not Yet Adopted
	Extraordinary Items. In January 2015, the Financial Accounting Standards Board (“FASB”) issued new accounting guidance which eliminates the concept of an extraordinary item. Under current accounting guidance, to be considered an extraordinary item an event or transaction must be both unusual in nature and must occur infrequently. Under the new guidance, the concept of an extraordinary item has been eliminated. As a result, an entity will no longer be permitted to segregate an extraordinary item from its results of operations; present an extraordinary item, net of tax, after income from continuing operations; or disclose earnings per share data applicable to an extraordinary item. The new guidance does not affect, however, the reporting and disclosure requirements for an event that is unusual in nature or that occurs infrequently. The guidance is effective for annual periods beginning after December 31, 2015 and interim periods within those annual periods. Early adoption is permitted. Entities may apply the guidance prospectively or retrospectively. If an entity chooses to apply the new guidance prospectively, it must disclose whether amounts included in income from continuing operations include items that would have qualified as extraordinary items previously. We expect to adopt the new guidance in Fiscal 2017.
	Revenue Recognition. In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers.” This ASU supersedes the revenue recognition requirements in Accounting Standards Codification (“ASC”) 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 company expects to be entitled in exchange for those goods or services. This standard is effective for the Company beginning in Fiscal 2018 and allows for either full retrospective adoption or modified retrospective adoption. The Company is in the process of assessing the impact of the adoption of ASU 2014-09 on its results of operations, cash flows and financial position.

Inventories

Inventories	3 Months Ended
	Dec. 31, 2014
Inventory Disclosure [Abstract]
Inventories	Note 4 — Inventories
	Inventories comprise the following:
		December 31,		September 30,		December 31,
		2014		2014		2013
	Non-utility LPG and natural gas	$	260.4	$	283.6	$	282.9
	Gas Utility natural gas	72.4		82.7		69.1
	Materials, supplies and other	58.2		56.7		60.4
	Total inventories	$	391	$	423	$	412.4
	At December 31, 2014, UGI Utilities is a party to four principal storage contract administrative agreements (“SCAAs”) having terms of 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, 2014, UGI Utilities has SCAAs with Energy Services and a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with non-affiliates at December 31, 2014, September 30, 2014 and December 31, 2013, comprising 3.4 billion cubic feet (“bcf”), 3.9 bcf and 3.1 bcf of natural gas, was $14.4, $16.8 and $12.3, respectively.

Goodwill_and_Intangible_Assets

Goodwill and Intangible Assets	3 Months Ended
	Dec. 31, 2014
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,
		2014			2014			2013
	Goodwill (not subject to amortization)	$	2,806.80		$	2,833.40		$	2,884.50
	Intangible assets:
	Customer relationships, noncompete agreements and other	$	709.3		$	712		$	709.6
	Accumulated amortization	(271.9		)	(263.8		)	(243.0		)
	Intangible assets, net (definite-lived)	437.4			448.2			466.6
	Trademarks and tradenames (indefinite-lived)	126.3			128.2			132.2
	Total intangible assets, net	$	563.7		$	576.4		$	598.8
	The decrease in goodwill and intangible assets at December 31, 2014, includes the effects of currency translation. Amortization expense of intangible assets was $13.0 and $13.3 for the three months ended December 31, 2014 and 2013, respectively. Amortization expense included in cost of sales in the Condensed Consolidated Statements of Income is not material. The estimated aggregate amortization expense of intangible assets for the remainder of Fiscal 2015 and for the next four fiscal years is as follows: remainder of Fiscal 2015 — $38.6; Fiscal 2016 — $44.9; Fiscal 2017 — $38.3; Fiscal 2018 — $36.6; Fiscal 2019 — $35.0.

Utility_Regulatory_Assets_and_

Utility Regulatory Assets and Liabilities and Regulatory Matters	3 Months Ended
	Dec. 31, 2014
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 9 in the Company’s 2014 Annual Report. UGI Utilities does not recover a rate of return on its regulatory assets. The following regulatory assets and liabilities associated with Utilities are included in our accompanying Condensed Consolidated Balance Sheets:
		December 31,		September 30,		December 31,
		2014		2014		2013
	Regulatory assets (a):
	Income taxes recoverable	$	111.1	$	110.7	$	106.4
	Underfunded pension and postretirement plans	107.8		110.1		92.8
	Environmental costs	14.7		14.6		14.9
	Deferred fuel and power costs	16.7		11.8		0.4
	Removal costs, net	17.6		16.8		13.7
	Other	2.7		4.2		5.7
	Total regulatory assets	$	270.6	$	268.2	$	233.9
	Regulatory liabilities (a):
	Postretirement benefits	$	19	$	18.6	$	16.8
	Environmental overcollections	0.2		0.3		2.3
	Deferred fuel and power refunds	—		0.3		7.5
	State tax benefits—distribution system repairs	10.3		10.1		8.7
	Other	3.4		3.2		1.3
	Total regulatory liabilities	$	32.9	$	32.5	$	36.6
	(a) Noncurrent regulatory assets are recorded in other assets and regulatory liabilities are recorded in other current and other noncurrent liabilities in the Condensed Consolidated Balance Sheets.
	Deferred fuel and power—costs and refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses which 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, 2014, September 30, 2014 and December 31, 2013 were $(6.8), $(1.4) and $2.0, respectively.
	Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. Because we have chosen not to elect the NPNS exception under GAAP related to these derivative instruments, these electricity supply contracts are recognized on the balance sheet at fair value with an associated adjustment to regulatory assets or liabilities because Electric Utility is entitled to fully recover its DS costs. At December 31, 2014, September 30, 2014, and December 31, 2013, the fair values of Electric Utility’s electricity supply contracts were gains (losses) of $(2.4), $0.3 and $(3.2), respectively. These amounts are reflected in current derivative assets and current derivative liabilities on the Condensed Consolidated Balance Sheets with equal and offsetting amounts reflected in deferred fuel and power costs and refunds in the table above.
	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, 2014, September 30, 2014, and December 31, 2013, were not material.

Energy_Services_Accounts_Recei

Energy Services Accounts Receivable Securitization Facility	3 Months Ended
	Dec. 31, 2014
Transfers and Servicing of Financial Assets [Abstract]
Energy Services Accounts Receivable Securitization Facility	Note 7 — Energy Services Accounts Receivable Securitization Facility
	Energy Services has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2015. The Receivables Facility provides Energy Services with the ability to borrow up to $150 of eligible receivables during the period November to May and up to $75 of eligible receivables during the period June to October. Energy Services uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes.
	Under the Receivables Facility, Energy Services transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, 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. ESFC was created and has been structured to isolate its assets from creditors of Energy Services and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank or the commercial paper conduit. The Company records interest expense on amounts owed to the bank or the commercial paper conduit. Energy Services continues to service, administer and collect trade receivables on behalf of the bank or commercial paper issuer, as applicable.
	During the three months ended December 31, 2014 and 2013, Energy Services transferred trade receivables to ESFC totaling $286.4 and $269.0, respectively. During the three months ended December 31, 2014 and 2013, ESFC sold an aggregate $105.0 and $92.0, respectively, of undivided interests in its trade receivables to the bank. At December 31, 2014, the outstanding balance of ESFC receivables was $96.5 of which $43.0 was sold to the bank. At December 31, 2013, the outstanding balance of ESFC receivables was $88.5 of which $35.5 was sold to the bank. Losses on sales of receivables to the bank during the three months ended December 31, 2014 and 2013, which are included in interest expense on the Condensed Consolidated Statements of Income, were not material.

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 8 — Commitments and Contingencies
	Environmental Matters
	UGI Utilities
	CPG is party to a Consent Order and Agreement (“CPG-COA”) with the Pennsylvania Department of Environmental Protection (“DEP”) requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which manufactured gas plant (“MGP”) related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1, respectively, in any calendar year. The CPG-COA is scheduled to terminate at the end of 2018. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two-year period beginning with the original effective date in March 2004. At December 31, 2014 and 2013, our accrued liabilities for environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11.2 and $12.1, respectively. We have recorded associated regulatory assets in equal amounts because recovery of these costs from CPG customers is probable.
	From the late 1800s through the mid-1900s, UGI Utilities and its former subsidiaries owned and operated a number of MGPs prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. Pursuant to the requirements of the Public Utility Holding Company Act of 1935, 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 does not expect its costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to its results of operations because (1) UGI Gas is currently permitted to include in rates, through future base rate proceedings, a five-year average of such prudently incurred remediation costs and (2) CPG and PNG are currently receiving regulatory recovery of estimated environmental investigation and remediation costs associated with Pennsylvania sites. At December 31, 2014, neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Gas was material.
	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.
	Other Matters
	Federal Trade Commission Investigation of Propane Grill Cylinder Filling Practices. On or about November 4, 2011, the General Partner received notice that the Federal Trade Commission (“FTC”) had initiated an antitrust and consumer protection investigation into certain practices of the Partnership relating to the filling of portable propane cylinders. On February 2, 2012, the Partnership received a Civil Investigative Demand from the FTC that requested documents and information concerning, among other things, (i) the Partnership’s decision, in 2008, to reduce the volume of propane in cylinders it sells to consumers from 17 pounds to 15 pounds, and (ii) cross-filling, related service arrangements and communications regarding the foregoing with competitors. The Partnership responded to that subpoena and cooperated with subsequent requests for information. On March 27, 2014, the FTC issued an administrative complaint against the Partnership and UGI alleging that the General Partner and one of its competitors colluded in 2008 to persuade its common customer, Walmart Stores, Inc., to accept the cylinder fill reduction from 17 pounds to 15 pounds.  The complaint does not seek monetary remedies.  The Partnership and UGI filed their answer to the complaint on April 18, 2014.  On August 25, 2014, the parties entered into an Agreement Containing Consent Orders, and on August 27, 2014, the FTC issued an Order Withdrawing Matter from Adjudication for the Purpose of Considering a Proposed Consent Agreement. The consent agreement was accepted by the FTC on October 31, 2014. Following a public comment period, the FTC on January 7, 2015 approved a final order settling the charges.  The order sets forth the conditions of settlement between the parties and concludes the FTC’s investigation.
	Purported Class Action Lawsuits.  Following the issuance of the FTC’s administrative complaint described above, more than 35 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 and combined to persuade its 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 Western District of Missouri.  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 consolidated financial position, results of operations or cash flows.

Defined_Benefit_Pension_and_Ot

Defined Benefit Pension and Other Postretirement Plans	3 Months Ended
	Dec. 31, 2014
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Defined Benefit Pension and Other Postretirement Plans	Note 9 — 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, Antargaz 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,	2014			2013			2014			2013
	Service cost	$	2.4		$	2.3		$	0.2		$	0.1
	Interest cost	6.3			6.4			0.2			0.2
	Expected return on assets	(7.9		)	(7.3		)	(0.2		)	(0.1		)
	Amortization of:
	Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.1		)
	Actuarial loss	2.5			1.9			—			—
	Net benefit cost	3.4			3.4			0.1			0.1
	Change in associated regulatory liabilities	—			—			0.9			0.9
	Net expense	$	3.4		$	3.4		$	1		$	1
	The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and 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, 2014 and 2013, the Company made cash contributions to the U.S. Pension Plan of $2.8 and $3.5, respectively. The Company expects to make additional discretionary cash contributions of $8.3 to the U.S. Pension Plan during the remainder of Fiscal 2015.
	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, 2014 and 2013.
	We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans (“Supplemental Defined Benefit Plans”). We recorded pre-tax expense associated with these plans of $0.7 and $0.8 in the three months ended December 31, 2014 and 2013, respectively.

Fair_Value_Measurements

Fair Value Measurements	3 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 10 — 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, 2014, September 30, 2014 and December 31, 2013:
			Asset (Liability)
			Level 1			Level 2			Level 3		Total
	December 31, 2014:
	Derivative instruments:
	Assets:
	Commodity contracts		$	14.1		$	26.1		$	—	$	40.2
	Foreign currency contracts		$	—		$	18.7		$	—	$	18.7
	Interest rate contracts		$	—		$	0.1		$	—	$	0.1
	Cross-currency swaps		$	—		$	4.3		$	—	$	4.3
	Liabilities:
	Commodity contracts		$	(69.4	)	$	(228.5	)	$	—	$	(297.9	)
	Interest rate contracts		$	—		$	(17.0	)	$	—	$	(17.0	)
	Non-qualified supplemental postretirement grantor trust investments (a)		$	31.4		$	—		$	—	$	31.4
	September 30, 2014:
	Derivative instruments:
	Assets:
	Commodity contracts		$	10.6		$	19.8		$	—	$	30.4
	Foreign currency contracts		$	—		$	12.8		$	—	$	12.8
	Interest rate contracts		$	—		$	0.1		$	—	$	0.1
	Cross-currency swaps		$	—		$	2.1		$	—	$	2.1
	Liabilities:
	Commodity contracts		$	(21.2	)	$	(32.9	)	$	—	$	(54.1	)
	Foreign currency contracts		$	—		$	(0.1	)	$	—	$	(0.1	)
	Interest rate contracts		$	—		$	(21.0	)	$	—	$	(21.0	)
	Non-qualified supplemental postretirement grantor trust investments (a)		$	30		$	—		$	—	$	30
	December 31, 2013 (b):
	Derivative instruments:
	Assets:
	Commodity contracts		$	9.8		$	49.6		$	—	$	59.4
	Foreign currency contracts		$	—		$	0.4		$	—	$	0.4
	Liabilities:
	Commodity contracts		$	(6.1	)	$	(4.6	)	$	—	$	(10.7	)
	Foreign currency contracts		$	—		$	(7.2	)	$	—	$	(7.2	)
	Interest rate contracts		$	—		$	(29.2	)	$	—	$	(29.2	)
	Cross-currency swaps		$	—		$	(2.1	)	$	—	$	(2.1	)
	Non-qualified supplemental postretirement grantor trust investments (a)		$	30.3		$	—		$	—	$	30.3
	(a)	Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.
	(b)	Certain immaterial amounts have been revised to correct the classification of derivatives.
	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 which 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 and foreign currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. 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, 2014, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,488.3 and $3,640.7, respectively. At December 31, 2013, the carrying amount and estimated fair value of our long-term debt (including current maturities) were $3,616.3 and $3,856.9, 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 our short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit our 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 which extends across many different U.S. markets and several foreign countries. For information regarding concentrations of credit risk associated with our derivative instruments, see Note 11. 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_Hed

Derivative Instruments and Hedging Activities	3 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Disclosures About Derivative Instruments and Hedging Activities	Note 11 — 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.
	Commodity Price Risk
	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 business units 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. In addition, the Partnership from time to time enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility. At December 31, 2014 and 2013, total volumes associated with LPG commodity derivative instruments totaled 429.6 million gallons and 215.2 million gallons, respectively. At December 31, 2014, the maximum period over which we are economically hedging our exposure to LPG commodity price risk is 33 months.
	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. At December 31, 2014 and 2013, the volumes of natural gas associated with Gas Utility’s unsettled NYMEX natural gas futures and option contracts totaled 11.2 million dekatherms and 9.7 million dekatherms, respectively. At December 31, 2014, the maximum period over which Gas Utility is economically hedging natural gas market price risk is 9 months. Gains and losses on natural gas futures contracts and any gains on 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).
	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. Because we have chosen not to elect the NPNS exception under GAAP related to these derivative instruments, the fair values of these contracts are reflected in current and noncurrent derivative instrument assets and liabilities in the accompanying Condensed Consolidated Balance Sheets. Associated gains and losses on these forward contracts are recorded in regulatory assets and liabilities on the Condensed Consolidated Balance Sheets in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). At December 31, 2014 and 2013, the volumes of Electric Utility’s forward electricity purchase contracts were 486.2 million kilowatt hours and 324.4 million kilowatt hours, respectively. At December 31, 2014, the maximum period over which these contracts extend is 17 months.
	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. 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. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 6). At December 31, 2014 and 2013, the total volumes associated with FTRs and NYISO capacity contracts totaled 331.8 million kilowatt hours and 1,085.9 million kilowatt hours, respectively. At December 31, 2014, the maximum period over which we are economically hedging electricity congestion and locational basis differences is 5 months.
	In order to manage market price risk relating to fixed-price sales contracts for natural gas and electricity, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures contracts, IntercontinentalExchange (“ICE”) natural gas basis swap contracts, and electricity futures contracts. Midstream & Marketing also uses NYMEX and over the counter electricity futures contracts to hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. 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 or propane. Because it could no longer assert the NPNS exception under GAAP for new contracts entered into for the forward purchase of natural gas and pipeline transportation, beginning in the second quarter of Fiscal 2014 Energy Services began recording these contracts at fair value with changes in fair value reflected in income.
	At December 31, 2014 and 2013, total volumes associated with Midstream & Marketing’s natural gas futures, forward and pipeline contracts totaled 70.0 million dekatherms and 27.4 million dekatherms, respectively. At December 31, 2014, the maximum period over which we are hedging our exposure to the variability in cash flows associated with natural gas commodity price risk is 41 months. At December 31, 2014 and 2013, total volumes associated with Midstream & Marketing’s electricity call contracts and electricity put contracts totaled 350.0 million kilowatt hours and 184.1 million kilowatt hours, and 664.7 million kilowatt hours and 371.0 million kilowatt hours, respectively. At December 31, 2014, the maximum period over which we are hedging our exposure to the variability in cash flows associated with electricity commodity price risk (excluding Electric Utility) is 24 months for electricity call contracts and 9 months for electricity put contracts. At December 31, 2014, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 0.6 million dekatherms and 2.6 million gallons, respectively. At December 31, 2013, the volumes associated with Midstream & Marketing’s natural gas and propane storage NYMEX contracts totaled 1.1 million dekatherms and 2.2 million gallons, respectively.
	In order to reduce operating expense volatility, UGI Utilities from time to time enters into NYMEX gasoline futures and swap contracts for a portion of gasoline volumes expected to be used in the operation of its vehicles and equipment.
	At December 31, 2014, the amount of net gains associated with commodity derivative instruments previously designated and qualified as cash flow hedges expected to be reclassified into earnings during the next twelve months is not material.
	Interest Rate Risk
	Antargaz’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. Antargaz and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rate of interest on their variable-rate term loans through the respective scheduled maturity dates. As of December 31, 2014 and 2013, the total notional amounts of variable-rate debt subject to interest rate swap agreements (excluding Flaga’s cross-currency swap as described below) were €401.1 and €439.8, respectively.
	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”). At December 31, 2014 and 2013, we had no unsettled IRPAs.
	We account for interest rate swaps and IRPAs as cash flow hedges. At December 31, 2014, 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 $2.7.
	Foreign Currency Exchange Rate Risk
	In order to reduce volatility, Antargaz hedges a portion of its anticipated U.S. dollar-denominated LPG product purchases during the heating-season months of October through March through the use of forward foreign currency exchange contracts. At December 31, 2014 and 2013, we were hedging a total of $225.8 and $149.1 of U.S. dollar-denominated LPG purchases, respectively. At December 31, 2014, the maximum period over which we are hedging our exposure to the variability in cash flows associated with U.S. dollar-denominated purchases of LPG is 36 months. From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value on a portion of our International Propane euro-denominated net investments. At December 31, 2014 and 2013, we had no euro-denominated net investment hedges.
	We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At December 31, 2014, the amount of net gains associated with currency rate risk (other than net investment hedges) expected to be reclassified into earnings during the next twelve months based upon current fair values is $8.7.
	Cross-Currency Swaps
	During Fiscal 2013, Flaga entered into a cross-currency swap to hedge its exposure to the variability in expected future cash flows associated with foreign currency and interest rate risk resulting from the issuance of $52 of U.S. dollar-denominated variable-rate debt. The cross-currency hedge includes 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. The cross-currency swap also includes an interest rate swap of a fixed foreign-denominated interest rate to a fixed U.S. dollar-denominated interest rate. We have designated this cross-currency swap as a cash flow hedge. At December 31, 2014, the amount of net gains associated with this cross-currency swap expected to be reclassified into earnings over the next twelve months is not material.
	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 form of letters of credit, parental guarantees or cash. Additionally, our natural gas and electricity exchange-traded futures contracts generally require cash deposits in margin accounts. At December 31, 2014 and 2013, restricted cash in brokerage accounts totaled $54.6 and $3.2, respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at December 31, 2014. 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, 2014, if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material.
	Fair Value of Derivative Instruments
	The following table presents the Company’s derivative assets and liabilities on a gross basis as of December 31, 2014 and 2013:
			December 31,			December 31,
			2014			2013 (a)
	Derivative assets:
	Derivatives designated as hedging instruments:
	Commodity contracts		$	—		$	41.5
	Foreign currency contracts		18.7			0.4
	Cross-currency contracts		4.3			—
	Interest rate contracts		0.1			—
			23.1			41.9
	Derivatives subject to utility rate regulation:
	Commodity contracts		0.2			2
	Derivatives not designated as hedging instruments:
	Commodity contracts		40			15.9
	Total derivative assets		$	63.3		$	59.8
	Derivative liabilities:
	Derivatives designated as hedging instruments:
	Commodity contracts		$	—		$	(0.6	)
	Foreign currency contracts		—			(7.2		)
	Cross-currency contracts		—			(2.1		)
	Interest rate contracts		(17.0		)	(29.2		)
			(17.0		)	(39.1		)
	Derivatives subject to utility rate regulation:
	Commodity contracts		(9.4		)	(3.4		)
	Derivatives not designated as hedging instruments:
	Commodity contracts		(288.5		)	(6.7		)
	Total derivative liabilities		$	(314.9	)	$	(49.2	)
	(a)	Certain immaterial amounts have been revised to correct the classification of derivatives.
	Offsetting Derivative Assets and Liabilities
	Derivative assets and liabilities are presented net by counterparty on our 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 our 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.
	The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of December 31, 2014 and 2013:
			Gross Amounts Recognized			Gross Amounts Offset in Balance Sheet			Net Amounts Recognized			Cash Collateral (Received) Pledged			Net Amounts Recognized in Balance Sheet
	31-Dec-14
	Derivative assets		$	63.3		$	(27.5	)	$	35.8		$	—		$	35.8
	Derivative liabilities		$	(314.9	)	$	27.5		$	(287.4	)	$	90.5		$	(196.9	)
	December 31, 2013
	Derivative assets		$	59.8		$	(6.0	)	$	53.8		$	—		$	53.8
	Derivative liabilities		$	(49.2	)	$	6		$	(43.2	)	$	—		$	(43.2	)
	Effect of Derivative Instruments
	The following tables provide information on the effects of derivative instruments in the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three months ended December 31, 2014 and 2013:
		Gain (Loss)						Gain (Loss)						Location of Gain (Loss) Reclassified from
		Recognized in						Reclassified from						AOCI and Noncontrolling
		AOCI and						AOCI and Noncontrolling						Interests into Income
		Noncontrolling Interests						Interests into Income
Three Months Ended December 31,		2014			2013			2014			2013
Cash Flow Hedges:
Commodity contracts		$	—		$	53.4		$	(2.4	)	$	22.3		Cost of sales
Foreign currency contracts		8.7			(2.5		)	2.7			(2.1		)	Cost of sales
Cross-currency contracts		2.1			(1.2		)	—			(0.3		)	Interest expense
Interest rate contracts		0.8			(1.7		)	(3.9		)	(4.1		)	Interest expense / other operating income, net
Total		$	11.6		$	48		$	(3.6	)	$	15.8
		Gain (Loss)						Location of Gain (Loss)
		Recognized in Income						Recognized in Income
Three Months Ended December 31,		2014			2013
Derivatives Not Designated as Hedging Instruments:
Commodity contracts		$	(292.5	)	$	12.8		Cost of sales
Commodity contracts		3.8			—			Revenues
Commodity contracts		(0.5		)	0.1			Operating expenses / other
								operating income, net
Total		$	(289.2	)	$	12.9
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, 2014 and 2013.
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 which 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 many of these contracts have the requisite elements of a derivative instrument, certain of 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_Comprehensiv

Accumulated Other Comprehensive Income	3 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Accumulated Other Comprehensive Income	Note 12 — Accumulated Other Comprehensive Income
	The table below presents changes in AOCI during the three months ended December 31, 2014 and 2013:
	Three Months Ended December 31, 2014	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
	AOCI - September 30, 2014	$	(20.6	)	$	(9.3	)	$	8.7		$	(21.2	)
	Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			7.7			(30.5		)	(22.8		)
	Amounts reclassified from AOCI and noncontrolling interests:
	Reclassification adjustments (pre-tax)	1			3.6			—			4.6
	Reclassification adjustments tax expense	(0.4		)	(1.5		)	—			(1.9		)
	Reclassification adjustments (after-tax)	0.6			2.1			—			2.7
	Other comprehensive income (loss)	0.6			9.8			(30.5		)	(20.1		)
	Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			1.2			—			1.2
	Other comprehensive income (loss) attributable to UGI	0.6			11			(30.5		)	(18.9		)
	AOCI - December 31, 2014	$	(20.0	)	$	1.7		$	(21.8	)	$	(40.1	)
	Three Months Ended December 31, 2013	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
	AOCI - September 30, 2013	$	(16.4	)	$	(26.9	)	$	51.7		$	8.4
	Other comprehensive income before reclassification adjustments (after-tax)	—			40.5			12.3			52.8
	Amounts reclassified from AOCI and noncontrolling interests:
	Reclassification adjustments (pre-tax)	0.3			(15.8		)	—			(15.5		)
	Reclassification adjustments tax benefit	0.1			2			—			2.1
	Reclassification adjustments (after-tax)	0.4			(13.8		)	—			(13.4		)
	Other comprehensive income	0.4			26.7			12.3			39.4
	Deduct other comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	—			(15.6		)	—			(15.6		)
	Other comprehensive income attributable to UGI	0.4			11.1			12.3			23.8
	AOCI - December 31, 2013	$	(16.0	)	$	(15.8	)	$	64		$	32.2
	For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 11.

Segment_Information

Segment Information	3 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Segment Information	Note 13 — Segment Information
	Our operations comprise six reportable segments generally based upon products sold, geographic location and regulatory environment. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising Antargaz; (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) Gas Utility; (5) Energy Services; and (6) Electric Generation. We refer to both international segments together as “UGI International” and Energy Services and Electric Generation together as “Midstream & Marketing.”
	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 2014 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 net gains and losses on commodity derivative instruments not associated with current-period transactions (“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 commodity derivative instruments. Net gains and losses on commodity derivative instruments not associated with current-period transactions are reflected in Corporate & Other because the Company’s chief operating decision maker does not consider such items when evaluating the financial performance of our reportable segments.
																Midstream & Marketing						UGI International
			Total			Elim-				AmeriGas			Gas			Energy Services			Electric Generation			Antargaz			Flaga &			Corporate
						inations				Propane			Utility												Other			& Other (b)
	Three Months Ended
	31-Dec-14
	Revenues		$	2,004.60		$	(67.7	)	(c)	$	888.8		$	260.5		$	297		$	16.5		$	337.9		$	224.6		$	47
	Cost of sales		$	1,404.60		$	(67.0	)	(c)	$	462.4		$	127.2		$	234.4		$	8		$	209.3		$	172.6		$	257.7
	Segment profit:
	Operating income (loss)		$	83.3		$	—			$	139.7		$	71.8		$	46.2		$	(0.7	)	$	38.4		$	15.1		$	(227.2	)
	Loss from equity investees		(1.0		)	—				—			—			—			—			(1.0		)	—			—
	Interest expense		(59.0		)	—				(41.0		)	(10.1		)	(0.6		)	—			(5.6		)	(1.0		)	(0.7		)
	Income (loss) before income taxes		$	23.3		$	—			$	98.7		$	61.7		$	45.6		$	(0.7	)	$	31.8		$	14.1		$	(227.9	)
	Partnership Adjusted EBITDA (a)									$	188.5
	Noncontrolling interests’ net income (loss)		$	(33.9	)	$	—			$	66.8		$	—		$	—		$	—		$	0.1		$	—		$	(100.8	)
	Depreciation and amortization		$	91		$	—			$	49.4		$	14.3		$	3.6		$	2.7		$	13.3		$	6.1		$	1.6
	Capital expenditures		$	123.5		$	—			$	30.4		$	53.5		$	12.8		$	6.6		$	12.1		$	6.4		$	1.7
	As of December 31, 2014
	Total assets		$	10,430.00		$	(92.7	)		$	4,491.00		$	2,346.20		$	699.9		$	286.4		$	1,671.50		$	579		$	448.7
	Short-term borrowings		$	458.5		$	—			$	253		$	153.5		$	43		$	—		$	—		$	9		$	—
	Goodwill		$	2,806.80		$	—			$	1,949.60		$	182.1		$	5.6		$	—		$	575.9		$	87.4		$	6.2
																Midstream & Marketing						UGI International
			Total			Elim-				AmeriGas			Gas			Energy			Electric			Antargaz			Flaga &			Corporate
						inations				Propane			Utility			Services			Generation						Other			& Other (b)
	Three Months Ended
	31-Dec-13
	Revenues		$	2,315.90		$	(65.5	)	(c)	$	1,045.80		$	271.6		$	272.7		$	20.8		$	425.3		$	293.3		$	51.9
	Cost of sales		$	1,429.90		$	(64.4	)	(c)	$	582.7		$	135.5		$	227.1		$	10.6		$	282.5		$	231.7		$	24.2
	Segment profit:
	Operating income		$	363.7		$	(0.1	)		$	179.7		$	82.1		$	31.8		$	4.4		$	43.2		$	13.7		$	8.9
	Income from equity investees		—			—				—			—			—			—			—			—			—
	Interest expense		(59.3		)	—				(41.6		)	(8.4		)	(1.0		)	—			(6.4		)	(1.3		)	(0.6		)
	Income before income taxes		$	304.4		$	(0.1	)		$	138.1		$	73.7		$	30.8		$	4.4		$	36.8		$	12.4		$	8.3
	Partnership Adjusted EBITDA (a)									$	230.2
	Noncontrolling interests’ net income		$	95.5		$	—			$	95.4		$	—		$	—		$	—		$	0.1		$	—		$	—
	Depreciation and amortization		$	94		$	—			$	52.3		$	13.4		$	2.6		$	2.6		$	15		$	6.6		$	1.5
	Capital expenditures		$	102.8		$	(1.2	)		$	23.3		$	32.9		$	21.7		$	9.3		$	9.8		$	4.6		$	2.4
	As of December 31, 2013
	Total assets		$	10,663.50		$	(101.1	)		$	4,682.30		$	2,188.60		$	574.8		$	279.3		$	1,938.90		$	696.5		$	404.2
	Short-term borrowings		$	421.5		$	—			$	208.8		$	73.5		$	124.5		$	—		$	—		$	14.7		$	—
	Goodwill		$	2,884.50		$	—			$	1,938.80		$	182.1		$	2.8		$	—		$	654.3		$	99.5		$	7
	(a)	The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income:
	Three Months Ended December 31,		2014			2013
	Partnership Adjusted EBITDA		$	188.5		$	230.2
	Depreciation and amortization		(49.4		)	(52.3		)
	Noncontrolling interests (i)		0.6			1.8
	Operating income		$	139.7		$	179.7
	(i)	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
	(b)	Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, and (4) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include net gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $(229.7) and $(7.2) during the three months ended December 31, 2014 and 2013, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and, in the three months ended December 31, 2013, an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
	(c)	Represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Derivatives Instruments	Derivative Instruments. Derivative instruments are reported in the Condensed Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exemption 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 or net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (“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 the forecasted transaction is determined to be no longer probable. Gains and losses on net investment hedges which relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on certain commodity derivative instruments used by Gas Utility and Electric Utility are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers.
	Effective October 1, 2014, UGI International determined that on a prospective basis it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Midstream & Marketing has not applied cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues. For additional information on our derivative instruments, see Note 11.
Earnings Per Common Share	Earnings Per Common Share. Basic earnings per share attributable to UGI Corporation shareholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share attributable to UGI Corporation include the effects of dilutive stock options and common stock awards.
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.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Dec. 31, 2014
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
		December 31,
		2014	2013
	Denominator (thousands of shares):
	Average common shares outstanding for basic computation	172,945	172,238
	Incremental shares issuable for stock options and awards	2,841	2,467
	Average common shares outstanding for diluted computation	175,786	174,705

Inventories_Tables

Inventories (Tables)	3 Months Ended
	Dec. 31, 2014
Inventory Disclosure [Abstract]
Components of Inventories	Inventories comprise the following:
		December 31,		September 30,		December 31,
		2014		2014		2013
	Non-utility LPG and natural gas	$	260.4	$	283.6	$	282.9
	Gas Utility natural gas	72.4		82.7		69.1
	Materials, supplies and other	58.2		56.7		60.4
	Total inventories	$	391	$	423	$	412.4

Goodwill_and_Intangible_Assets1

Goodwill and Intangible Assets (Tables)	3 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Components of Company's Intangible Assets	Goodwill and intangible assets comprise the following:
		December 31,			September 30,			December 31,
		2014			2014			2013
	Goodwill (not subject to amortization)	$	2,806.80		$	2,833.40		$	2,884.50
	Intangible assets:
	Customer relationships, noncompete agreements and other	$	709.3		$	712		$	709.6
	Accumulated amortization	(271.9		)	(263.8		)	(243.0		)
	Intangible assets, net (definite-lived)	437.4			448.2			466.6
	Trademarks and tradenames (indefinite-lived)	126.3			128.2			132.2
	Total intangible assets, net	$	563.7		$	576.4		$	598.8

Utility_Regulatory_Assets_and_1

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)	3 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility	The following regulatory assets and liabilities associated with Utilities are included in our accompanying Condensed Consolidated Balance Sheets:
		December 31,		September 30,		December 31,
		2014		2014		2013
	Regulatory assets (a):
	Income taxes recoverable	$	111.1	$	110.7	$	106.4
	Underfunded pension and postretirement plans	107.8		110.1		92.8
	Environmental costs	14.7		14.6		14.9
	Deferred fuel and power costs	16.7		11.8		0.4
	Removal costs, net	17.6		16.8		13.7
	Other	2.7		4.2		5.7
	Total regulatory assets	$	270.6	$	268.2	$	233.9
	Regulatory liabilities (a):
	Postretirement benefits	$	19	$	18.6	$	16.8
	Environmental overcollections	0.2		0.3		2.3
	Deferred fuel and power refunds	—		0.3		7.5
	State tax benefits—distribution system repairs	10.3		10.1		8.7
	Other	3.4		3.2		1.3
	Total regulatory liabilities	$	32.9	$	32.5	$	36.6
	(a) Noncurrent regulatory assets are recorded in other assets and regulatory liabilities are recorded in other current and other noncurrent liabilities in the Condensed Consolidated Balance Sheets.

Defined_Benefit_Pension_and_Ot1

Defined Benefit Pension and Other Postretirement Plans (Tables)	3 Months Ended
	Dec. 31, 2014
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,	2014			2013			2014			2013
	Service cost	$	2.4		$	2.3		$	0.2		$	0.1
	Interest cost	6.3			6.4			0.2			0.2
	Expected return on assets	(7.9		)	(7.3		)	(0.2		)	(0.1		)
	Amortization of:
	Prior service cost (benefit)	0.1			0.1			(0.1		)	(0.1		)
	Actuarial loss	2.5			1.9			—			—
	Net benefit cost	3.4			3.4			0.1			0.1
	Change in associated regulatory liabilities	—			—			0.9			0.9
	Net expense	$	3.4		$	3.4		$	1		$	1

Fair_Value_Measurement_Tables

Fair Value Measurement (Tables)	3 Months Ended
	Dec. 31, 2014
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, 2014, September 30, 2014 and December 31, 2013:
			Asset (Liability)
			Level 1			Level 2			Level 3		Total
	December 31, 2014:
	Derivative instruments:
	Assets:
	Commodity contracts		$	14.1		$	26.1		$	—	$	40.2
	Foreign currency contracts		$	—		$	18.7		$	—	$	18.7
	Interest rate contracts		$	—		$	0.1		$	—	$	0.1
	Cross-currency swaps		$	—		$	4.3		$	—	$	4.3
	Liabilities:
	Commodity contracts		$	(69.4	)	$	(228.5	)	$	—	$	(297.9	)
	Interest rate contracts		$	—		$	(17.0	)	$	—	$	(17.0	)
	Non-qualified supplemental postretirement grantor trust investments (a)		$	31.4		$	—		$	—	$	31.4
	September 30, 2014:
	Derivative instruments:
	Assets:
	Commodity contracts		$	10.6		$	19.8		$	—	$	30.4
	Foreign currency contracts		$	—		$	12.8		$	—	$	12.8
	Interest rate contracts		$	—		$	0.1		$	—	$	0.1
	Cross-currency swaps		$	—		$	2.1		$	—	$	2.1
	Liabilities:
	Commodity contracts		$	(21.2	)	$	(32.9	)	$	—	$	(54.1	)
	Foreign currency contracts		$	—		$	(0.1	)	$	—	$	(0.1	)
	Interest rate contracts		$	—		$	(21.0	)	$	—	$	(21.0	)
	Non-qualified supplemental postretirement grantor trust investments (a)		$	30		$	—		$	—	$	30
	December 31, 2013 (b):
	Derivative instruments:
	Assets:
	Commodity contracts		$	9.8		$	49.6		$	—	$	59.4
	Foreign currency contracts		$	—		$	0.4		$	—	$	0.4
	Liabilities:
	Commodity contracts		$	(6.1	)	$	(4.6	)	$	—	$	(10.7	)
	Foreign currency contracts		$	—		$	(7.2	)	$	—	$	(7.2	)
	Interest rate contracts		$	—		$	(29.2	)	$	—	$	(29.2	)
	Cross-currency swaps		$	—		$	(2.1	)	$	—	$	(2.1	)
	Non-qualified supplemental postretirement grantor trust investments (a)		$	30.3		$	—		$	—	$	30.3
	(a)	Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.
	(b)	Certain immaterial amounts have been revised to correct the classification of derivatives.

Derivative_Instruments_and_Hed1

Derivative Instruments and Hedging Activities (Tables)	3 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Balance Sheet Location and Fair Value of Derivative Assets and Liabilities	The following table presents the Company’s derivative assets and liabilities on a gross basis as of December 31, 2014 and 2013:
			December 31,			December 31,
			2014			2013 (a)
	Derivative assets:
	Derivatives designated as hedging instruments:
	Commodity contracts		$	—		$	41.5
	Foreign currency contracts		18.7			0.4
	Cross-currency contracts		4.3			—
	Interest rate contracts		0.1			—
			23.1			41.9
	Derivatives subject to utility rate regulation:
	Commodity contracts		0.2			2
	Derivatives not designated as hedging instruments:
	Commodity contracts		40			15.9
	Total derivative assets		$	63.3		$	59.8
	Derivative liabilities:
	Derivatives designated as hedging instruments:
	Commodity contracts		$	—		$	(0.6	)
	Foreign currency contracts		—			(7.2		)
	Cross-currency contracts		—			(2.1		)
	Interest rate contracts		(17.0		)	(29.2		)
			(17.0		)	(39.1		)
	Derivatives subject to utility rate regulation:
	Commodity contracts		(9.4		)	(3.4		)
	Derivatives not designated as hedging instruments:
	Commodity contracts		(288.5		)	(6.7		)
	Total derivative liabilities		$	(314.9	)	$	(49.2	)
	(a)	Certain immaterial amounts have been revised to correct the classification of derivatives.
Derivative Assets and Liabilities and the Effects of Offsetting	The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of December 31, 2014 and 2013:
			Gross Amounts Recognized			Gross Amounts Offset in Balance Sheet			Net Amounts Recognized			Cash Collateral (Received) Pledged			Net Amounts Recognized in Balance Sheet
	31-Dec-14
	Derivative assets		$	63.3		$	(27.5	)	$	35.8		$	—		$	35.8
	Derivative liabilities		$	(314.9	)	$	27.5		$	(287.4	)	$	90.5		$	(196.9	)
	December 31, 2013
	Derivative assets		$	59.8		$	(6.0	)	$	53.8		$	—		$	53.8
	Derivative liabilities		$	(49.2	)	$	6		$	(43.2	)	$	—		$	(43.2	)
Effects of Derivative Instruments on the Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest	The following tables provide information on the effects of derivative instruments in the Condensed Consolidated Statements of Income and changes in AOCI and noncontrolling interests for the three months ended December 31, 2014 and 2013:
			Gain (Loss)						Gain (Loss)						Location of Gain (Loss) Reclassified from
			Recognized in						Reclassified from						AOCI and Noncontrolling
			AOCI and						AOCI and Noncontrolling						Interests into Income
			Noncontrolling Interests						Interests into Income
	Three Months Ended December 31,		2014			2013			2014			2013
	Cash Flow Hedges:
	Commodity contracts		$	—		$	53.4		$	(2.4	)	$	22.3		Cost of sales
	Foreign currency contracts		8.7			(2.5		)	2.7			(2.1		)	Cost of sales
	Cross-currency contracts		2.1			(1.2		)	—			(0.3		)	Interest expense
	Interest rate contracts		0.8			(1.7		)	(3.9		)	(4.1		)	Interest expense / other operating income, net
	Total		$	11.6		$	48		$	(3.6	)	$	15.8
			Gain (Loss)						Location of Gain (Loss)
			Recognized in Income						Recognized in Income
	Three Months Ended December 31,		2014			2013
	Derivatives Not Designated as Hedging Instruments:
	Commodity contracts		$	(292.5	)	$	12.8		Cost of sales
	Commodity contracts		3.8			—			Revenues
	Commodity contracts		(0.5		)	0.1			Operating expenses / other
									operating income, net
	Total		$	(289.2	)	$	12.9

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income	The table below presents changes in AOCI during the three months ended December 31, 2014 and 2013:
	Three Months Ended December 31, 2014	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
	AOCI - September 30, 2014	$	(20.6	)	$	(9.3	)	$	8.7		$	(21.2	)
	Other comprehensive income (loss) before reclassification adjustments (after-tax)	—			7.7			(30.5		)	(22.8		)
	Amounts reclassified from AOCI and noncontrolling interests:
	Reclassification adjustments (pre-tax)	1			3.6			—			4.6
	Reclassification adjustments tax expense	(0.4		)	(1.5		)	—			(1.9		)
	Reclassification adjustments (after-tax)	0.6			2.1			—			2.7
	Other comprehensive income (loss)	0.6			9.8			(30.5		)	(20.1		)
	Add other comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners	—			1.2			—			1.2
	Other comprehensive income (loss) attributable to UGI	0.6			11			(30.5		)	(18.9		)
	AOCI - December 31, 2014	$	(20.0	)	$	1.7		$	(21.8	)	$	(40.1	)
	Three Months Ended December 31, 2013	Postretirement Benefit Plans			Derivative Instruments			Foreign Currency			Total
	AOCI - September 30, 2013	$	(16.4	)	$	(26.9	)	$	51.7		$	8.4
	Other comprehensive income before reclassification adjustments (after-tax)	—			40.5			12.3			52.8
	Amounts reclassified from AOCI and noncontrolling interests:
	Reclassification adjustments (pre-tax)	0.3			(15.8		)	—			(15.5		)
	Reclassification adjustments tax benefit	0.1			2			—			2.1
	Reclassification adjustments (after-tax)	0.4			(13.8		)	—			(13.4		)
	Other comprehensive income	0.4			26.7			12.3			39.4
	Deduct other comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	—			(15.6		)	—			(15.6		)
	Other comprehensive income attributable to UGI	0.4			11.1			12.3			23.8
	AOCI - December 31, 2013	$	(16.0	)	$	(15.8	)	$	64		$	32.2

Segment_Information_Tables

Segment Information (Tables)	3 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Schedule of Segment Reporting Information
																Midstream & Marketing						UGI International
			Total			Elim-				AmeriGas			Gas			Energy Services			Electric Generation			Antargaz			Flaga &			Corporate
						inations				Propane			Utility												Other			& Other (b)
	Three Months Ended
	31-Dec-14
	Revenues		$	2,004.60		$	(67.7	)	(c)	$	888.8		$	260.5		$	297		$	16.5		$	337.9		$	224.6		$	47
	Cost of sales		$	1,404.60		$	(67.0	)	(c)	$	462.4		$	127.2		$	234.4		$	8		$	209.3		$	172.6		$	257.7
	Segment profit:
	Operating income (loss)		$	83.3		$	—			$	139.7		$	71.8		$	46.2		$	(0.7	)	$	38.4		$	15.1		$	(227.2	)
	Loss from equity investees		(1.0		)	—				—			—			—			—			(1.0		)	—			—
	Interest expense		(59.0		)	—				(41.0		)	(10.1		)	(0.6		)	—			(5.6		)	(1.0		)	(0.7		)
	Income (loss) before income taxes		$	23.3		$	—			$	98.7		$	61.7		$	45.6		$	(0.7	)	$	31.8		$	14.1		$	(227.9	)
	Partnership Adjusted EBITDA (a)									$	188.5
	Noncontrolling interests’ net income (loss)		$	(33.9	)	$	—			$	66.8		$	—		$	—		$	—		$	0.1		$	—		$	(100.8	)
	Depreciation and amortization		$	91		$	—			$	49.4		$	14.3		$	3.6		$	2.7		$	13.3		$	6.1		$	1.6
	Capital expenditures		$	123.5		$	—			$	30.4		$	53.5		$	12.8		$	6.6		$	12.1		$	6.4		$	1.7
	As of December 31, 2014
	Total assets		$	10,430.00		$	(92.7	)		$	4,491.00		$	2,346.20		$	699.9		$	286.4		$	1,671.50		$	579		$	448.7
	Short-term borrowings		$	458.5		$	—			$	253		$	153.5		$	43		$	—		$	—		$	9		$	—
	Goodwill		$	2,806.80		$	—			$	1,949.60		$	182.1		$	5.6		$	—		$	575.9		$	87.4		$	6.2
																Midstream & Marketing						UGI International
			Total			Elim-				AmeriGas			Gas			Energy			Electric			Antargaz			Flaga &			Corporate
						inations				Propane			Utility			Services			Generation						Other			& Other (b)
	Three Months Ended
	31-Dec-13
	Revenues		$	2,315.90		$	(65.5	)	(c)	$	1,045.80		$	271.6		$	272.7		$	20.8		$	425.3		$	293.3		$	51.9
	Cost of sales		$	1,429.90		$	(64.4	)	(c)	$	582.7		$	135.5		$	227.1		$	10.6		$	282.5		$	231.7		$	24.2
	Segment profit:
	Operating income		$	363.7		$	(0.1	)		$	179.7		$	82.1		$	31.8		$	4.4		$	43.2		$	13.7		$	8.9
	Income from equity investees		—			—				—			—			—			—			—			—			—
	Interest expense		(59.3		)	—				(41.6		)	(8.4		)	(1.0		)	—			(6.4		)	(1.3		)	(0.6		)
	Income before income taxes		$	304.4		$	(0.1	)		$	138.1		$	73.7		$	30.8		$	4.4		$	36.8		$	12.4		$	8.3
	Partnership Adjusted EBITDA (a)									$	230.2
	Noncontrolling interests’ net income		$	95.5		$	—			$	95.4		$	—		$	—		$	—		$	0.1		$	—		$	—
	Depreciation and amortization		$	94		$	—			$	52.3		$	13.4		$	2.6		$	2.6		$	15		$	6.6		$	1.5
	Capital expenditures		$	102.8		$	(1.2	)		$	23.3		$	32.9		$	21.7		$	9.3		$	9.8		$	4.6		$	2.4
	As of December 31, 2013
	Total assets		$	10,663.50		$	(101.1	)		$	4,682.30		$	2,188.60		$	574.8		$	279.3		$	1,938.90		$	696.5		$	404.2
	Short-term borrowings		$	421.5		$	—			$	208.8		$	73.5		$	124.5		$	—		$	—		$	14.7		$	—
	Goodwill		$	2,884.50		$	—			$	1,938.80		$	182.1		$	2.8		$	—		$	654.3		$	99.5		$	7
	(a)	The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income:
	Three Months Ended December 31,		2014			2013
	Partnership Adjusted EBITDA		$	188.5		$	230.2
	Depreciation and amortization		(49.4		)	(52.3		)
	Noncontrolling interests (i)		0.6			1.8
	Operating income		$	139.7		$	179.7
	(i)	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
	(b)	Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, and (4) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include net gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $(229.7) and $(7.2) during the three months ended December 31, 2014 and 2013, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and, in the three months ended December 31, 2013, an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.
	(c)	Represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.

Nature_of_Operations_Details

Nature of Operations (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
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%
Limited Partnership Common Units held in AmeriGas Partners (in units)	23,756,882
General public as limited partner interests in AmeriGas Partners	73.70%
Common Units owned by public (in units)	69,117,556
General Partner incentive distribution	$6.50	$5.40

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Details)	3 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Ownership interests in certain subsidiaries under equity method investment, maximum	100.00%
Voting rights in investment businesses not traded publicly accounted for under the cost method, Maximum	20.00%

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Denominator (thousands of shares):
Average common shares outstanding for basic computation	172,945	172,238
Incremental shares issuable for stock options and awards	2,841	2,467
Average common shares outstanding for diluted computation	175,786	174,705

Inventories_Details

Inventories (Details) (USD $)	0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
		ft3	ft3
Inventory
Number of storage agreements	4
Volume of gas storage inventories released under SCAAs with non-affiliates (in cubic feet)	3,400,000,000	3,900,000,000	3,100,000,000
Carrying value of gas storage inventories released under SCAAs with non-affiliates	14.4	$16.80	$12.30
Minimum
Inventory
SCAA contract term (in years)	1 year
Maximum
Inventory
SCAA contract term (in years)	3 years

Inventories_Components_of_Inve

Inventories - Components of Inventories (Details) (USD $)	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Inventory
Inventory, net	$391	$423	$412.40
Non-utility LPG and Natural Gas
Inventory
Inventory, net	260.4	283.6	282.9
Gas Utility Natural Gas
Inventory
Inventory, net	72.4	82.7	69.1
Materials, Supplies and Other
Inventory
Inventory, net	$58.20	$56.70	$60.40

Goodwill_and_Intangible_Assets2

Goodwill and Intangible Assets (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense of intangible assets	$13	$13.30
Remainder of Fiscal 2015	38.6
Fiscal 2016	44.9
Fiscal 2017	38.3
Fiscal 2018	36.6
Fiscal 2019	$35

Goodwill_and_Intangible_Assets3

Goodwill and Intangible Assets - Components of Company's Intangible Assets (Details) (USD $)	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill (not subject to amortization)	$2,806.80	$2,833.40	$2,884.50
Intangible assets:
Customer relationships, noncompete agreements and other	709.3	712	709.6
Accumulated amortization	-271.9	-263.8	-243
Intangible assets, net (definite-lived)	437.4	448.2	466.6
Trademarks and tradenames (indefinite-lived)	126.3	128.2	132.2
Total intangible assets, net	$563.70	$576.40	$598.80

Utility_Regulatory_Assets_and_2

Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) (USD $)	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Gas Utility
Regulatory Assets
Fair value of unrealized gains (losses)	($6.80)	($1.40)	$2
Electric Utility Electric Supply Contracts
Regulatory Assets
Fair value of unrealized gains (losses)	($2.40)	$0.30	($3.20)

Utility_Regulatory_Assets_and_3

Utility Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Gas Utility and Electric Utility (Details) (USD $)	Dec. 31, 2014		Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Regulatory Assets And Liabilities
Regulatory assets	$270.60	[1]	$268.20	[1]	$233.90	[1]
Regulatory liabilities	32.9	[1]	32.5	[1]	36.6	[1]
Postretirement Benefits
Regulatory Assets And Liabilities
Regulatory liabilities	19	[1]	18.6	[1]	16.8	[1]
Environmental Overcollections
Regulatory Assets And Liabilities
Regulatory liabilities	0.2	[1]	0.3	[1]	2.3	[1]
Deferred Fuel and Power Refunds
Regulatory Assets And Liabilities
Regulatory liabilities	0	[1]	0.3	[1]	7.5	[1]
State Tax Benefits—Distribution System Repairs
Regulatory Assets And Liabilities
Regulatory liabilities	10.3	[1]	10.1	[1]	8.7	[1]
Other
Regulatory Assets And Liabilities
Regulatory liabilities	3.4	[1]	3.2	[1]	1.3	[1]
Income Taxes Recoverable
Regulatory Assets And Liabilities
Regulatory assets	111.1	[1]	110.7	[1]	106.4	[1]
Underfunded Pension and Postretirement Plans
Regulatory Assets And Liabilities
Regulatory assets	107.8	[1]	110.1	[1]	92.8	[1]
Environmental Costs
Regulatory Assets And Liabilities
Regulatory assets	14.7	[1]	14.6	[1]	14.9	[1]
Deferred Fuel and Power Costs
Regulatory Assets And Liabilities
Regulatory assets	16.7	[1]	11.8	[1]	0.4	[1]
Removal Costs, Net
Regulatory Assets And Liabilities
Regulatory assets	17.6	[1]	16.8	[1]	13.7	[1]
Other
Regulatory Assets And Liabilities
Regulatory assets	$2.70	[1]	$4.20	[1]	$5.70	[1]
[1]	Noncurrent regulatory assets are recorded in other assets and regulatory liabilities are recorded in other current and other noncurrent liabilities in the Condensed Consolidated Balance Sheets.

Energy_Services_Accounts_Recei1

Energy Services Accounts Receivable Securitization Facility (Details) (USD $)	3 Months Ended		5 Months Ended	7 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Oct. 31, 2015	31-May-15
Energy Services
Accounts, Notes, Loans and Financing Receivable
Sale of trade receivables	$286.40	$269
Energy Services Funding Corporation
Accounts, Notes, Loans and Financing Receivable
Sale of undivided interests in its trade receivables to the commercial paper conduit	105	92
Outstanding balance of trade receivables	96.5	88.5
Outstanding balance of trade receivables sold	43	35.5
Forecast | Maximum
Accounts, Notes, Loans and Financing Receivable
Receivables facility			$75	$150

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	lb
	competitors
	lawsuit
Commitments and Contingencies
Amount of propane in cylinders before reduction	17
Amount of propane in cylinders after reduction	15
Number of competitors who alleged to have colluded with the Partnership	1
Class action lawsuits (more than 35)	35
PNG MGP
Commitments and Contingencies
Loss contingency, settlement agreement, terms	2 years
Environmental Matters | CPG MGP
Commitments and Contingencies
Environmental expenditures cap during calendar year	1.8
Environmental Matters | PNG MGP
Commitments and Contingencies
Environmental expenditures cap during calendar year	1.1
Environmental Matters | UGI Utilities
Commitments and Contingencies
Base year for determination of investigation and remediation cost (in years)	5 years
CPG and PNG COAs | UGI Utilities
Commitments and Contingencies
Accrual for environmental loss contingencies	11.2	$12.10

Defined_Benefit_Pension_and_Ot2

Defined Benefit Pension and Other Postretirement Plans (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Contribution made to Pension Plan	$2.80	$3.50
Expected contribution to pensions plans during remainder of fiscal year	8.3
Net cost to sponsor unfunded and non-qualified supplemental executive retirement plans	$0.70	$0.80

Defined_Benefit_Pension_and_Ot3

Defined Benefit Pension and Other Postretirement Plans - Components of Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Defined Benefit Plan Disclosure
Service cost	$2.40	$2.30
Interest cost	6.3	6.4
Expected return on assets	-7.9	-7.3
Amortization of:
Prior service cost (benefit)	0.1	0.1
Actuarial loss	2.5	1.9
Net benefit cost	3.4	3.4
Change in associated regulatory liabilities	0	0
Net expense	3.4	3.4
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	0.2	0.1
Interest cost	0.2	0.2
Expected return on assets	-0.2	-0.1
Amortization of:
Prior service cost (benefit)	-0.1	-0.1
Actuarial loss	0	0
Net benefit cost	0.1	0.1
Change in associated regulatory liabilities	0.9	0.9
Net expense	$1	$1

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value Disclosures [Abstract]
Carrying value of long-term debt	$3,488.30	$3,616.30
Estimated fair value of long-term debt	$3,640.70	$3,856.90

Fair_Value_Measurements_Financ

Fair Value Measurements - Financial Assets and Liabilities that are Measured at Fair Value on a Recurring Basis (Details) (Fair Value, Measurements, Recurring, USD $)	Dec. 31, 2014		Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments (a)	$31.40	[1]	$30	[1]	$30.30	[1],[2]
Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	40.2		30.4		59.4	[2]
Derivative financial instruments, liabilities	-297.9		-54.1		-10.7	[2]
Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	18.7		12.8		0.4	[2]
Derivative financial instruments, liabilities			-0.1		-7.2	[2]
Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0.1		0.1
Derivative financial instruments, liabilities	-17		-21		-29.2	[2]
Cross-currency swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	4.3		2.1
Derivative financial instruments, liabilities					-2.1	[2]
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments (a)	31.4	[1]	30	[1]	30.3	[1],[2]
Level 1 | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	14.1		10.6		9.8	[2]
Derivative financial instruments, liabilities	-69.4		-21.2		-6.1	[2]
Level 1 | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0		0	[2]
Derivative financial instruments, liabilities			0		0	[2]
Level 1 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0
Derivative financial instruments, liabilities	0		0		0	[2]
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	[2]
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments (a)	0	[1]	0	[1]	0	[1],[2]
Level 2 | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	26.1		19.8		49.6	[2]
Derivative financial instruments, liabilities	-228.5		-32.9		-4.6	[2]
Level 2 | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	18.7		12.8		0.4	[2]
Derivative financial instruments, liabilities			-0.1		-7.2	[2]
Level 2 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0.1		0.1
Derivative financial instruments, liabilities	-17		-21		-29.2	[2]
Level 2 | Cross-currency swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	4.3		2.1
Derivative financial instruments, liabilities					-2.1	[2]
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Non-qualified supplemental postretirement grantor trust investments (a)	0	[1]	0	[1]	0	[1],[2]
Level 3 | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0		0	[2]
Derivative financial instruments, liabilities	0		0		0	[2]
Level 3 | Foreign currency contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0		0	[2]
Derivative financial instruments, liabilities			0		0	[2]
Level 3 | Interest rate contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Derivative financial instruments, assets	0		0
Derivative financial instruments, liabilities	0		0		0	[2]
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	[2]
[1]	Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans.
[2]	Certain immaterial amounts have been revised to correct the classification of derivatives.

Derivative_Instruments_and_Hed2

Derivative Instruments and Hedging Activities (Details)

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

USD ($)

USD ($)

USD ($)

Brokerage Accounts

Brokerage Accounts

Interest Rate Swaps

Interest Rate Swaps

Interest Rate Protection Agreements

Interest Rate Protection Agreements

Foreign Currency

Foreign Currency

Cross Currency Contracts

Gas Utility

Gas Utility

Electric Utility

Electric Utility

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Midstream & Marketing

Net Investment Hedging

Net Investment Hedging

gal

gal

USD ($)

USD ($)

EUR (€)

EUR (€)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

DTH

DTH

kWh

kWh

Electricity (millions of kilowatt-hours)

Electricity (millions of kilowatt-hours)

Electricity (millions of kilowatt-hours)

Electricity (millions of kilowatt-hours)

Propane Storage (millions of dekatherms)

Propane Storage (millions of dekatherms)

Gas Utility Natural Gas

Gas Utility Natural Gas

Natural Gas

Natural Gas Storage

Natural Gas Storage

FTR and NYISO Contracts

FTR and NYISO Contracts

FTR and NYISO Contracts

EUR (€)

EUR (€)

Forward Purchase Contracts

Forward Purchase Contracts

Forward Sales Contracts

Forward Sales Contracts

Forward Sales Contracts

Forward Sales Contracts

Forward Purchase Contracts

Forward Purchase Contracts

Forward Sales Contracts

Forward Sales Contracts

Electric transmission congestion (excluding Electric Utility)

Electric transmission congestion (excluding Electric Utility)

kWh

kWh

kWh

kWh

gal

gal

DTH

DTH

DTH

DTH

kWh

kWh

Derivative

Volume of LPG commodity derivatives (in gallons)

429,600,000

215,200,000

Maximum length of time hedging exposure to LPG commodity price risk

33 months

Outstanding derivative commodity instruments volumes

11,200,000

9,700,000

486,200,000

324,400,000

350,000,000

664,700,000

184,100,000

371,000,000

2,600,000

2,200,000

70,000,000

27,400,000

600,000

1,100,000

331,800,000

1,085,900,000

Maximum length of time hedged in price risk cash flow hedges

36 months

9 months

17 months

24 months

9 months

41 months

5 months

Notional amount

€ 401.10

€ 439.80

$0

$0

$225.80

$149.10

$52

€ 0

€ 0

Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months

2.7

Amount of net gains associated with currency rate risk to be reclassified into earnings during the next 12 months

8.7

Restricted cash

$54.60

$4.50

$16.60

$54.60

$3.20

Derivative_Instruments_and_Hed3

Derivative Instruments and Hedging Activities - Fair Value of Derivative Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative assets:
Derivative asset, gross	$63.30	$59.80	[1]
Derivative liabilities:
Derivative liability, gross	-314.9	-49.2	[1]
Designated as Hedging Instrument
Derivative assets:
Derivative asset, gross	23.1	41.9	[1]
Derivative liabilities:
Derivative liability, gross	-17	-39.1	[1]
Designated as Hedging Instrument | Commodity Contracts
Derivative assets:
Derivative asset, gross	0	41.5	[1]
Derivative liabilities:
Derivative liability, gross	0	-0.6	[1]
Designated as Hedging Instrument | Foreign Currency Contracts
Derivative assets:
Derivative asset, gross	18.7	0.4	[1]
Derivative liabilities:
Derivative liability, gross	0	-7.2	[1]
Designated as Hedging Instrument | Cross Currency Contracts
Derivative assets:
Derivative asset, gross	4.3	0	[1]
Derivative liabilities:
Derivative liability, gross	0	-2.1	[1]
Designated as Hedging Instrument | Interest rate contracts
Derivative assets:
Derivative asset, gross	0.1	0	[1]
Derivative liabilities:
Derivative liability, gross	-17	-29.2	[1]
Derivatives Subject to Utility Rate Regulation | Commodity Contracts
Derivative assets:
Derivative asset, gross	0.2	2	[1]
Derivative liabilities:
Derivative liability, gross	-9.4	-3.4	[1]
Derivatives Not Designated as Hedging Instruments | Commodity Contracts
Derivative assets:
Derivative asset, gross	40	15.9	[1]
Derivative liabilities:
Derivative liability, gross	($288.50)	($6.70)	[1]
[1]	Certain immaterial amounts have been revised to correct the classification of derivatives.

Derivative_Instruments_and_Hed4

Derivative Instruments and Hedging Activities - Offsetting Derivative Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative asset, gross	$63.30	$59.80	[1]
Derivative asset, gross liability	-27.5	-6
Derivative asset, net	35.8	53.8
Cash collateral (received) pledged	0	0
Derivative asset, net amount recognized in balance sheet	35.8	53.8
Derivative liability, gross	-314.9	-49.2	[1]
Derivative liability, gross asset	27.5	6
Derivative liability, net	-287.4	-43.2
Cash collateral (received) pledged	90.5	0
Derivative liability, net amount recognized in balance sheet	($196.90)	($43.20)
[1]	Certain immaterial amounts have been revised to correct the classification of derivatives.

Derivative_Instruments_and_Hed5

Derivative Instruments and Hedging Activities - Effects of Derivative Instruments on the Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivatives Not Designated as Hedging Instruments
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	($289.20)	$12.90
Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI and Noncontrolling Interests	11.6	48
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	-3.6	15.8
Commodity Contracts | Derivatives Not Designated as Hedging Instruments | Cost of Sales
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	-292.5	12.8
Commodity Contracts | Derivatives Not Designated as Hedging Instruments | Revenues
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	3.8	0
Commodity Contracts | Derivatives Not Designated as Hedging Instruments | Operating Expenses / Other Operating Income
Derivative Instruments, Gain (Loss)
Gain (Loss) recognized in income	-0.5	0.1
Commodity Contracts | Cash Flow Hedges | Cost of Sales
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI and Noncontrolling Interests	0	53.4
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	-2.4	22.3
Foreign Currency Contracts | Cash Flow Hedges | Cost of Sales
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI and Noncontrolling Interests	8.7	-2.5
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	2.7	-2.1
Cross Currency Contracts | Cash Flow Hedges | Interest Expense
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI and Noncontrolling Interests	2.1	-1.2
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	0	-0.3
Interest rate contracts | Cash Flow Hedges | Interest Expense / Other Operating Income
Derivative Instruments, Gain (Loss)
Gain (loss) recognized in AOCI and Noncontrolling Interests	0.8	-1.7
Gain (loss) reclassified from AOCI and Noncontrolling Interest into income	($3.90)	($4.10)

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income - Schedule of Accumulated Other Comprehensive Income (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss)
AOCI - balance at beginning of period	($21.20)	$8.40
Other comprehensive income (loss) before reclassification adjustments (after-tax)	-22.8	52.8
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	4.6	-15.5
Reclassification From AOCI Current Period Tax	-1.9	2.1
Reclassification adjustments (after-tax)	2.7	-13.4
Other comprehensive (loss) income	-20.1	39.4
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	1.2	-15.6
Comprehensive (loss) income	-18.9	23.8
AOCI - balance at end of period	-40.1	32.2
Postretirement Benefit Plans
Accumulated Other Comprehensive Income (Loss)
AOCI - balance at beginning of period	-20.6	-16.4
Other comprehensive income (loss) before reclassification adjustments (after-tax)	0	0
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	1	0.3
Reclassification From AOCI Current Period Tax	-0.4	0.1
Reclassification adjustments (after-tax)	0.6	0.4
Other comprehensive (loss) income	0.6	0.4
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	0	0
Comprehensive (loss) income	0.6	0.4
AOCI - balance at end of period	-20	-16
Derivative Instruments
Accumulated Other Comprehensive Income (Loss)
AOCI - balance at beginning of period	-9.3	-26.9
Other comprehensive income (loss) before reclassification adjustments (after-tax)	7.7	40.5
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	3.6	-15.8
Reclassification From AOCI Current Period Tax	-1.5	2
Reclassification adjustments (after-tax)	2.1	-13.8
Other comprehensive (loss) income	9.8	26.7
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	1.2	-15.6
Comprehensive (loss) income	11	11.1
AOCI - balance at end of period	1.7	-15.8
Foreign Currency
Accumulated Other Comprehensive Income (Loss)
AOCI - balance at beginning of period	8.7	51.7
Other comprehensive income (loss) before reclassification adjustments (after-tax)	-30.5	12.3
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0	0
Reclassification From AOCI Current Period Tax	0	0
Reclassification adjustments (after-tax)	0	0
Other comprehensive (loss) income	-30.5	12.3
Add comprehensive loss (deduct comprehensive income) attributable to noncontrolling interests, principally in AmeriGas Partners	0	0
Comprehensive (loss) income	-30.5	12.3
AOCI - balance at end of period	($21.80)	$64

Segment_Information_Details

Segment Information (Details)	3 Months Ended
	Dec. 31, 2014
	segment
Segment Reporting [Abstract]
Number of reportable segments (in reportable segments)	6

Segment_Information_Schedule_o

Segment Information - Schedule of Segment Reporting Information (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Sep. 30, 2014
Segment Reporting Information
Revenues	$2,004.60		$2,315.90
Cost of sales	1,404.60		1,429.90
Segment profit:
Operating income (loss)	83.3		363.7
Loss from equity investees	-1		0
Interest expense	-59		-59.3
Income (loss) before income taxes	23.3		304.4
Noncontrolling interests’ net income (loss)	-33.9		95.5
Depreciation and amortization	-91		-94
Capital expenditures	123.5		102.8
Total assets	10,430		10,663.50		10,093
Short-term borrowings	458.5		421.5		210.8
Goodwill	2,806.80		2,884.50		2,833.40
General Partnership interest in AmeriGas OLP (percentage)	1.01%		1.01%
Gains (losses) on unsettled commodity derivative instruments, net	-229.7		-7.2
Eliminations
Segment Reporting Information
Revenues	-67.7	[1]	-65.5	[1]
Cost of sales	-67	[1]	-64.4	[1]
Segment profit:
Operating income (loss)	0		-0.1
Loss from equity investees	0		0
Interest expense	0		0
Income (loss) before income taxes	0		-0.1
Noncontrolling interests’ net income (loss)	0		0
Depreciation and amortization	0		0
Capital expenditures	0		-1.2
Total assets	-92.7		-101.1
Short-term borrowings	0		0
Goodwill	0		0
AmeriGas Propane
Segment Reporting Information
Revenues	888.8		1,045.80
Cost of sales	462.4		582.7
Segment profit:
Operating income (loss)	139.7		179.7
Loss from equity investees	0		0
Interest expense	-41		-41.6
Income (loss) before income taxes	98.7		138.1
Partnership Adjusted EBITDA	188.5	[2]	230.2	[2]
Noncontrolling interests’ net income (loss)	66.8		95.4
Depreciation and amortization	-49.4		-52.3
Capital expenditures	30.4		23.3
Total assets	4,491		4,682.30
Short-term borrowings	253		208.8
Goodwill	1,949.60		1,938.80
Noncontrolling interests	0.6	[3]	1.8	[3]
Gas Utility
Segment Reporting Information
Revenues	260.5		271.6
Cost of sales	127.2		135.5
Segment profit:
Operating income (loss)	71.8		82.1
Loss from equity investees	0		0
Interest expense	-10.1		-8.4
Income (loss) before income taxes	61.7		73.7
Noncontrolling interests’ net income (loss)	0		0
Depreciation and amortization	-14.3		-13.4
Capital expenditures	53.5		32.9
Total assets	2,346.20		2,188.60
Short-term borrowings	153.5		73.5
Goodwill	182.1		182.1
Midstream & Marketing, Energy Services
Segment Reporting Information
Revenues	297		272.7
Cost of sales	234.4		227.1
Segment profit:
Operating income (loss)	46.2		31.8
Loss from equity investees	0		0
Interest expense	-0.6		-1
Income (loss) before income taxes	45.6		30.8
Noncontrolling interests’ net income (loss)	0		0
Depreciation and amortization	-3.6		-2.6
Capital expenditures	12.8		21.7
Total assets	699.9		574.8
Short-term borrowings	43		124.5
Goodwill	5.6		2.8
Midstream & Marketing, Electric Generation
Segment Reporting Information
Revenues	16.5		20.8
Cost of sales	8		10.6
Segment profit:
Operating income (loss)	-0.7		4.4
Loss from equity investees	0		0
Interest expense	0		0
Income (loss) before income taxes	-0.7		4.4
Noncontrolling interests’ net income (loss)	0		0
Depreciation and amortization	-2.7		-2.6
Capital expenditures	6.6		9.3
Total assets	286.4		279.3
Short-term borrowings	0		0
Goodwill	0		0
UGI International, Antargaz
Segment Reporting Information
Revenues	337.9		425.3
Cost of sales	209.3		282.5
Segment profit:
Operating income (loss)	38.4		43.2
Loss from equity investees	-1		0
Interest expense	-5.6		-6.4
Income (loss) before income taxes	31.8		36.8
Noncontrolling interests’ net income (loss)	0.1		0.1
Depreciation and amortization	-13.3		-15
Capital expenditures	12.1		9.8
Total assets	1,671.50		1,938.90
Short-term borrowings	0		0
Goodwill	575.9		654.3
UGI International, Flaga & Other
Segment Reporting Information
Revenues	224.6		293.3
Cost of sales	172.6		231.7
Segment profit:
Operating income (loss)	15.1		13.7
Loss from equity investees	0		0
Interest expense	-1		-1.3
Income (loss) before income taxes	14.1		12.4
Noncontrolling interests’ net income (loss)	0		0
Depreciation and amortization	-6.1		-6.6
Capital expenditures	6.4		4.6
Total assets	579		696.5
Short-term borrowings	9		14.7
Goodwill	87.4		99.5
Corporate & Other
Segment Reporting Information
Revenues	47	[4]	51.9	[4]
Cost of sales	257.7	[4]	24.2	[4]
Segment profit:
Operating income (loss)	-227.2	[4]	8.9	[4]
Loss from equity investees	0	[4]	0	[4]
Interest expense	-0.7	[4]	-0.6	[4]
Income (loss) before income taxes	-227.9	[4]	8.3	[4]
Noncontrolling interests’ net income (loss)	-100.8	[4]	0	[4]
Depreciation and amortization	-1.6	[4]	-1.5	[4]
Capital expenditures	1.7	[4]	2.4	[4]
Total assets	448.7	[4]	404.2	[4]
Short-term borrowings	0	[4]	0	[4]
Goodwill	$6.20	[4]	$7	[4]
[1]	Represents the elimination of intersegment transactions principally among Midstream & Marketing, Gas Utility and AmeriGas Propane.
[2]	The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane operating income:Three Months Ended December 31, 2014 2013Partnership Adjusted EBITDA $188.5 $230.2Depreciation and amortization (49.4) (52.3)Noncontrolling interests (i) 0.6 1.8Operating income $139.7 $179.7(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.
[4]	Corporate & Other results principally comprise (1) Electric Utility, (2) Enterprises’ heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses (“HVAC”), (3) net expenses of UGI’s captive general liability insurance company, and (4) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include net gains and (losses) on commodity derivative instruments not associated with current-period transactions totaling $(229.7) and $(7.2) during the three months ended December 31, 2014 and 2013, respectively. Corporate & Other assets principally comprise cash, short-term investments, the assets of Electric Utility and HVAC, and, in the three months ended December 31, 2013, an intercompany loan. The intercompany loan and associated interest is removed in the segment presentation.